These privacy rules do not apply in the case of DOT drug and alcohol testing requirements.  The following was recently re-released by the DOT – Office of Drug & Alcohol Policy & Compliance to confirm permission is not needed in these circumstances.

Medical Review Officers Contacting Employees’ Treating Physicians

We wish to clarify an issue brought recently to our attention regarding Medical Review Officers (MROs) contacting employees’ treating physicians.  For a number of years, we have emphasized that Health Insurance Portability and Accountability Act (HIPAA) rules do not apply to MROs carrying out their verification process duties under 49 CFR Part 40.  That position still holds: MROs do not need and must not attempt to obtain an employee’s permission in order to confer with prescribing physicians.

The  General Issue Update Question and Answer [dated 07/06] is the Department’s official and authorative position in this matter.  It states, in part:

MROs need no written authorizations from employees to verify drug test results, to discuss alternative medical explanations with prescribing physicians and issuing pharmacists, to report results to employers, to confer with Substance Abuse Professionals (SAPs) and evaluating physicians, or to report other medical information (see §40.327).

If an employee presents a medical explanation during the verification interview, we encourage the MRO to contact the treating physician if the MRO has suspicions or questions resulting from the interview.  We also encourage the MRO to contact the pharmacy to verify the legitimacy of the prescription.  Requiring a waiver or consent for this information is contrary to Part 40, and it would impose a requirement on an employee for a release that is also counter to Part 40 (see §40.355).

 Cindy Ingrao

Senior Policy Advisor

Office of Drug and Alcohol

  Policy and Compliance

U.S. Department of Transportation

– Laboratories need no written authorizations from employees to perform DOT drug and validity testing, or to report test results to Medical Review Officers (MROs).

– MROs need no written authorizations from employees to verify drug test results, to discuss alternative medical explanations with prescribing physicians and issuing pharmacists, to report results to employers, to confer with Substance Abuse Professionals (SAPs) and evaluating physicians, or to report other medical information (see §40.327).

– SAPs need no written authorizations from employees to conduct SAP evaluations, to confer with employers, to confer with MROs, to confer with appropriate education and treatment providers, or to provide SAP reports to employers.

– Consortia/Third Party Administrators need no written authorizations from employees to bill employers for service agent functions that they perform for employers or contract on behalf of employers.

– Evaluating physicians need no written authorizations from employees to report evaluation information and results to MROs or to employers, as appropriate.

– Employers and service agents need no written authorizations from employees to release information to requesting Federal, state, or local safety agencies with regulatory authority over them or employees.

All this and more in WinDOT, The Pipeline Safety Encyclopedia.

The following interpretation from 2007 addresses this question.

Interpretation 192.3  40
February 7, 2007

U.S. Department of Transportation
Pipeline and Hazardous Materials Safety Administration
400 Seventh Street, S.W.
Washington, D.C. 20590

FEB 16 2007

Mr. Rod Dyck

Pipeline Operations Group Chair
National Transportation Safety Board
490 L’Enfant Plaza, SW
Washington, DC 50594-0001

Re:  Gas pipeline incident in West Cote Blanche Bay, Louisiana

Dear Mr. Dyck:

This letter responds to your request for a determination by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the regulatory status of an 8-inch gas pipeline involved in an incident in West Cote Blanche Bay, Louisiana on October 12, 2006. PHMSA has determined that the pipeline segment involved in the incident is subject to the pipeline safety requirements in 49 C.F.R. § 192.612 based on the depth of water and because the pipeline’s location places it within an “inlet” of the Gulf of Mexico for purposes of 49 C.F.R. § 192.3.

The pipeline is an 8-inch gas gathering line operated by Chevron USA, which transports processed gas to gathering systems. The pipeline was apparently damaged when a barge traveling above the pipeline released a spud or stabilizing stake, which penetrated the ground bed and punctured the pipeline, causing an explosion. The line had approximately 24 to 48 inches of cover when the incident occurred. The water depth at the location is approximately 8 feet.

Section 60102(a)(2) of title 49, United States Code, authorizes PHMSA to prescribe standards for gas pipeline transportation. Gas pipeline transportation includes gathering, transmission and distribution of gas by pipeline, but only includes gathering through “regulated gathering lines.” The minimum safety requirements for gas pipeline facilities and the transportation of gas are set forth in 49 C.F.R. Part 192. Under § 192.1, these regulations do not apply to the onshore gathering of gas “through a pipeline that is not a regulated onshore gathering line (as determined in § 192.8)” or “within inlets of the Gulf of Mexico, except for the requirements in § 192.612.”

PHMSA defines “regulated onshore gathering line” as a gathering line with particular characteristics located in a Class 2, 3, or 4 area. While regulated onshore gathering lines must comply with the gas pipeline safety regulations under § 192.9, onshore gathering lines in a Class 1 area, such as West Cote Blanche Bay, are not subject to Part 192, except that all onshore gathering lines within the Gulf of Mexico and its inlets are subject to the requirements in § 192.612 for reducing the risks associated with vessels hitting underwater pipelines.

Section 192.612 requires each operator to “identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a hazard to navigation.” An operator must also “conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk.” If an operator discovers that a line has become exposed or poses a hazard to navigation, the operator must promptly notify the National Response Center, mark the location of the pipeline, and within 6 months bury the pipeline so that the top of the pipe is 36 inches below the natural bottom (18 inches for rock excavation).

PHMSA defines “the Gulf of Mexico and its inlets” to mean “waters from the mean high water mark of the coast of the Gulf of Mexico and its inlets open to the sea (excluding rivers, tidal marshes, lakes, and canals) seaward to include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water.” (§ 192.3) Based on its geography, and in accordance with this agency’s prior interpretations, we consider West Cote Blanche Bay an “inlet” of the Gulf of Mexico within the meaning of § 192.612. Accordingly, to the extent that the pipeline is located in waters less than 15 feet deep (including at the point of impact), the pipeline involved in the October 12, 2006 incident is subject to the inspection and reburial requirements in § 192.612. However, because the pipeline does not meet the definition of a regulated onshore gathering line, the pipeline is not subject to the other Part 192 requirements.

