RULES REGULATING PIPELINE OPERATORS AND GAS PIPELINE SAFETY

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Code of Colorado Regulations › 700 Department of Regulatory Agencies › 723 Public Utilities Commission › 4 CCR 723-11

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Text

Department of Regulatory Agencies

Public Utilities Commission

RULES REGULATING PIPELINE OPERATORS AND GAS PIPELINE SAFETY

4 CCR 723-11

[Editor’s Notes follow the text of the rules at the end of this CCR Document.]

BASIS, PURPOSE, AND STATUTORY AUTHORITY

The purpose of these rules is to describe the requirements for the safe operation of

jurisdictional gas pipeline facilities, including construction, operations, maintenance, and

operator reporting. These rules outline how the Commission will conduct pipeline safety

program activities and complete the Commission’s Program Certification Obligations.

The statutory authority for the promulgation of these rules can be found at §§ 40-1-103,

40-2-108, 40-2-115, 40-3-110, 40-4-109, 40-6-108, and 40-7-117, C.R.S.

GENERAL PROVISIONS

11000.

Scope and Applicability.

(a)

Absent a specific statute, rules or Commission order that provides otherwise, all

rules in this Part 11 (the 11000 series) shall apply to all public utilities and all

municipal or quasi-municipal corporations transporting natural gas or providing

natural gas service, all operators of master meter systems, and all operators or

pipelines transporting gas in intrastate commerce, as defined in 49 C.F.R. §

191.3.

(b)

The Public Utilities Commission conducts its Pipeline Safety Program (PSP)

activities under §§ 40-1-103, 40-2-115, and 40-7-117, C.R.S. These provide the

state statutory authority permitting the Commission to enter into cooperative

agreements with federal agencies and to adopt and create rules to administer

and to enforce the Natural Gas Pipeline Act found at 49 U.S.C. §§ 60101, et.

seq. Collectively, the above referenced federal code and state statutes comprise

the Commission’s Program Certification Obligations.

40-7-117, C.R.S. These provide the

state statutory authority permitting the Commission to enter into cooperative

agreements with federal agencies and to adopt and create rules to administer

and to enforce the Natural Gas Pipeline Act found at 49 U.S.C. §§ 60101, et.

seq. Collectively, the above referenced federal code and state statutes comprise

the Commission’s Program Certification Obligations.

(c)

These gas pipeline safety rules prescribe the Commissions’ requirements for:

(I)

the safe construction, operation, maintenance, and integrity management

of:

(A)

all intrastate pipeline facilities engaged in the transportation of

hazardous gases, including natural gas and vaporized liquefied

petroleum (LP) gas; and

Code of Colorado Regulations

Secretary of State

State of Colorado

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(B)

liquefied natural gas (LNG) facilities; and

(II)

reporting requirements for operators of all facilities and pipeline systems.

(d)

These rules apply to establish and govern:

(I)

regulations and standards for the safe transportation of hazardous gases

by intrastate pipeline in Colorado;

(II)

administration of the pipeline safety regulations by the Commission;

(III)

reporting to the Commission by operators of specific information related to

pipeline safety; and

(IV)

adoption of federal minimum safety standards for transportation of natural

gas and other gas by pipeline including;

(A)

adoption of federal minimum safety standards for LNG facilities;

and

(B)

adoption of federal drug and alcohol testing regulations and

procedures.

(e)

Except as otherwise directed, processes provided in the Commission’s Rules of

Practice and Procedure, 4 CCR 723-1, including the rules governing

confidentiality, shall apply to all filings made pursuant to this Part 11.

gas by pipeline including;

(A)

adoption of federal minimum safety standards for LNG facilities;

and

(B)

adoption of federal drug and alcohol testing regulations and

procedures.

(e)

Except as otherwise directed, processes provided in the Commission’s Rules of

Practice and Procedure, 4 CCR 723-1, including the rules governing

confidentiality, shall apply to all filings made pursuant to this Part 11.

(f)

Consistent with § 40-15-107(2)(a), C.R.S., all information, documents, and

copies of documents provided in connection with an audit, including any Request

for Information from the PSP Chief or PSP Staff, shall be treated as confidential

and shall not be made public by the Commission or any other person without

prior written consent of the person providing such information, documents, or

copies; or pursuant to a court order issued pursuant to § 24-72-204(5), C.R.S. If

any such information, document, or copy of a document becomes the basis for,

or employed within, an enforcement action pursuant to rule 11500 et seq., rules

1100-1103 of the Commission’s Rules of Practice and Procedure shall govern

any claim of confidentiality in such proceeding. Any such information, document,

or copy of a document that is not treated as, or deemed, confidential or highly

confidential in any such proceeding thereafter shall not be treated by the

Commission as confidential for any other purpose.

(g)

Nothing in these rules shall be construed to exempt pipeline operators from

complying with § 9-1.5-105, C.R.S.

11001.

Definitions.

The following definitions apply throughout this Part 11, except where a specific rule or

statute provides otherwise or where the context otherwise indicates. In the event of a

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conflict between these definitions and a statutory definition, the statutory definition shall

apply.

ying with § 9-1.5-105, C.R.S.

11001.

Definitions.

The following definitions apply throughout this Part 11, except where a specific rule or

statute provides otherwise or where the context otherwise indicates. In the event of a

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conflict between these definitions and a statutory definition, the statutory definition shall

apply.

(a)

“Advanced leak detection technology” means commercially available equipment

that, for screening surveys, can detect potential or confirmed leaks in a pipeline

to use with other Part 192 regulated gas pipeline facilities or within a suite of

mutually reinforcing technologies to offer comparable leak detection ability. This

can include a variety of commercially available methods to detect leaks including,

but not limited to, optical, infrared, or laser-based devices, continuous monitoring

via stationary gas detectors, pressure monitoring or other means; mobile

surveys; or systemic use of any other commercially available advanced

technology, based on the following:

(I)

technology using infrared or laser-based leak detection equipment;

mobile, aerial, or satellite-based platforms; or fixed continuous monitoring

systems must have a minimum flowrate detection threshold of 10 kg/hr

with 90 percent or greater probability of detection; or

(II)

technology using handheld leak detection equipment or equipment

mounted on ground vehicles must have a minimum sensitivity of 5 ppm.

logy using infrared or laser-based leak detection equipment;

mobile, aerial, or satellite-based platforms; or fixed continuous monitoring

systems must have a minimum flowrate detection threshold of 10 kg/hr

with 90 percent or greater probability of detection; or

(II)

technology using handheld leak detection equipment or equipment

mounted on ground vehicles must have a minimum sensitivity of 5 ppm.

(b)

“Business district” means:

(I)

areas where gas facilities are located, with or without other underground

facilities, under continuous street and sidewalk paving that extends to the

building walls on one or both sides of the street (this may include areas

where the public regularly congregates or where the majority of the

buildings on either side of the street are regularly utilized for industrial,

commercial, financial, educational, religious, health, multi-family

residential, or recreational purposes); or

(II)

any other area that, in the judgement of the operator, should be so

designated.

(c)

“C.F.R.” means the Code of Federal Regulations.

(d)

“Confirmed discovery” means a discovery defined, as of the effective date of

these rules, in 49 C.F.R. § 191.3.

(e)

“Continuing violation” or “time-dependent violation” means any violation of these

rules for which a timeframe of non-compliance can be established through

physical evidence and/or records that include, but are not limited to: operator

annual reports; operator compliance, operations, and maintenance records; and

Commission inspection, compliance and proceeding records.

(f)

“Delivered system pressure” means the system operating pressure measured at

the outlet of the furthest downstream appurtenance maintained by the pipeline

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system operator, e.g., regulator, meter, valve, or the terminal connection of the

service riser in low-pressure distribution systems.

compliance and proceeding records.

(f)

“Delivered system pressure” means the system operating pressure measured at

the outlet of the furthest downstream appurtenance maintained by the pipeline

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system operator, e.g., regulator, meter, valve, or the terminal connection of the

service riser in low-pressure distribution systems.

(g)

“De minimis gas system” means a non-utility underground pipeline system used

for transport and distribution of natural gas to less than ten customers within a

definable private (i.e., non-municipal or public) area (e.g., a mobile home park or

resort) and that does not cross a public right-of-way.

(h)

“Direct sales meter” means a meter that measures the transfer of gas to a direct

sales customer purchasing gas for consumption.

(i)

“Direct sales pipeline” means a pipeline not under the jurisdiction of the Federal

Energy Regulatory Commission and that runs from an intrastate or interstate

transmission pipeline, a production facility, or a gathering pipeline to a direct

sales meter, a pressure regulator, or an emergency valve, whichever is the

furthest downstream.

(j)

“Distribution system” means the piping and associated facilities used to deliver

natural gas to customers and does not include the facilities that an operator owns

that are classified as production, storage, gathering, or transmission facilities.

(k)

“Excavation damage” means any impact that results in the need to repair or

replace an underground facility due to a weakening or the partial or complete

destruction of a facility, including, the protective coating; plastic pipe tracer wire;

lateral support; cathodic protection; or the housing for the line device or facility.

(l)

“Gas” means natural gas, flammable gas, and any gas that is toxic or corrosive

gas, or petroleum gas.

(m)

“Gathering pipeline” means any pipeline determined through the use of 49 C.F.R.

§ 192.8 to be jurisdictional.

mplete

destruction of a facility, including, the protective coating; plastic pipe tracer wire;

lateral support; cathodic protection; or the housing for the line device or facility.

(l)

“Gas” means natural gas, flammable gas, and any gas that is toxic or corrosive

gas, or petroleum gas.

(m)

“Gathering pipeline” means any pipeline determined through the use of 49 C.F.R.

§ 192.8 to be jurisdictional.

(n)

“Geographic Information Systems (GIS)” means a computer-based system for

capturing, storing, checking, displaying, and analyzing data related to positions

on Earth’s surface.

(o)

“Hazardous facility” means a pipeline facility that, if allowed to go into operation

or to remain in operation, would pose a severe or imminent risk to public safety.

(p)

“Inactive/Idle” means a pipeline or pipeline segment that has ceased normal

operations and will not resume service for a period of not less than 180 days; has

been isolated from all sources of hazardous liquid, natural gas, or other gas; and

has been purged of combustibles and hazardous materials and maintains a

blanket of inert, non-flammable gas at low pressure or has not been purged but

the volume of gas is so small that there is no potential hazard, as defined in 49

U.S.C. § 60143.

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(q)

“Incident” means an event defined as of the effective date of these rules, in 49

C.F.R. § 191.3, for a pipeline facility covered by 49 C.F.R. Part 192 or an

emergency, as defined in § 193.2007 for an LNG facility.

(r)

“Liquefied natural gas” (LNG) means natural or synthetic gas that has methane

(CH4) as its major constituent and that has been converted to liquid form for

purposes of storage or transport.

nt” means an event defined as of the effective date of these rules, in 49

C.F.R. § 191.3, for a pipeline facility covered by 49 C.F.R. Part 192 or an

emergency, as defined in § 193.2007 for an LNG facility.

(r)

“Liquefied natural gas” (LNG) means natural or synthetic gas that has methane

(CH4) as its major constituent and that has been converted to liquid form for

purposes of storage or transport.

(s)

“Liquid petroleum gas (LPG) system” means the liquid petroleum (LP) tanks

and/or the pipeline system used to transport and distribute LP fuel gas to ten or

more customers within a definable private (i.e. non-municipal or public) area

(e.g., a mobile home park or resort), or less than ten customers if the system

crosses a public right-of-way. LPG systems may have multiple operators if the

supplying tank(s) is/are operated and maintained distinctly from the pipeline

system by a different owner.

(t)

“Low-pressure distribution system” means a gas distribution system in which the

gas pressure in the main is substantially the same as the pressure provided to

the customer, i.e., the low-pressure gas burning equipment of the customer may

be safely and continually operated at the delivered system pressure.

(u)

“LPG Tank – CDLE OPS Inspected” means any LPG tank inspected by the

Colorado Department of Labor and Employment, Division of Oil and Public

Safety under the authority of the OPS rules.

(v)

“LNG facility” means a pipeline facility that is used for liquefying natural or

synthetic gas and/or for transferring, storing, or vaporizing liquefied natural gas.

(w)

“Main” means a distribution line that serves, or is designed to serve, as a

common source of supply for more than one service line.

(x)

“Major master meter operator (MMO)/LPG system” refers to any MMO or LPG

pipeline system serving 100 or more customers.

pipeline facility that is used for liquefying natural or

synthetic gas and/or for transferring, storing, or vaporizing liquefied natural gas.

(w)

“Main” means a distribution line that serves, or is designed to serve, as a

common source of supply for more than one service line.

(x)

“Major master meter operator (MMO)/LPG system” refers to any MMO or LPG

pipeline system serving 100 or more customers.

(y)

“Mechanical excavation” means any operation in which earth is moved or

removed by means of any tools, equipment, or explosives and includes auguring,

backfilling, boring, ditching, drilling, grading, plowing-in, pulling-in, ripping,

scraping, trenching, hydro-excavating, post/postholing, and tunneling.

(z)

“MMO gas system” means a non-utility pipeline system used for transport and

distribution of natural gas to ten or more customers within a definable private

(i.e., non-municipal or public) area (e.g., a mobile home park or resort), or less

than ten customers if the system crosses a public right-of-way.

(aa)

“Minor MMO/LPG system” means any MMO or LPG pipeline system serving

between 20 and 99 customers.

(bb)

“Municipality” means a city, town, or village in the state of Colorado.

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(cc)

“NRC” means the National Response Center of the United States Coast Guard.

(dd)

“NTSB” means the National Transportation Safety Board, an independent federal

agency.

(ee)

“Natural Gas Pipeline Act” means the federal statute found at 49 U.S.C. §§

60101 et seq., as amended.