PHMSA intends to review these regulations, in particular the definition of “Gulf of Mexico and its inlets” in § 192.3, to determine if any changes to the text are necessary to improve clarity and promote more consistent application of the regulations for pipelines located in the Gulf area. In the meantime, PHMSA plans to work with the State of Louisiana and our other State partners in the Gulf area to ensure the pipelines subject to these regulations meet the specifications for burial depth. PHMSA is also developing additional guidance material for pipeline operators to aid them in complying with these important safety regulations.

If you have any further questions pertaining to this matter, please contact Mr. Joy Kadnar of my staff at (202) 366-4595.

Sincerely,

Jeffrey D. Wiese
Acting Associate Administrator for Pipeline Safety

cc:     Tom Fortner
Director, State Programs, PHMSA

James H. Welsh
Commissioner of Conservation
Louisiana Department of Natural Resources

Read more about it in WinDOT, The Pipeline Safety Encyclopedia.

Parts 192 and 195 include specific requirements for welding, including the need for qualified welding procedures.  Operators must have procedures that are specific to the system being built or repaired.

The following interpretation from 1993 addresses a question on fillet weld procedures.

Interpretation 192.225  3
September 7, 1993

INFORMATION: Fillet Welding Procedures

Cesar De Leon
Director, Regulatory Programs for OPS

Richard Sanders, DTI-60

This responds to your speed memo of July 30, 1993, asking whether §§ 192.225 and 195.214 permit operators to use the same welding procedure for different sizes of fillet welds.
These standards require welding to be performed in accordance with procedures that have been qualified by destructive testing to meet certain requirements. Because welding procedures are qualified on the basis of a variety of welding variables, including size of weld, a qualified procedure may be used only for welds characterized by those variables. A procedure must be revised and requalified to account for any change in variables.

So a procedure that has been qualified for a particular size of fillet weld could not be used on sizes for which the procedure has not been qualified. However, a single procedure could be qualified for a range of weld sizes, enabling an operator to use the same procedure for different sizes of fillet welds.
The size of a fillet weld corresponds generally to the thickness of the material that is being welded to pipe. Thus, we cannot envision pipeline fillet welds that are 10 or 12 inches in size, as mentioned in your memo. If these dimensions referred to the length of fillet welds, since weld length is not a welding procedure variable, changes in weld length would not affect qualification of the welding procedure.

******************************************************************

SPEED MEMO

Subject: Fillet welding procedures.

Date of Initial Message
July 30, 1993

TO: Cesar DeLeon, DPS-10
Pipeline Safety Specialist DTI-60

Part 192.225 Welding-General
Part 195.214 Welding-General

Inquiry
I recently received a telephone inquiry from one of the Region engineers concerning code requirements for the number of welding procedures which would be required for making fillet welds on a natural gas system.

A pipeline operator being subject to a periodic inspection was found to have one fillet welding procedure for use when welding on his pipeline system. This one procedure was used for repair sleeve welding, welding of control line fittings, and attachment of various size weld-o-lets to the pipeline. The inspector raised the question as to whether the code required a different welding procedure for the various size of fillet welds the operator was making: The fillet welds on the repair sleeve might range in size to 10 or 12 inch, the weld-o-lets might only be 2 to 4 inches, while the control line welds may be 1/2 inch. So the question was would one fillet weld procedure suffice for these different size welds and would any procedure have to reflect other essential variables such as pipe material (grade), various wall thicknesses, or in fact the same consideration given to the essential variables given to butt welding procedures?

TSI Staff response
Part 192 or even Part 195 does not specifically address this issue. A review of API 1104, 17th Edition , 1988 was made on this question. The scope (1.1) of this standard states that “This standard covers the gas and arc welding of butt, fillet and socket welds …”. In Section 2 on qualification of welding procedures 2.3 which list the various information that should be included in a welding procedure, fillet welds are only specifically addressed at 2.3.2.4, under joint design. I assume that if fillet welds are not specifically addressed then the requirements in this standard apply both to butt welds and to fillet welds. Further, that Section 2.4, Essential Variables, would apply to fillet welds and require separate fillet welding procedures when welding is to be performed when there is a change in those variables.

Since API 1104 is very clear on butt welding procedures and qualifications, but not so clear on fillet welding, I reviewed the requirements found in API 1107, “Recommended Pipe Line Maintenance Welding Practices”, as this features a considerable amount of fillet welding information. In API 1107 the same basic consideration of certain essential variables is addressed and requires a sufficient number of fillet welding procedures if the operator is to perform welding with those variable conditions present.

I also reviewed all of the past welding interpretations and opinions for Part 192, 193, and 195. None addressed this question.

Response
I offered to the regional inspector that I also concurred with his interpretation that more then one fillet welding procedure would be required based upon the operators circumstances.
Since our response to the inquiry took a certain amount of time and research, we would like to place the facts in this action in our newly created DTI-60 Staff Opinion binder for future reference and use by all of out TSI staff to eliminate repeating the same research effort and to insure that any question on this subject would result in the same answer.

If you concur with our staff opinion on this subject, please indicate your agreement with your signature and date on this memo.

All this and more including complete docket history for all regulations in WinDOT, The Pipeline Safety Encyclopedia.

In the original Part 195 issued in 1969 section 195.402 contained this paragraph:

(c)  Whenever a carrier discovers any condition that could adversely affect the safe operation of its pipeline system, it shall correct it within a reasonable time.  However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the carrier may not operate the affected part of the system until it has corrected the unsafe condition.

This was subsequently moved to §195.401  General requirements, and later the term “carrier” was changed to “operator”.  This requirement remains today with the only modification being “shall” is now “must”.  This regulation has guided operators for over 40 years identify threats to their facilities and correct them.

Yes, Integrity Management may be relatively new words in the regulations, but their meaning has always been there.  The following interpretation from 1984 explores such a threat.