(ff)

“No immediate safety impact” refers to action or inaction by operator/operator

contractors on jurisdiction pipeline facilities that resulted in no immediate or

imminent hazard to either the public, operator/operator contractor personnel, or

pipeline system integrity

ndent federal

agency.

(ee)

“Natural Gas Pipeline Act” means the federal statute found at 49 U.S.C. §§

60101 et seq., as amended.

(ff)

“No immediate safety impact” refers to action or inaction by operator/operator

contractors on jurisdiction pipeline facilities that resulted in no immediate or

imminent hazard to either the public, operator/operator contractor personnel, or

pipeline system integrity.

(gg)

“Operator” means a person who is engaged in the transportation of gas, or who

has the right to bury underground pipeline, or who is both engaged in the

transportation of gas and has the right to bury underground pipeline, and may

include an owner, such as a pipeline corporation.

(hh)

“Operator contractor” means any person or entity empowered by an operator to

perform any action covered by 49 C.F.R. Part 192 and these rules.

(ii)

“Operator endangerment” refers to action or inaction by operator/operator

contractors on pipeline facilities that resulted in an immediate or imminent hazard

to operator/operator contractor personnel.

(jj)

“OPS” means the Office of Pipeline Safety, a unit of the PHMSA.

(kk)

“Part 192” means 49 C.F.R. Part 192 – Transportation of natural and other gas

by pipeline: Minimum Federal safety standards.

(ll)

“Person” means an individual, firm, joint venture, partnership, corporation,

association, municipality, cooperative association, or joint stock association, and

includes any trustee, receiver, assignee, or personal representative thereof.

(mm) “Petroleum gas” means propane, propylene, butane, (normal butane or

isobutanes), and butylene or mixtures composed predominately of these gases.

(nn)

“PHMSA” means the Pipeline and Hazardous Materials Safety Administration, an

agency of the United States Department of Transportation

, or joint stock association, and

includes any trustee, receiver, assignee, or personal representative thereof.

(mm) “Petroleum gas” means propane, propylene, butane, (normal butane or

isobutanes), and butylene or mixtures composed predominately of these gases.

(nn)

“PHMSA” means the Pipeline and Hazardous Materials Safety Administration, an

agency of the United States Department of Transportation.

(oo)

“Pipeline” or “pipeline system” means all parts of those physical intrastate

facilities through which gas moves in transportation, including, but not limited to,

pipes, valves, and other appurtenances attached to pipes, compressor units,

metering stations, regulator stations, delivery stations, holders, and fabricated

assemblies that start downstream beyond the farthest most point of oil and gas

production. Flowlines that are regulated by the ECMC and used for oil and gas

production are not included in the definition.

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(pp)

“Pipeline excavation damage prevention program” means an operator’s written

program and processes to prevent damage to a pipeline by excavation, as

defined in 49 C.F.R. § 192.614.

(qq)

“Pipeline facility” means new and existing intrastate pipelines, rights-of-way, and

any equipment, facility, or building used in the transportation of gas, or in the

treatment of gas during transportation.

(rr)

“Pipeline integrity” means the ability of a pipeline system to operate as it was

verifiably designed and constructed.

(ss)

“Pipeline safety program” (PSP) means the Commission’s pipeline safety

program operated in accordance with the Commission’s 49 U.S.C. §§ 60105 (a)

certification and 60106 (a) agreement.

(tt)

“Production facility” means flowline and associated equipment used at a wellsite

in producing, extracting, recovering, lifting, stabilizing, initial separating, treating,

initial dehydrating, disposing, and/or above ground storing, of liquid

hydrocarbons, associated liquids, and associated natural hydrocarbon gases

the Commission’s 49 U.S.C. §§ 60105 (a)

certification and 60106 (a) agreement.

(tt)

“Production facility” means flowline and associated equipment used at a wellsite

in producing, extracting, recovering, lifting, stabilizing, initial separating, treating,

initial dehydrating, disposing, and/or above ground storing, of liquid

hydrocarbons, associated liquids, and associated natural hydrocarbon gases. A

production facility may include flowlines up to a central delivery point directly

associated with a specific producing field. To be a production facility under this

rule, a flowline must be used in the process of extracting hydrocarbons and

associated liquids from the ground or from facilities where hydrocarbons are

produced or must be used for disposal or injection in reservoir maintenance or

recovery operations.

(uu)

“PSP Chief” means the program manager of the PHMSA certified PSP of the

Colorado Public Utilities Commission.

(vv)

“PSP Lead Engineer” means the senior technical staff member of the PHMSA

certified PSP of the Colorado Public Utilities Commission.

(ww) “PSP Staff” means a staff member of the PHMSA certified PSP of the Colorado

Public Utilities Commission.

(xx)

“Program certification obligations and agreements” means the pipeline safety

program obligations required under 49 U.S.C. § 60105 (a) and the pipeline safety

agreements required under 49 U.S.C. § 60106 (b).

(yy)

“Public endangerment” means an action or inaction by an operator/operator

contractor on pipeline facilities that results in:

(I)

interruption or delay of make safe actions designed to protect human life;

(II)

unintended gas release requiring emergency (versus precautionary)

evacuation of the public;

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49 U.S.C. § 60106 (b).

(yy)

“Public endangerment” means an action or inaction by an operator/operator

contractor on pipeline facilities that results in:

(I)

interruption or delay of make safe actions designed to protect human life;

(II)

unintended gas release requiring emergency (versus precautionary)

evacuation of the public;

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(III)

an unsafe ignition of intended gas release in an area accessible to the

public;

(IV)

system over pressurization event/failure of system overpressure protection

requiring emergency (versus precautionary) evacuation of the public; or

(V)

any other hazardous situation that results in an immediate or imminent

hazard to the public.

(zz)

“Records” means information created, manipulated, communicated or stored in

physical, digital, or electronic form. Records relate, but are not limited, to

functions, policies, decisions, procedures, operations, or other activities of the

utility.

(aaa) “Roadway” means a main public artery, highway, or interstate highway.

(bbb) “Related violation” for purposes of informing the Commission authority pursuant

to § 40-7-117, C.R.S., means a violation of these rules that has been proven to

be directly linked with a PUC rule violation or violations by time, place, activity,

and/or personnel.

(ccc) “Request for Information (RFI)” means any request from the PSP Chief or

assignee to a jurisdictional operator for information associated with PSP

inspection activities authorized by paragraph 11013(a).

(ddd) “Single structure, above-ground MMO/LPG system” or “SSAG System” means

any MMO or LPG system that is:

(I)

a low-pressure gas distribution system;

(II)

is comprised wholly of above-ground piping/appurtenances; and

(III)

is contained wholly within or on a single continuous structure such as an

apartment building, hotel, mall, etc.

(eee) “Small operator” means any gas distribution system operator that operates less

than 1000 natural gas distribution services in the state of Colorado

G system that is:

(I)

a low-pressure gas distribution system;

(II)

is comprised wholly of above-ground piping/appurtenances; and

(III)

is contained wholly within or on a single continuous structure such as an

apartment building, hotel, mall, etc.

(eee) “Small operator” means any gas distribution system operator that operates less

than 1000 natural gas distribution services in the state of Colorado.

(fff)

“Threshold MMO/LPG system” means any MMO or LPG pipeline system serving

less than 20 customers.

(ggg) “Transportation of gas” means the gathering, transmission, or distribution, of gas

by pipeline, or the storage of gas within the state of Colorado that is not subject

to the jurisdiction of the Federal Energy Regulatory Commission under the

Natural Gas Act.

(hhh) “UNCC/Colorado 811” means the Utility Notification Center of Colorado.

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(iii)

“U.S.C.” means the United States Code.

11002. – 11007.

[Reserved].

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11008.

Incorporation by Reference.

(a)

The Commission incorporates by reference the federal standards for reporting

safety-related conditions associated with the transportation of natural gas and

other gas by pipeline published in 49 C.F.R. § 191.23 (reporting safety-related

conditions), effective May 16, 2022 and § 191.25 (filing safety-related condition

reports), effective July 1, 2020. This incorporation by reference does not include

later amendments to, or editions of, 49 C.F.R. Part 191.

(b)

The Commission incorporates by reference the federal safety standards for the

transportation of natural gas and other gas by pipeline published in 49 C.F.R.

Part 192, effective January 15, 2025. This incorporation by reference does not

include later amendments to, or editions of, 49 C.F.R. Part 192.

poration by reference does not include

later amendments to, or editions of, 49 C.F.R. Part 191.

(b)

The Commission incorporates by reference the federal safety standards for the

transportation of natural gas and other gas by pipeline published in 49 C.F.R.

Part 192, effective January 15, 2025. This incorporation by reference does not

include later amendments to, or editions of, 49 C.F.R. Part 192.

(c)

The Commission incorporates by reference the federal safety standards for

liquefied natural gas facilities that are published in 49 C.F.R. Part 193 effective

August 6, 2015. This incorporation by reference does not include later

amendments to, or editions of, 49 C.F.R. Part 193.

(d)

The Commission incorporates by reference the drug and alcohol testing

regulations and procedures of PHMSA published in 49 C.F.R. Part 40, effective

June 21, 2024 and Part 199 effective, April 23, 2019. This incorporation by

reference does not include later amendments to, or editions of, 49 C.F.R. Parts

40 and 199.

(e)

The Commission incorporates by reference the NPMS Operator Standards

Manual, updated January 2025.

(f)

Any material incorporated by reference in this Part 11 may be examined at the

offices of the Commission, 1560 Broadway, Suite 250, Denver, Colorado 80202,

during normal business hours, Monday through Friday, except for state holidays.

Incorporated standards shall be available electronically and provided in certified

copies, at cost, upon request. Restrictions on the provision of physical copies

due to copyright protections may apply. The Director or the Director’s designee

will provide information regarding how the incorporated standards may be

examined at any state public depository library. The standards and regulations

are also available from the agency, organization or association originally issuing

the code, standard, guideline or rule as follows: Code of Federal Regulations:

www.govinfo.gov/help/cfr.

11009.

More Stringent Standards

r or the Director’s designee

will provide information regarding how the incorporated standards may be

examined at any state public depository library. The standards and regulations

are also available from the agency, organization or association originally issuing

the code, standard, guideline or rule as follows: Code of Federal Regulations:

www.govinfo.gov/help/cfr.

11009.

More Stringent Standards.

In the event of a more stringent rule of the Commission regarding any administrative,

enforcement, operations, maintenance, or construction task, or reporting requirement of

49 C.F.R. Parts 40, 192, 193, and/or 199 and Commission Pipeline Safety Rules, the

Commission’s rules shall apply.

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11010.

Interpretation.

(a)

Consistent with rule 1304 of the Commission Rules of Practice and Procedure, 4

CCR 723-1, an operator may file a petition seeking a declaratory order that

resolves a controversy or uncertainty regarding any statute, Commission rule,

regulation, and/or Commission decision. The requestor shall include with each

request, at least the following:

(I)

the statutory provision(s), Commission rule(s), regulation(s). and/or

decision(s) at issue;

(II)

the specific instance or illustration of the application of the statutory

provision(s), Commission rule(s), regulation(s), and/or decision(s) that

causes the controversy or uncertainty; and

(III)

the complete petitioner’s contact information.

(IV)

The petition may also include a request for expedited treatment if an

interpretation is needed quickly and good cause exists.

(b)

Upon receipt of the petition for a declaratory order, the Commission will consider

whether to accept the filing consistent with rule 1304 of the Commission’s Rules

of Practice and Procedure, 4 CCR 723-1.

nty; and

(III)

the complete petitioner’s contact information.

(IV)

The petition may also include a request for expedited treatment if an

interpretation is needed quickly and good cause exists.

(b)

Upon receipt of the petition for a declaratory order, the Commission will consider

whether to accept the filing consistent with rule 1304 of the Commission’s Rules

of Practice and Procedure, 4 CCR 723-1.

(c)

If the petition requires interpretation of a federal regulation incorporated by

reference into these rules and the Commission accepts the petition, PHMSA

must review the Commission’s interpretation of the federal regulation. The

Commission’s decision interpreting the federal regulation, and the reasons

therefore, shall issue as an interim decision that shall be provided to the Office of

Pipeline Safety for final review. Any response by the Office of Pipeline Safety

shall be incorporated into the Commission’s final decision.

(d)

Nothing in these rules prohibits an operator from contacting the PSP Chief or

PSP Lead Engineer for informal assistance. Consistent with paragraph 1007(d)

of the Commission’s Rules of Practice and Procedure, 4 CCR 723-1, opinions

expressed by the PSP Chief or PSP Lead Engineer do not represent the official

views of the Commission, but are designed to aid the public and to facilitate the

accomplishment of the Commission’s functions. Nothing communicated by the

PSP Chief or PSP Lead Engineer constitutes legal advice.

11011.

Waiver – Non-emergency.

(a)

An owner or operator may request a waiver or a variance from any of these rules

in accordance with § 40-2-115, C.R.S., 49 U.S.C. § 60118(d), and paragraph

1003(b) of the Commission’s Rules of Practice and Procedure 4 CCR 723-1.

Requests for waiver from the standards in 49 C.F.R. Part 192 that are

incorporated by reference into these rules that are made pursuant to 49 C.F.R.

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Part 192.1013 are subject to the requirements of both paragraphs (b) and (c)

below.

8(d), and paragraph

1003(b) of the Commission’s Rules of Practice and Procedure 4 CCR 723-1.

Requests for waiver from the standards in 49 C.F.R. Part 192 that are

incorporated by reference into these rules that are made pursuant to 49 C.F.R.

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Part 192.1013 are subject to the requirements of both paragraphs (b) and (c)

below.