Interpretation  December 13, 1984

Mr. Jerry C. Huffer

7891 Queen B Road

Plymouth, Indiana 40583

Dear Mr. Huffer:

This responds to your letter of November 25, 1984, to Secretary Dole regarding the proposed construction of a landfill near an existing liquefied gas pipeline operated by the Dome Pipeline Corporation in Plymouth, Indiana. You expressed concern that excavations planned close to the pipeline will be potentially dangerous, and ask that the Department of Transportation require that “safety zones” be provided between the pipeline and excavations.

In the Department, the Materials Transportation Bureau issues and enforces th4 Department’s safety regulations governing the transportation of gas or hazardous liquids by pipeline. The Dome pipeline you are concerned about is subject to the safety standards contained in Part 195 of title 49 of the Code of Federal Regulations, a copy of which is enclosed.

Under these standards, operators are required to inspect their rights-of-way about every two weeks (§195.412). Also, they are required to correct conditions they know about that could adversely affect safe operations (§195.401(b). Excavating close enough to a pipeline to disturb either the pipeline or, its foundation would be such a condition. The usual response in these situations is for the operator to temporarily mark the pipeline’s location before excavation begins to avoid the potential for pipeline damage. Depending on the nature of the planned excavation, more extensive protective measures might be necessary, involving, for example, monitoring, shoring, or, in extreme cases, relocation of the pipeline.

Under the standards, the choice of corrective action is left to the operator. The creation of a “safety zone”, which we presume would involve the operator’s purchasing additional land interests near its pipeline, might be one of several courses of action. It is one that normally is not chosen, however, because either the land interests are not for sale or there are less expensive but effective remedies available.

Because of your concern about the Dome pipeline in Plymouth, I am forwarding a copy of your letter and our response to the Bureau’s Central Region Office in Kansas City, Missouri. That office is in charge of enforcing the Part 195 standards against operators In Indiana, and can contact Dome to be sure that proper protective measures are taken if the proposed landfill is constructed.

Sincerely,

Original signed by

Richard L. Beam

Associate Director for

Pipeline Safety Regulation

Materials Transportation Bureau

Jerry C. Huffer

7891 Queen B Road

Plymouth, Indiana 46563

November 25, 1984

Mrs. Elizabeth Dole

Department of Transportation

400 7th Street S.W.

Washington D.C. 20590

Dear Mrs. Dole:

I am writing concerning a proposed landfill to be located just west of Plymouth, Indiana in Marshall County. The applicant for this landfill is Mr. Jerry Hinds of Al Disposal Company of Plymouth, Indiana.

Our organization represents between one and two thousand Marshall County residents and landowners who are opposed to this landfill. Our concerns are based on the fact that an international pipeline easement crosses the proposed site. The landfill plans call for extensive excavating very close to the pipeline easement. It is the concern of many in the area that this excavating, combined with the fact that this pipeline is a high pressure type liquid natural gas line, creates the potential for an accident of devastating proportions.

This pipeline runs along and under a major U.S. highway which borders the landfill site on the south. To even further add to the danger, high voltage electric lines are directly overhead of the pipeline.

With the United States attempting to improve relations with Canada and the pipeline being Canadian owned, I am sure you will agree that it would not be beneficial to find the Department of Transportation not taking every precaution to insure the integrity of this pipeline.

I have been in touch with Mr. Leeroy Crabtree; Area Foremen of the Dome Pipeline Corporation of Coshen, Indiana regarding this matter but to date no action has been taken.

May I call upon you to investigate this matter and exercise your authority to insure that additional safety zones be required between the pipeline and the excavations for both the landfill and, the planned drainage ditches.

Sincerely yours,

Jerry C. Huffer

Secretary

Citizens Against Landfills, Inc

All this and more including past history of the regulations and interpretations in WinDOT, The Pipeline Safety Encyclopedia.

The pipeline industry was first eligible to lower its testing rate in 1997, and in fact RSPA did lower the rate starting that year.  Each year since then the pipeline industry has maintained a less than 1 percent positive testing rate and subsequently its 25% covered employee rate.

A question that has been asked is whether supervisors or managers, who direct the work of others but do not themselves perform the work, should be in the drug testing pool.  The following interpretation answers that question.

Interpretation 199.3  9
May 18, 1990

Mr. Thomas W. Worrell
Manager, Industrial Relations
South Jersey Gas Company
Number One South Jersey Plaza
Route 54
Folsom, New Jersey  08037

Dear Mr. Worrell:

I am responding to your letter of April 16, 1990, to Cesar De Leon asking whether certain supervisory and management personnel must be included in your company’s drug testing program under 49 CFR Part 199 in view of the activities those personnel perform under your company’s emergency response manual.

A person is subject to drug testing under Part 199 when that person performs on a pipeline or liquefied natural gas facility a function that is regulated by 49 CFR Part 192, 193, or 195.  (See the Part 199 definition of “employee.”)  Persons that serve in a supervisory or management capacity are not exempt from testing under Part 199.  However, such persons are subject to testing only if they actually perform a regulated operation, maintenance, or emergency-response function.  Merely directing the work of others who perform these regulated functions is not an activity that qualifies a person for drug testing under Part 199.

In Part 192, emergency plans are covered by § 192.615.  This regulation requires operators to prepare written procedures covering various functions involved in responding to a gas pipeline emergency.  Any function an operator describes in its § 192.615 procedures, including functions that exceed the minimum requirements of § 192.615, is a regulated function because compliance with the procedures is mandatory.  Thus, performance of any function described in an operator’s written procedures that are intended to implement § 192.615 would make a supervisor or manager who performs the function subject to drug testing under Part 199.

We trust this adequately responds to your inquiry.

Sincerely,

George W. Tenley, Jr.
Director
Office of Pipeline Safety

All this and more including the complete history of drug and alcohol testing in WinDOT, The Pipeline Safety Encyclopedia.

Each rulemaking also has a color code. A rule may be green, yellow, red or black. A “green” designation means the rule is on schedule. “Yellow” means the rule is not likely to meet the schedule. “Red” means the rule is behind schedule; if red, an explanation will be provided for the delay. Finally, “black” means the Department does not yet have a schedule for publication.