(b)

The petition shall include:

(I)

information required by rule 1003 paragraph (c);

(II)

the specific instance or illustration of the rule’s application requiring

modification/waiver;

(III)

proposed alternatives to compliance with the regulation (e.g., additional

inspections and tests, shortened reassessment intervals, etc.);

(IV)

an explanation of the necessity with supporting evidence and

documentation, including:

(A)

the mileage or footage of pipeline to be covered and the counties in

which it is located;

(B)

a description of the pipeline(s) affected by the permit (e.g., year

installed, material, thickness, diameter, operating pressure, etc.);

(C)

all pipeline other facilities such as pump and compressor stations

that the permit will affect; and

(D)

other pertinent operational history/data (e.g., leak history, corrosion

history, etc.);

(V)

a certification that the modification/waiver is consistent with pipeline

safety; and

(VI)

the complete operator contact information.

(c)

An owner or operator may file a petition for waiver under 49 C.F.R. Part

192.1013 to deviate from the standards in 49 C.F.R. Part 192 that are

incorporated into these rules to alter the frequency of periodic inspections and

tests on the basis of an engineering analysis and risk assessment.

(I)

A request for waiver for an alternative frequency of inspections and tests

required under Part 192 will be granted if the request is found to be not

inconsistent with pipeline safety

1013 to deviate from the standards in 49 C.F.R. Part 192 that are

incorporated into these rules to alter the frequency of periodic inspections and

tests on the basis of an engineering analysis and risk assessment.

(I)

A request for waiver for an alternative frequency of inspections and tests

required under Part 192 will be granted if the request is found to be not

inconsistent with pipeline safety. For intrastate facilities, an operator must

file its proposal as a petition for waiver through the Commission’s E-Filings

System at least 120 days before the requested effective date.

(II)

An owner or operator may implement an approved reduction in the

frequency of a periodic inspection or test only where the operator has

developed and implemented an integrity management program that

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provides an equal or improved overall level of safety despite the request

for reduced frequency of periodic inspections.

(III)

In addition to the information in subparagraph (b) above, each petition filed

under this subsection must include the following information:

(A)

name of the owner or operator;

(B)

duration of the deviation proposal;

(C)

specific regulations from which the owner or operator seeks relief;

(D)

a description of the pipeline for which the deviation is sought,

including:

(i)

the mileage or footage of the pipeline to be covered by the

request and the counties in which it is located;

(ii)

the year the pipeline was installed;

(iii)

all pipeline facilities that the request will affect; and

on of the deviation proposal;

(C)

specific regulations from which the owner or operator seeks relief;

(D)

a description of the pipeline for which the deviation is sought,

including:

(i)

the mileage or footage of the pipeline to be covered by the

request and the counties in which it is located;

(ii)

the year the pipeline was installed;

(iii)

all pipeline facilities that the request will affect; and

(iv)

the material, thickness, diameter, and operating pressure of

the pipeline;

(E)

alternatives proposed for compliance with the regulation (e.g.,

additional inspections and tests, shortened reassessment

intervals); and

(F)

a certification that operation of the owner or operator’s pipeline

under the requested alternative frequency of periodic inspections

and tests would not be inconsistent with pipeline safety and will

provide and equal or greater overall level of safety.

(IV)

After receiving notice of the petition, the PSP Chief will confer with the

Office of Pipeline Safety on the waiver requested by the owner or

operator. The PSP Chief will file a notice in the petition proceeding

indicating whether the request should be accepted by the Commission

and if so, whether additional conditions or limitations that are relevant and

in the public interest should be adopted. The Commission shall consider

the petition for waiver and the notice filing of the PSP Chief in rendering a

decision.

(d)

PHMSA Review: If the Commission grants a petition filed by an owner/operator

for a waiver of a federal rule that is incorporated into the Commission rules,

PHMSA must review the Commission’s decision, except for petitions for waiver

covered by paragraph (c) above. The Commission’s decision granting a waiver

request that requires PHMSA review, and the reasons therefore, shall issue as

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y an owner/operator

for a waiver of a federal rule that is incorporated into the Commission rules,

PHMSA must review the Commission’s decision, except for petitions for waiver

covered by paragraph (c) above. The Commission’s decision granting a waiver

request that requires PHMSA review, and the reasons therefore, shall issue as

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an interim decision that shall be provided to the Office of Pipeline Safety for final

review pursuant to 49 U.S.C. § 60118(d). Any response by the Office of Pipeline

Safety shall be incorporated into the Commission’s final decision.

11012.

Waiver – Emergency.

(a)

An operator may file a petition to request an emergency waiver or variance in

situations that require expedited review that is otherwise inconsistent with § 40-2-

115, C.R.S., 49 U.S.C. § 60118(d), and the Commission’s Rules of Practice and

Procedure.

(b)

An emergency waiver request will be granted if it is in the public interest, is

consistent with pipeline safety, and is necessary to address an actual or

impending emergency involving pipeline transportation, including emergencies

caused by natural or manmade disasters.

(c)

An emergency waiver is an order by which the Commission may temporarily

modify compliance with state pipeline regulations for affected pipeline owners or

operators and the Commission may waive compliance with a safety regulation if,

after receiving notice on an incorporated federal rule, PHMSA concurs in the

action.

(d)

The Commission will determine on a case-by-case basis what duration of waiver

or variance is necessary to address the emergency. However, as required by

statute, no emergency waiver may be issued for a period exceeding 60 days.

Each emergency waiver will automatically expire on the date stated in the

Commission’s decision.

ng notice on an incorporated federal rule, PHMSA concurs in the

action.

(d)

The Commission will determine on a case-by-case basis what duration of waiver

or variance is necessary to address the emergency. However, as required by

statute, no emergency waiver may be issued for a period exceeding 60 days.

Each emergency waiver will automatically expire on the date stated in the

Commission’s decision.

(e)

An operator may request an emergency Special Permit modifying or waiving of

any of these rules by submitting a written request as follows.

(I)

If the request concerns a Colorado-specific rule then no subsequent

review by PHMSA is required. The requestor shall file a petition for the

emergency waiver with the Commission using one of the following

methods:

(A)

the Commission’s E-Filings System; or

(B)

express mail/overnight courier to Doug Dean, Director of the

Colorado Public Utilities Commission, 1560 Broadway, Suite 250,

Denver, CO 80202.

(II)

If the request concerns a federal rule incorporated by reference into these

rules, a review by PHMSA is required. The requestor shall submit a

petition for the emergency waiver directly to the Commission using one of

the methods described above and to PHMSA using any of the following

methods:

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(A)

direct fax to the PHMSA Crisis Management Center at: 202-366-

3768;

(B)

direct e-mail to PHMSA at: phmsa.pipeline-

emergencyspecpermit@dot.gov; or

(C)

express mail/overnight courier to the Associate Administrator for

Pipeline Safety, Pipeline and Hazardous Materials Safety

Administration, 1200 New Jersey Avenue, SE East Building,

Washington, DC 20590.

CCR 723-11

Public Utilities Commission

(A)

direct fax to the PHMSA Crisis Management Center at: 202-366-

3768;

(B)

direct e-mail to PHMSA at: phmsa.pipeline-

emergencyspecpermit@dot.gov; or

(C)

express mail/overnight courier to the Associate Administrator for

Pipeline Safety, Pipeline and Hazardous Materials Safety

Administration, 1200 New Jersey Avenue, SE East Building,

Washington, DC 20590.

(f)

The requestor shall include with each emergency waiver petition:

(I)

the information required by rule 1003 paragraph (c);

(II)

an explanation of the actual or impending emergency;

(III)

the specific instance or illustration of the rule’s application requiring

modification/waiver;

(IV)

proposed alternatives to compliance with the regulation (e.g., additional

inspections and tests, shortened reassessment intervals, etc.);

(V)

to the extent possible, as much of the information as is required in

paragraph 11011(c); and

(VI)

measures to be taken after the emergency situation or permit expires,

whichever comes first, that will confirm/assure long-term operational

reliability of the facility impacted by the Special Permit.

(g)

The emergency waiver is effective upon final order by the Commission or the

PHMSA Administrator for Pipeline Safety, as appropriate to the review.

11013.

Inspections and Investigations.

(a)

Upon presenting appropriate credentials, a representative of the PSP may enter

upon, inspect, and examine, at reasonable times, and in a reasonable manner,

the records, facilities, and properties of pipeline operators to the extent such

records, facilities, and properties are relevant to determining the compliance of

such operators with the requirements of these rules or Commission orders.

ns.

(a)

Upon presenting appropriate credentials, a representative of the PSP may enter

upon, inspect, and examine, at reasonable times, and in a reasonable manner,

the records, facilities, and properties of pipeline operators to the extent such

records, facilities, and properties are relevant to determining the compliance of

such operators with the requirements of these rules or Commission orders.

(b)

Verifiable credentials for personnel engaged in pipeline construction, inspection,

and repair activities are required to be provided on site at the time that the

activities are taking place. Operator qualifications for the same personnel may be

provided at a different time and location by request if they cannot be provided on

site, such as an office phone number and point of contact.

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(c)

Prior to an inspection or investigation, the PSP Chief or assignee shall notify an

operator. Except in emergency situations, the operator shall have an opportunity

to respond to the notification prior to the initiation of an inspection or investigation

relating to any jurisdictional pipeline facility, including the operator’s right of way

or easement, new and existing piping, valves, and other above ground

appurtenances attached to pipes, or, upon request of PHMSA, an interstate

pipeline to determine compliance with 49 U.S.C. §§ 60101 et. seq., with these

rules, and with applicable Commission orders.

initiation of an inspection or investigation

relating to any jurisdictional pipeline facility, including the operator’s right of way

or easement, new and existing piping, valves, and other above ground

appurtenances attached to pipes, or, upon request of PHMSA, an interstate

pipeline to determine compliance with 49 U.S.C. §§ 60101 et. seq., with these

rules, and with applicable Commission orders.

(d)

Inspections and investigations are necessitated by the existence of one or more

of the following circumstances:

(I)

routine scheduling by the PSP Chief, PSP Lead Engineer, or other

designee;

(II)

pipeline-related incidents and events reported to the PSP in accordance

with rules 11101 through 11103;

(III)

a complaint received from a member of the public and verified by the PSP

Chief or Lead Engineer as related to a jurisdictional pipeline facility and

involving a discrete and auditable matter potentially impacting public

safety;

(IV)

information obtained from a previous inspection; or

(V)

when deemed appropriate by the Commission or PHMSA under their

respective authorities.

(e)

After an inspection, the PSP Chief will pursue one of the following:

(I)

an inspection close-out indicating that no further action will be taken on

final inspection findings;

(II)

a RFI indicating that the inspection is ongoing without final inspection

findings, to be answered within the timeframe requested in the RFI,

typically 30 calendar days from the operator’s receipt of the RFI unless

otherwise indicated and agreed to by the PSP Chief and the operator; or

(III)

a compliance action taken on final inspection findings as described in

rules 11502 and 11503.

findings;

(II)

a RFI indicating that the inspection is ongoing without final inspection

findings, to be answered within the timeframe requested in the RFI,

typically 30 calendar days from the operator’s receipt of the RFI unless

otherwise indicated and agreed to by the PSP Chief and the operator; or

(III)

a compliance action taken on final inspection findings as described in

rules 11502 and 11503.

(f)

If a representative of the PSP investigates an incident involving a pipeline facility,

the PSP Chief of the Commission may request that the operator make available

to the representative all records and information that directly or indirectly pertain

to the incident, including integrity management plans and test results, and that

the operator afford all reasonable assistance in the investigation.

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(g)

To the extent necessary to carry out the responsibilities of the Program

Certification Obligations, the PSP may require testing of portions of pipeline

facilities that have been involved in, or affected by, an incident. However, before

exercising this authority and accepting responsibility, the PSP shall make every

effort to negotiate a mutually acceptable plan with the owner of those facilities

and, where appropriate, other local and state fire and safety authorities, PHMSA,

the NTSB, and any known third parties for performing the testing.

11014.

Advisory Bulletins.

PSP advisories or PHMSA advisory bulletins are periodically drafted and communicated

to affected operators as a result of circumstances identified by the PSP, PHMSA,

NTSB, or industry with the potential to become pipeline system safety risks. Operators

should review these bulletins for relevancy to their individual pipeline system operations.

11015. – 11099.

[Reserved].

INFORMATION REQUIRED OF OPERATORS

11100.

Submission of Reports and Notices - General.

y drafted and communicated

to affected operators as a result of circumstances identified by the PSP, PHMSA,

NTSB, or industry with the potential to become pipeline system safety risks. Operators

should review these bulletins for relevancy to their individual pipeline system operations.

11015. – 11099.

[Reserved].

INFORMATION REQUIRED OF OPERATORS

11100.

Submission of Reports and Notices - General.

(a)

For all annual reporting, the PSP will access the PHMSA Pipeline Data Mart

beginning on March 16 of every year to confirm operator submittals. Failure to

meet annual report submittal deadlines will result in issuance in a warning notice;

failure to meet submittal deadlines in two successive calendar years will result in

the issuance of a NPV against the operator.

(b)

For all specialized reporting, failure to meet submittal deadlines and

requirements will result in issuance in a warning notice or a NPV against the

operator.

(c)

Geographic Information System (GIS) data listed in subparagraph (II) below shall

be submitted to the PSP. GIS data shall be submitted in the North American

Datum of 1983 (NAD 83). Data may be submitted in zipped geodatabase (GDB),

zipped shapefile (SHP), or google keyhole markup language (KML), with

preference for GDB and SHP.

(I)

Data shall be submitted electronically, including through a form available

on the Commission’s website. Commission staff may update the form

periodically. Whether annual filings are provided through the Commission-

provided form or separately, operators shall ensure that all information

required is included in any submitted report filings.

(II)

Data specifications. The following data attributes for transmission,

distribution, and gathering pipelines shall be submitted to the extent

available:

(A)

spatial location of the pipeline;

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mission-

provided form or separately, operators shall ensure that all information

required is included in any submitted report filings.