86. Pipeline Safety: Enforcement of State Excavation Damage Laws

91. Pipeline Safety: Safety of On-Shore Liquid Hazardous Pipelines

93. Pipeline Safety: Excess Flow Valves In Applications Other Than Single-Family Residences in Gas Distribution Systems

94. Pipeline Safety: Gas Transmission

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However, pipeline safety was not ignored at these facilities.  Maintenance manuals and programs for these installations incorporated many of the requirements from Part 192 for leak surveys and corrosion control.

Over the past two decades the military has had a program to privatize utility systems on their domestic bases. The question arises now about systems that are on federal property but operated by non-federal entities.  Are these operators and the respective pipeline systems subject to the DOT and state pipeline safety regulations?

The following interpretation from earlier this year answers that question.

Interpretation
Jul 12, 2011

Mr. Mark McCarver

Director, Pipeline Safety

Mississippi Public Service Commission

501 N West Street, Suite 201-A

Jackson, MS  39201

Dear Mr. McCarver:

In a letter to the Pipeline and Hazardous Materials Safety Administration (PHMSA) dated  March 31, 2011, you asked whether two gas distribution pipeline systems located on Federal properties but operated by non-Federal entities would be subject to the requirements of 49 CFR Parts 191 and 192 and, if so, be regulated by the Mississippi Public Service Commission (MSPSC).  You stated that both systems had formerly been operated by Federal personnel and were considered for many years to be exempt from the Federal pipeline safety regulations.  You stated, however, that both systems have been recently privatized and that each gas system is now operated by an outside contractor.  You also mentioned that both systems also transport gas for resale as defined in § 191.3.

You described the facilities as follows:  The first gas system is located on the grounds of the National Aeronautics and Space Administration¿s (NASA¿s) Stennis Space Center in Hancock County, Mississippi.  The system consists of 30.788 miles of 8-inch, 6-inch, 4-inch and 2-inch steel and polyethylene pipelines.  This pipeline is operating at 50-55 pounds per square inch gauge (psig).  The maximum allowable operating pressure (MAOP) is 150 psig.  There are no regulator stations on site and the pressure is regulated by the supplier.  There are several cafeterias (buildings) that are owned by NASA and operated by contract personnel.  There are several private companies that lease buildings from NASA.  This system is now operated by an outside contractor.

The second gas system is located on the grounds of the Kessler Air Force Base in Biloxi, Mississippi.  This system consists of approximately 12 miles of 8-inch steel pipeline which carries gas from a Gulf South Pipeline transmission line in Gulfport, Mississippi to the Base.  You stated that this line is reported to have a MAOP of 150 psig with a normal operating range of 80 to 100 psig.  There are several regulator stations along this line serving military housing with some of the services located outside the perimeter of the Base.  This system is now operated by an outside contractor.

The pipeline safety regulations are applicable to pipeline facility operators.  The gas pipeline safety regulations at Parts 191 and 192 define an operator to mean a person who engages in the transportation of gas.

The definition of a person in these Federal pipeline safety regulations is:

Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof.

Based on these definitions and the legislative history of the pipeline safety laws, while a pipeline system is operated by a Federal entity, it is exempt from compliance with the pipeline safety regulations.[1]  However, if a system is privatized and becomes operated by a non-Federal entity, the operator must comply with the pipeline safety regulations.  Therefore, the answer to the first part of your question is yes, both of these gas pipeline systems are subject to the Part 191 and Part 192 requirements.  As to the second part of your question, because the MSPSC has an annual certification at 49 U.S.C. § 60105, both of these gas distribution systems, as intrastate gas pipeline operations, are subject to the authority of the MSPSC as the primary regulator of these pipelines.

I hope that this information is helpful to you.  If I can be of further assistance, please contact me at (202) 366-4046.

Sincerely,

John A. Gale

Director

Office of Standards and Rulemaking

[1]  PHMSA strongly recommends that even exempt facilities follow the pipeline safety requirements on a voluntary basis to ensure the safety of facility personnel.

All this and more including interpretations for all code parts in WinDOT, The Pipeline Safety Encyclopedia.

The following interpretation from 1993 and Memorandum of Understanding assist in answering this question.

Interpretation 194.1  3
March 1, 1993

Ms. Stephanie R. Meadows
American Petroleum Institute
1220 L Street, N.W.
Washington, D.C.   20005

Dear Ms. Meadows:

I am writing in response to your telephone discussions with Stacey Gerard concerning the application of the recently published interim final rule on response plans for onshore oil pipelines (58 FR 244; January 5, 1993; adopting Part 194, Title 49, Code of Federal Regulations).  In those conversations, you asked for an opinion of whether the new regulations, adopted to implement provisions of Title IV of the Oil Pollution Act of 1990 (OPA), apply to specific categories of pipelines.

Following are the pipeline categories in your inquiry and our response:

Pipelines used to carry extracted oil and gas from stripper wells to tank batteries.

Under Executive Order 12777, and delegations of authorities under that order from the Secretary of Transportation to the Administrator of the Research and Special Programs Administration (RSPA) (58 FR 6193; January 27, 1993), the requirements for spill response planning by operators of on-shore pipeline facilities (including the submission of plans to RSPA) only apply to transportation-related facilities.  We have reviewed the application of Part 194 to pipeline used to carry extracted oil and gas from stripper wells to tank batteries, and have determined that Part 194 does not apply to those facilities because they are not transportation-related.  This opinion is consistent with the terms of a Memorandum of Understanding between the Department of Transportation and the Environmental Protection Agency (EPA) (36 FR 24080; December 18, 1971), which was executed to assure effective implementation of the Federal Water Pollution Act (which the OPA amends).  Under the terms of that Memorandum, we consider the lines at issue to be “non-transportation-related” facilities and not subject to the Department’s regulations.  You should note, however, that these lines may be subject to OPA requirements the EPA may adopt.

Natural gas gathering lines upstream from a processing unit that carry minimal amounts of condensate along with the gas.

Most gas gathering lines are connected to processing units where heavier hydrocarbons are removed from the gas and sold separately.  The small amount of condensates in such lines could not reasonably be expected to cause substantial harm to the environment.  Therefore, oil spill response plans covering these gas gathering lines would not be required to be filed by February 18, 1993.

Natural gas transmission lines downstream from a processing unit that may form a minimal amount of condensate in the transmission of the gas.

Downstream of a processing unit, the gas is in a condition fit for use by gas customers.  Beyond the processing unit the gas generally is transported in a transmission line for delivery to a distribution center or storage facility.  Natural gas, depending on the volume of gas transported and temperature differentials, will form small amounts of light hydrocarbons or condensates while being transported in the transmission pipelines because of the recurring compression and subsequent pressure drops.  Condensates so formed are not considered to cause substantial harm to the environment and oil spill response plans would not be required to be filed by February 18, 1993.

Hydrant distribution systems associated with airport fuel facilities

Part 194 does not apply to a hydrant distribution system which distributes fuel from a tank battery at an airport facility because the hydrant distribution system is a non-transportation-related facility as the term is used in the Memorandum of Understanding between the Department of Transportation and the EPA (36 FR 24080; December 18, 1971).  While Part 194 does not apply to the hydrant distribution system, it may be subject to OPA requirements the EPA may adopt.

I trust this information is responsive to your request.  If you have further questions about this or other matters, please let me know.

Sincerely,

George W. Tenley, Jr.
Associate Administrator for
Pipeline Safety

Memorandum of Understanding Between the Environmental Protection Agency and the Department of Transportation

1971 MOU between DOT and EPA on Transportation-Related Facilities
NOTICE: Department of Transportation, Coast Guard
Memorandum of Understanding Between the Environmental Protection Agency and the Department of Transportation

This memorandum establishes polices and guidelines relating to the definition of transportation and onshore and offshore facilities and the responsibilities of the Environmental Protection Agency and the U.S. Coast Guard with respect to the prevention of oil discharges from vessels and onshore and offshore facilities.

SECTION I – GENERAL

1. Section 11(j)(1)(C) of the Federal Water Pollution Control Act, as amended, authorizes the President to issue regulations consistent with maritime safety and with marine navigation laws establishing procedures, methods, and requirements for equipment to prevent discharges of oil from vessels and onshore and offshore facilities.
2. This authority was delegated by the President in Executive Order 11548. Section 1 of that Executive Order delegates responsibility and authority to the Secretary of the Interior to carry out the provisions of subsection (j)(1)(C) of section 11 of the Act after consultation with the Secretary of Transportation relating to procedures, methods, and requirements for equipment to prevent discharges of oil from nontransportation-related onshore and offshore facilities. The authority delegated to the Secretary of the Interior was subsequently vested in the Administrator of the Environmental Protection Agency in Reorganization Plan No. 3 of 1970 and section 9 of Executive Order 11548.

3. Section 2 of Executive Order 11548 delegates responsibility and authority to the Secretary of Transportation in consultation with the Secretary of the Interior, to carry out the provisions of subsection (j)(1)(C) of section 11 of the Act relating to procedures, methods, and requirements for equipment to prevent discharges of oil from vessels and transportation-related onshore and offshore facilities. The Secretary of Transportation in turn redelegated this authority to the Commandant, U.S. Coast Guard.

4. Although Executive Order 11548 divided responsibility and authority into transportation-related and nontransportation-related facilities, no indication of the extent of transportation relation is given. In the broadest sense every facility is transportation related. Any activity that can possibly discharge oil must transport materials to some extent and have materials transported either to, from, or by the facility.
5. In distinguishing between transportation-related and nontransportation-related facilities, a systems approach was utilized. It is recognized that the life-cycle of oil is characterized by various operations conducted at many different types of facilities. Most facilities necessarily engage in more than one type of operation. These operations include drilling, producing, refining, storing, transferring, transporting, using, and disposing. To the extent possible and considering agency resource capabilities and expertise, it is considered most practical to assign one agency the responsibility for regulating a complete operation at any one facility. The Department of Transportation will generally be responsible for regulating the transferring of oil to or from a vessel at any facility including terminal facilities; the transporting of oil via highway, pipeline, railroad, or vessel; and certain storing operations. The Environmental Protection Agency will generally be responsible for regulating drilling, producing, refining, storing, disposing, and certain transferring operations at various types of facilities.

6. While the following definitions are intended to be as specific and inclusive as possible, it is recognized that certain problems concerning these definitions will arise from time to time requiring the cooperation and agreement of the Department of Transportation and the Environmental Protection Agency for resolution.

SECTION II — DEFINITIONS
The Environmental Protection Agency and the Department of Transportation agree that for the purposes of Executive Order 11548 the term –

(1) Non-transportation-related onshore and offshore facilities means:

(A) Fixed onshore and offshore oil well drilling facades including all equipment and appurtenance related thereto used in drilling operations for exploratory or development wells, but excluding any terminal facility, unit or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.
(B) Mobile onshore and offshore oil well drilling platforms, barges, trucks, or other mobile facilities including all equipment and appurtenances related thereto when such mobile facilities are fixed in position for the purpose of drilling operations for exploratory or development wells, but excluding any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.

(C) Fixed onshore and offshore oil production structures, platforms, derricks, and rigs including all equipment and appurtenances related thereto, as well as completed wells and wellhead equipment, piping from wellheads to oil separators, oil separators, and storage facilities used in the production of oil but excluding any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.
(D) Mobile onshore and offshore oil production structures, platforms, derricks, and rigs including all equipment and appurtenances related thereto, as well as completed wells and wellhead equipment, piping from wellheads to oil separators, oil separators, and storage facilities used in the production of oil when such mobile facilities are fixed in position for the purpose of oil production operations, but excluding any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.

(E) Oil refining facilities including all equipment and appurtenances related thereto, as well as inplant processing units, storage units, piping, drainage systems, and waste treatment units used in the refining of oil, but excluding any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.
(F) Oil storage facilities including all equipment and appurtenances related thereto, as well as fixed bulk plant storage, terminal oil storage facilities, consumer storage pumps, and drainage systems used in the storage of oil, but excluding in-line or breakout storage tanks needed for the continuous operation of a pipeline system and any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.