(II)

Data specifications. The following data attributes for transmission,

distribution, and gathering pipelines shall be submitted to the extent

available:

(A)

spatial location of the pipeline;

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(B)

operator name;

(C)

fluid type;

(D)

designation of pipeline as transmission, distribution, or gathering;

(E)

for transmission pipelines only, the additional data provided to the

National Pipeline Mapping System (NPMS) by the operator;

(F)

abandoned as defined in 49 CFR 192.3 and inactive pipelines.

Include abandonment and inactive dates as applicable, as defined

in 49 CFR 192.727;

(G)

the maximum allowable operating pressure;

(H)

the testing pressure;

(I)

the pipe description (i.e., nominal diameter, coating, standard

dimension ratio, wall thickness, and material);

(J)

description of corrosion protection (i.e., Galvanic,

Rectified/Impressed Current, or NA);

(K)

identify as HCA/MCA on each segment, as applicable; and

(L)

identify class location for each segment, as applicable.

(III)

Disclosure of GIS data.

(A)

The PSP Chief will make the GIS data in subparagraphs (II)(A)-(F)

above available through a publicly accessible online map viewer.

Online map viewer data only will be available at scales greater than

or equal to 1:6,000. Any person may view spatial data at scales

less than 1:6,000 for an individual parcel at the Commission’s

office, with the exception of map viewer data filed confidentially.

Any data provided confidentially must be filed with a publicly

accessible version at a scale greater than or equal to 1:24000

ap viewer.

Online map viewer data only will be available at scales greater than

or equal to 1:6,000. Any person may view spatial data at scales

less than 1:6,000 for an individual parcel at the Commission’s

office, with the exception of map viewer data filed confidentially.

Any data provided confidentially must be filed with a publicly

accessible version at a scale greater than or equal to 1:24000.

(B)

Upon request from a local governmental designee(s), and subject

to executing a confidentiality agreement and the provisions of the

Colorado Open Records Act and applicable federal law, the

Commission will allow the local government to view in the

Commission’s offices the GIS data (including the data described in

subparagraphs (II)(G)-(L) above) for transmission, distribution or

gathering pipeline systems within the Commission’s jurisdiction.

The local government may only reproduce or publish data that the

Commission makes publicly available through its website. A local

government may share more specific data in-person than that

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which the Commission makes publicly-available, but the information

must be treated as confidential and may not be reproduced or

published.

(C)

Except as provided in subparagraphs (III)(A) and (B) above, the

Commission will keep all such GIS data confidential to the extent

allowed by the Colorado Open Records Act.

(D)

This data will not be used in lieu of Colorado 811 locates and is

subject to civil penalties set forth in and fines assessed pursuant to

§§ 9-1.5-104.4 or 9-1.5-104.5, C.R.S.

ntial and may not be reproduced or

published.

(C)

Except as provided in subparagraphs (III)(A) and (B) above, the

Commission will keep all such GIS data confidential to the extent

allowed by the Colorado Open Records Act.

(D)

This data will not be used in lieu of Colorado 811 locates and is

subject to civil penalties set forth in and fines assessed pursuant to

§§ 9-1.5-104.4 or 9-1.5-104.5, C.R.S.

(d)

For all electronic reporting to PHMSA, if this reporting method imposes an undue

burden and hardship, an operator may submit a written request for an alternative

reporting method to: Information Resources Manager, Office of Pipeline Safety,

Pipeline and Hazardous Materials Safety Administration, PHP-20, 1200 New

Jersey Avenue, SE, Washington, DC 20590. The request must describe the

undue burden and hardship. PHMSA will review the request and may authorize,

in writing, an alternative reporting method. An authorization will state the period

for which it is valid, which may be indefinite. An operator must contact PHMSA at

202-366-8075; electronically to informationresourcesmanager@dot.gov; or make

arrangements for submitting a report that is due after a request for alternative

reporting is submitted but before an authorization or denial is received.

(e)

Annual leak report.

(I)

Beginning March 31, 2025 and annually on March 31 of each year

thereafter, each operator must submit a report to the Commission that

includes:

(A)

the total number of known pending leaks, excluding those repaired

in pipelines owned by the operator as of January 1st of the year the

report is submitted;

(B)

the total number of hazardous leaks, as defined by DOT F7100.1-1

reporting instructions, eliminated or repaired during the previous

one-year period ending December 31st;

(C)

the total number of nonhazardous leaks eliminated or repaired

during the previous one-year period ending December 31st;

(D)

the total number of leaks scheduled for repair in the next one-year

period beginning January 1st of the year the report is submitted;

(E)

the approxima

y DOT F7100.1-1

reporting instructions, eliminated or repaired during the previous

one-year period ending December 31st;

(C)

the total number of nonhazardous leaks eliminated or repaired

during the previous one-year period ending December 31st;

(D)

the total number of leaks scheduled for repair in the next one-year

period beginning January 1st of the year the report is submitted;

(E)

the approximate date and location of each identified leak from the

gas pipeline system detected by the operator through leak survey

and pending as of January 1 of the reporting calendar year;

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(F)

for repaired leaks, the material type of the pipe and facility that was

leaking;

(G)

the leak survey method(s) used to detect each pending leak;

(H)

the approximate date and location of each leak caused by third-

party excavation;

(I)

the volume of each leak, measured in millions of cubic feet, except

that where an exact volume of gas leaked cannot be identified, an

operator may provide its best approximation, if available, and

narrative explanation of its calculations and regarding its

estimation;

(J)

whether the identified cause of each repaired leak was from:

corrosion failure; natural force damage; excavation damage; other

outside force damage; pipe, weld, or joint failure; equipment failure;

incorrect operations; or other causes; and

(K)

a list of the deployed leak detection technology(ies) for each type of

leak survey conducted in the prior calendar year and the leak

indicator(s) that the technology(ies) provide(s). Subsequent annual

reports need only to update the information from previous calendar

year’s report when a different equipment is utilized. This

requirement will go into effect one year after these rules are

effective

a list of the deployed leak detection technology(ies) for each type of

leak survey conducted in the prior calendar year and the leak

indicator(s) that the technology(ies) provide(s). Subsequent annual

reports need only to update the information from previous calendar

year’s report when a different equipment is utilized. This

requirement will go into effect one year after these rules are

effective.

(II)

Natural gas leaks include all confirmed discoveries of unintentional leak

events, including leaks from: corrosion failure; natural force damage;

excavation damage; other outside force damage; pipe, weld, or joint

failure; equipment failure; incorrect operation; or other causes.

(III)

The Commission may use the data reported by operators under this

section, as well as other data reported by operators to the Commission

and to the Air Pollution Control Division and spill and incident data

reported by operators to Carbon and Energy Management Commission to

estimate the volume of leaked gas and associated greenhouse gas

emissions from operational practices in the state. The Commission may

request additional information.

(IV)

The data provided in this section, including the total number of leaks

scheduled for repair under subsection 11100(e)(I)(D), does not prevent

the operator from prioritizing its repair schedule based on new information

and newly identified leaks.

(f)

Disclosure of leak detection data.

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(I)

By June 1, 2025 and annually on June 1 of each year thereafter, the

Commission will provide on its public internet website aggregate data, as

submitted by operators under this section, concerning the volume and

causes of gas leaks.