(G) Industrial, commercial, agricultural, or public facilities which use and store oil, but excluding any terminal facility, unit, or process integrally associated with the handling or transferring of oil in bulk to or from a vessel.
(H) Waste treatment facilities including in-plant pipelines, effluent discharge lines, and storage tanks, but excluding waste treatment facilities located on vessels and terminal storage tanks and appurtenance for the reception of oily ballast water or tank washings from vessels and associated systems used for off-loading vessels.

(I) Loading racks, transfer hoses, loading arms, and other equipment which are appurtenant to a non-transportation-related facility and which are used to transfer oil in bulk to or from high way vehicles or railroad cars.
(J) Highway vehicles and railroad cars which are used for the transport of oil exclusively within the confines of a non-transportation-related facility and which are not intended to transport oil in interstate or intrastate commerce.
(K) Pipeline systems which are used for the transport of oil exclusively within the confines of a non-transportation-related facility or terminal facility and which are not intended to transport oil in interstate or intrastate commerce, but excluding pipeline systems used to transfer oil in bulk to or from a vessel.

(2) Transportation-related onshore and offshore facilities means –

(A) Onshore and offshore terminal facilities including transfer hoses, loading arms, and other equipment and appurtenances used for the purpose of handling or transferring of oil in bulk to or from a vessel as well as storage tanks and appurtenances for the reception of oil ballast water or tank washings from vessels, but excluding terminal waste treatment facilities, and terminal oil storage facilities.
(B) Transfer hoses, loading arms, and other equipment appurtenant to a non-transportation-related facility which is used to transfer oil in bulk to or from a vessel.

(C) Interstate and intrastate onshore and offshore pipeline systems including pumps and appurtenances related thereto, as well as in-line or breakout storage tanks needed for the continuous operation of a pipeline system, and pipelines from onshore and offshore oil production facilities, but excluding onshore and offshore piping from wellheads to oil separators and pipelines which are used for the transport of oil exclusively within the confines of a non-transportation-related facility or terminal facility and which are not intended to transport oil in interstate or intrastate commerce or to transfer oil in bulk to or from a vessel.

(D) Highway vehicles and railroad cars which are used for the transport of oil in interstate and intrastate commerce and the equipment and appurtenances related thereto, and equipment used for the fueling of locomotive units, as well as the rights-of-way on which they operate. Excluded are highway vehicles and railroad cars and motive power used exclusively within the confines of a non-transportation-related facility or terminal facility and which are not intended for use in interstate or intrastate commerce.

SECTION III — COORDINATION AND ENFORCEMENT
The above definitions have been developed to facilitate the development and enforcement of regulations for prevention of oil discharge and to correspond as much as possible to the existing regulations of the Department of Transportation and the Environmental Protection Agency. It is recognized, however, that in some situations, the Department of Transportation may have expertise that could be helpful to the Environmental Protection Agency in the development and enforcement of these regulations and vice

versa. Such a situation might arise in connection with the regulation of the non-transportation-related facilities included within definitions 1(J) and (K) in Section II above.
It is agreed that in such situations the Department of Transportation and the Environmental Protection Agency will provide assistance to and coordinate with each other in the development and enforcement of the regulations to the extent that existing resources permit.

Done this 24th day of November 1981 at the City of Washington.

For the Department of Transportation, John A. Volpe.
For the Environmental Protection Agency, William D. Ruckelshaus
(FR Doc.71-18542; Filed 12/17/71; 8:48 a.m.)

FEDERAL REGISTER, Vol. 36, No. 244 (pp 24081 & 24082) Saturday, December 18, 1971

All this and more including the historical recreation of the regulations in WinDOT, The Pipeline Safety Encyclopedia.

The following interpretation from 1971 asks a series of questions about service lines, inspection and testing.

Interpretation 192.363  2
March 19, 1971

Mr. Ronald K. Espe
Manager of Engineering
Mineapolis Gas Company
Minneapolis, Minnesota 55402

This is in reply to your letter concerning your request for interpretations of several Sections of 49 CFR, Part 192.

Your questions and our replies follow:

Question:  Paragraph 192.63: Our practice is to salvage large size pipe and fittings when they have been exposed by other construction (sewer, water, bridge, grade change, etc.) and relocation will be necessary.  Pipe is cleaned, inspected and re-coated internally and externally.  Fittings are cleaned, inspected and ends are re-finished.  We then normally return the pipe and fittings to the same type of service that it originally served.  Is it permissable to salvage pipe and fittings when the original markings or purchase specifications are not available?

Answer:  Section 192.63 applies only prospectively, that is, to items manufactured after the effective date of the regulations, November 12, 1970.  It therefore, does not apply to the use of salvaged pipe or fittings meeting other safety standards.  If the pipe is qualified for the intended service under section 192.107 (yield strength (s) for steel pipe) and Section 192.109 (nominal wall thickness (t) for steel pipe), it may be used.  Salvaged components may be reused only to the degree that their specifications can be verified to meet the requirements of Subpart D, Design of Pipeline Components.

Question:  Paragraph 192.355: We are concerned about the concept of making the utility responsible for any action or installation by the customer.  We objected to this in the initial call for comments and feel it deserves additional consideration.  Mrs. Goldman stated her desire to make the utility responsible for everything, including the appliances, but you added that the present law is only intended to include the meter outlet.  It is impossible for any gas distribution company to monitor all the equipment and appliances a customer might install.  When we are aware of any questionable installations we will notify the local plumbing inspector and the customer.  The responsibility in this area belongs in the municipal plumbing and heating ordinances.

Answer:  49 CFR, Section 192.3 of the Minimum Federal Safety Standards defines a service line as a distribution line that transports gas to a customer meter set assembly from a common source of supply.  Section 192.355 imposes additional requirements for the meter itself.  We further contend, as Mrs. Goldman stated, that the burden is on the operator to ascertain the safe condition of the customer’s service lines to which gas is delivered.

Question:  Paragraph 192.363: The question of what is a “specialized tool” was brought up in the Kansas City meeting and we request a waiver on this section pending further investigation.  To our knowledge there are no tamper-proof cocks made in larger than 2” size.  Our original comments on this section asked that this requirement apply only to residential services.  Mrs. Goldman stated the reasoning behind the rule was to prevent acts of sabotage or destruction. On 2” and larger services it would be faster to use a hacksaw, or pipe cutter, or even a sledge hammer than to attempt to dismantle a plug valve and remove the core.  Our company has no history of trouble caused by the willful removal of a valve core on a 2” or larger commercial or industrial service.

Answer:  Section 192.363 (c) was taken directly from the ANSI B31.8 Code (1968 edition).  We are aware that tamper-proof valves are not made in larger than two inch size.  A locking device or placement of the valve within a locked enclosure would in our interpretation, fully meet the requirements of this section.  After considering this interpretation, if you still wish to request a waiver you may do so by formally submitting your request with appropriate justification.

Question:  Paragraph 192.513: Why have the test requirements for plastic services been made more extreme than the B31.8 Code requested?  In Kansas City you stated that the test requirements were the same as they had been under the B31.8 Code.  This is not so. The B31.8 Code (paragraph 849.152 (b)) required that plastic service lines operating between 40 psi and 100 psi to be tested to the maximum operating pressure or 100 psi whichever is the lesser.  We have tested thousands and thousands of plastic services at 100 psi with excellent results.  Increasing the test pressure to 150% of operating pressure would mean that the present standard air compressors in general use would not be adequate.  We request a waiver on this section pending further study.

Answer:  The ANSI B31.8 Code required a test pressure of 1.5x the MOP for plastic pipeline and mains (842.52(b)) or a minimum of 50 psi.  The B31.8 Code also permited a test pressure for plastic service lines of only the proposed operating pressure or 100 psi whichever is less for service lines operating in excess of 40 psi (849.152(b)). The Office of Pipeline Safety did not feel we would be justified from a safety point of view to permit a lesser test on plastic service lines compared to other plastic pipelines particularly since the construction requirements for plastic were not near as extensive as for steel (welding specifications, qualifications of welder, material specification, length of reference etc.)

After considering this interpretation, if you still wish to request a waiver you may do so by formally submitting your request with appropriate justification.

Question:  Paragraph 192.619: When this section is considered in conjunction with paragraph 192.511 we get a very unusual testing chart for steel services:

Operating pressure  0 psi to 1 psi = 150% test
Operating pressure  1 psi to 34 psi = 50 psi test
Operating pressure  34 psi to 40 psi = 150% test
Operating pressure  40 psi to 60 psi = 90 psi test
Operating pressure  60 psi to 20% SMYS = 150% test

It seems this has been made particularly cumbersome without any safety advantages.  In our discussion #4 we pointed out our fine safety record using 100 psi testing for all services operating at 100 psi or less.  We urge that this same criteria be adapted and that we be granted a waiver on these sections as presently written.
Answer:  the spot amendment to §192.619(a)(2)(ii) in part corrected this problem.  We are also considering some clarifying changes to the testing and MAOP requirements that will go through the rulemaking process.

The 50 psi test level and the 90 psi test level as specified in the existing regulation were so specified to ease the burden of the operator in the 100 psi or less operating range and still provide an adequate safety level. It was our opinion that this would take care of most of the operators’ testing problems.  For facilities operating over 100 psi it is our opinion that the test level should be the specified amount over the desired MOP in order to provide an adequate and uniform level of safety.

After considering this interpretation, if you still wish to request a waiver you may do so by formally submitting your request with appropriate justification.

Question:  Paragraph 192.725: Do you consider this section to be applicable when a service is temporarily cut out of the way for other construction (sewer, water, etc)?  It has been our company’s feeling that it is better and safer to remove the conflicting section of gas service and replace it after the other installation is completed and the backfilling is nearly completed.  The idea has been to prevent possible unknown damage to the gas system.  It now appears that your new regulation will reward the company that allows other construction to work around live gas facilities.  If this section is intended to apply only to lines taken out of service for more than one day or lines that have be damaged we would have no objection.  We also see no value in maintaining continuous service through a by-pass as a safety factor.  The same fittings and material will be used for the re-connection regardless of continuous service or not.  We ask that this section be re-evaluated also.

Answer:  Section 192.725 imposes the same requirements as those in the ANSI B31.8 code (1968 Edition), paragraph 853.4 and was also part of the interim minimum Federal standards, and we have no reason to believe it is not a valid safety requirement.  If you have such evidence and wish to submit it to this office, we will consider the possibility of further rulemaking action to amend this section.

If we can be of further assistance, do not hesitate to call on us.

Sincerely,
Joseph C. Caldwell
Director, Acting
Office of Pipeline Safety

************************************************************************
Minneapolis Gas Company
Minneapolis, Minnesota 55402

November 3, 1970

Mr. Frank E. Fulton
Technical Division
Office of Pipeline Safety
Department of Transportation
Washington, D.C. 20590

Dear Mr. Fulton

At the Regional Orientation Meeting in Kansas City, Missouri, on October 23, 1970, I asked a number of questions that you felt should be presented by letter. In private conversation after the formal program you indicated that reasonable requests and valid proposals would be carefully evaluated and there was a definite possibility of getting temporary waivers on certain specific parts of the new regulation.

I know that your office has considered the response of the industry in formulating the present regulation. However, there are a few points that deserve additional evaluation and a few points that have been revised since the initial proposals were released for comments. Would you please respond to the following questions and ideas?

1.  Paragraph 192.63: Our practice is to salvage large size pipe and fittings when they have been exposed by other construction (sewer, water, bridge, grade change, etc.) and relocation will be necessary. Pipe is cleaned, inspected and re-coated internally and externally. Fittings are cleaned, inspected and ends are re-finished. We then normally return the pipe and fittings to the same type of service that it originally served. Is it permissible to salvage pipe and fittings when the original markings or purchase specifications are not available?

2.  Paragraph 192.355: We are concerned about the concept of making the utility responsible for any action or installation by the customer. We objected to this in the initial call for comments and feel it deserves additional consideration. Mrs. Goldman stated her desire to make the utility responsible for everything, including the appliances, but you added that the present law is only intended to include the meter outlet. It is impossible for any gas distribution company to monitor all the equipment and appliances a customer might install. When we are aware of any questionable installations we will notify the local plumbing inspector and the customer. The responsibility in this area belongs in the municipal plumbing and heating ordinances.

3.  Paragraph 192.36: The question of what is a “specialized tool” was brought up in the Kansas City meeting and we request a waiver on this section pending further investigation. To our knowledge there are no tamperproof cooks made in larger than 2″ size. Our original comments on this section asked that this requirement apply only to residential services. Mrs. Goldman stated the reasoning behind the rule was to prevent acts of sabotage or destruction. On 2″ and larger services it would be faster to use a hacksaw, or pipe cutter, or even a sledge hammer than to attempt to dismantle a plug valve and remove the core. Our company has no history of trouble caused by the willful removal of a valve core on a 2″ or larger commercial or industrial service.

4.  Paragraph 192.513: Why have the test requirements for plastic services been made more extreme than the B31.8 Code requested? In Kansas City you stated that the test requirements were the same as they had been under the B31.8 Code. This is not so. The B31.8 Code (Paragraph 849.152 (b) ) required that plastic service lines operating between 40 psi and 100 psi be tested to the maximum operating pressure or 100 psi whichever is the lesser. We have tested thousands and thousands of plastic services at 100 psi with excellent results. Increasing the test pressure to 150% of operating pressure would mean that the present standard air compressors in general use would not be adequate. We request a waiver on this section pending further study.

5.  Paragraph 192.619: When this section is considered in conjunction with Paragraph 192.511 we get a very unusual testing chart for steel services:

Operating Pressure    0 psi to 1 psi = 150% test
Operating Pressure    1 psi to 34 psi = 50 psi test
Operating Pressure    34 psi to 40 psi = 150% test
Operating Pressure    40 psi to 60 psi = 90 psi test
Operating Pressure    60 psi to 20% SMYS = 150% test
It seems this has been made particularly cumbersome without any safety advantages. In our discussion #4 we pointed out our fine safety record using 100 psi testing for all services operating at 100 psi or less. We urge that this same criteria be adapted and that we be granted a waiver on these sections as presently written.

6.  Paragraph 192.725: Do you consider this section to be applicable when a service is temporarily cut out of the way for other construction (sewer, water, etc.)? It has been our company’s feeling that it is better and safer to remove the conflicting section of gas service and replace it after the other installation is completed and the backfilling is nearly completed. The idea has been to prevent possible unknown damage to the gas system. It now appears that your new regulation will reward the company that allows other construction to work around live gas facilities. If this section is intended to apply only to lines taken out of service for more than one day or two lines that have been damaged we would have no Objection. We also see no value in maintaining continuous service through a by-pass as a safety factor. The same fittings and material will be used for the re-connection regardless of continuous service or not. We ask that this section be re-evaluated also.

Thank you for the opportunity of presenting some of our ideas and experience to your organization. I know we are both vitally interested in the safe and efficient transportation of gas.

Sincerely

Ronald K. Espe
Manager of Engineering

All this and more including the complete history of Part 192 in WinDOT, The Pipeline Safety Encyclopedia.

Homeowners and homeowner associations are often critical of markers, as they feel the markers are unsightly  and detract from the neighborhood.  It is not unusual for these persons to remove markers they feel are unsightly.

Part 190 Pipeline Safety Programs and Rulemaking Procedures in §190.229(d) states “ Any person who willfully and knowingly defaces, damages, removes, destroys any pipeline sign, right-of-way marker, or marine buoy required by 49 U.S.C. 60101 et seq. or 49 U.S.C. 5101 et seq., or any regulation or order issued thereunder shall, upon conviction, be subject, for each offense, to a fine of not more than $5,000, imprisonment for a term not to exceed 1 year, or both.”

When markers are destroyed or removed operators should inform those responsible, if known, of this provision.

The following interpretation reinforces the importance of markers and the penalties for removal.

Interpretation 195.410  7
April 2, 1991

The Honorable E. Thomas Coleman
U. S. House of Representatives
2468 Rayburn House Office Building
Washington, DC  20515

Dear Congressman Coleman:

Your recent inquiry transmitted a letter from your constituent,  Lana Fowler, to our Office of Congressional Affairs.  Ms. Fowler, President of the Hidden Lake Homes Association, explained therein that Williams Pipe Line Company (Williams) had installed white plastic marker poles in her neighborhood to identify the location of petroleum pipelines.  The Association proposes to replace the marker poles with markers flush with the ground.

The markers identify the location of four pipelines in a single corridor that traverse the neighborhood.  They carry gasoline, jet fuel, and home heating oil.  The federal regulation (49 CFR 195.410) referred to by Ms. Fowler requires operators such as Williams to mark the presence of pipelines carrying there products by using signs or other objects.  The particular type or size of marker is not specified in the regulation, but is left to the operator’s discretion provided the objectives of the rule – to warn others of the presence of underground pipelines and to provide an emergency telephone number – are carried out.  The importance of pipeline markers was recognized by Congress in 1988 in the Pipeline Safety Reauthorization Act when the destruction or removal of pipeline markers was made subject to criminal penalties.

Although the flush markers recommended by Ms. Fowler may technically be permissible under the pipeline safety regulations, we do not encourage their use because they can become obscured by snow, debris, or vegetation.  I believe the most effective alternative would be an above ground marker that conveys the required information, but in an aesthetically pleasing manner.  Hopefully, this can be worked out in discussions between Ms. Fowler’s homeowner’s association and Williams.

If we can be of further assistance, please let us know.

Sincerely,

Travis P. Dungan

All this and more in WinDOT, The Pipeline Safety Encyclopedia.