(II)

By June 1, 2025 and annually on June 1 of each year thereafter, the

Commission will transmit to the Air Pollution Control Division and Energy

and Carbon Management Commission information on gas leakage in the

state, as submitted by operators under this rule.

11101.

Submission of Reports and Notices.

, as

submitted by operators under this section, concerning the volume and

causes of gas leaks.

(II)

By June 1, 2025 and annually on June 1 of each year thereafter, the

Commission will transmit to the Air Pollution Control Division and Energy

and Carbon Management Commission information on gas leakage in the

state, as submitted by operators under this rule.

11101.

Submission of Reports and Notices.

(a)

Operators must submit all required reports, as applicable, within the specified

deadline(s) for the following occasions requiring specialized reporting or notice.

Any reporting shall be in addition to, or supplemental to, reporting required under

federal law and shall not be duplicative.

(b)

Incident reporting.

(I)

Written reports of all incidents required to be reported under these rules

must be submitted as soon as practicable but not more than 30 days after

detection of the incident.

(II)

Each operator submitting information to PHMSA via its electronic portal

shall also file such information with the Commission in accordance with

subparagraph 1204(a)(III) of the Commission’s Rules of Practice and

Procedure in the repository proceeding opened for such reporting

purpose.

(III)

Each operator that submits information to PHMSA via alternative methods

shall file copies of this information with the Commission.

(IV)

Each operator of a distribution pipeline system, excepting MMO/LPG

systems, shall submit the Incident Report (PHMSA F 7100.1) to PHMSA

using its electronic portal at https://portal.phmsa.dot.gov.

(V)

Each operator of an MMO/LPG system shall submit a Small Operator

Incident Report (PSP SOIR) to the Commission through its E-Filings

System in the repository proceeding opened for such reporting purposes.

(VI)

Each operator of a transmission or gathering system (Types A, B, and C),

shall submit the Incident Report (PHMSA F 7100.2) to PHMSA using its

electronic portal at https://portal.phmsa.dot.gov

Each operator of an MMO/LPG system shall submit a Small Operator

Incident Report (PSP SOIR) to the Commission through its E-Filings

System in the repository proceeding opened for such reporting purposes.

(VI)

Each operator of a transmission or gathering system (Types A, B, and C),

shall submit the Incident Report (PHMSA F 7100.2) to PHMSA using its

electronic portal at https://portal.phmsa.dot.gov.

(VII)

Each operator of a LNG facility shall submit the Incident Report (PHMSA F

7100.3) to PHMSA using its electronic portal at

https://portal.phmsa.dot.gov.

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(VIII) When additional relevant information is obtained after the report is

submitted under paragraph (a) or (b) of this rule, the operator shall make

supplementary reports as deemed necessary with a clear reference by

date and subject to the original report. The operator shall notify the PSP

Chief of all supplementary reporting.

(c)

Safety-related condition (SRC) reporting.

(I)

Written reports of SRC’s must be submitted in accordance with the

timelines established in 49 C.F.R. Part 191, § 191.25(a).

(II)

Written reports of SRC’s must be submitted with information as required in

49 C.F.R. Part 191, § 191.25(b).

(III)

Any operator filing a SRC report as required by 49 C.F.R. Part 191, §

191.23 (Reporting SRC’s) and §191.25 (Filing SRC reports) with PHMSA

shall also concurrently inform the PSP Chief through e-mail at

dora_copuc_pipeline_safety@state.co.us and submit the SRC report to

Commission through its E-Filings System in accordance with

subparagraph 1204(a)(III) of the Commission’s Rules of Practice and

Procedure in the repository proceeding opened for such reporting

purposes no later than close of the next business day.

RC reports) with PHMSA

shall also concurrently inform the PSP Chief through e-mail at

dora_copuc_pipeline_safety@state.co.us and submit the SRC report to

Commission through its E-Filings System in accordance with

subparagraph 1204(a)(III) of the Commission’s Rules of Practice and

Procedure in the repository proceeding opened for such reporting

purposes no later than close of the next business day.

(d)

Pipeline damage and locate information reporting. Each operator subject to the

requirements of these rules and Colorado Revised Statutes Title 9, Article 1.5

(the “Colorado One-call Law”) shall submit the PSP Damage and Locate Report

(PSP DLR) to the Commission through its E-Filings System in accordance with

paragraph 1204(a) of the Commission’s Rules of Practice and Procedure in the

repository proceeding opened for such reporting purposes.

11102.

Verbal Reporting of Pipeline Incidents and Events.

(a)

Colorado pipeline incidents.

(I)

All pipeline and LNG facility operators must provide expedited reporting of

a pipeline incident as soon as possible after confirmed discovery; not to

exceed two hours after confirmed discovery.

(II)

If the expedited reporting time for a pipeline incident exceeds two hours

after confirmed discovery, the operator shall provide a written explanation

for the time exceedance to the PSP Chief within ten business days after

the incident.

(III)

All operators must report a pipeline incident to:

(A)

the NRC via telephone at 800-424-8802; and

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pedited reporting time for a pipeline incident exceeds two hours

after confirmed discovery, the operator shall provide a written explanation

for the time exceedance to the PSP Chief within ten business days after

the incident.

(III)

All operators must report a pipeline incident to:

(A)

the NRC via telephone at 800-424-8802; and

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(B)

after an NRC control number is issued for the incident, to the PSP

Staff via telephone at 303-894-2854.

(IV)

A telephonic report made pursuant to this rule must include the following

information:

(A)

the NRC control number;

(B)

the name and telephone number of the operator and the contact for

more information on the incident;

(C)

the location of the incident or event;

(D)

the date and time of the incident or event;

(E)

the number of fatalities and personal injuries, if any; and

(F)

all other significant facts that are known by the person making the

report that are relevant to the cause of the incident and the extent

of the damage.

(b)

Colorado pipeline events.

(I)

All pipeline operators, including operators of LNG facilities/systems and

MMO/LPG systems, must provide expedited reporting of pipeline events

described below as soon as possible after discovery; not to exceed two

hours after confirmed discovery.

(II)

If the expedited reporting time for a pipeline event exceeds two hours after

confirmed discovery, the operator shall provide a written explanation for

the exceedance to the PSP Chief within ten business days after the event

MO/LPG systems, must provide expedited reporting of pipeline events

described below as soon as possible after discovery; not to exceed two

hours after confirmed discovery.

(II)

If the expedited reporting time for a pipeline event exceeds two hours after

confirmed discovery, the operator shall provide a written explanation for

the exceedance to the PSP Chief within ten business days after the event.

(III)

All pipeline operators must report the following pipeline events to the PSP

Staff via telephone at 303-894-2854:

(A)

an unplanned/emergency event that occurs on the pipeline system

that results in the evacuation of 50 or more people from a normally

occupied building or property;

(B)

an unplanned/emergency event that occurs on the pipeline system

that results in the closure of all lanes in either direction of a

roadway or railroad;

(C)

an unplanned/emergency event that occurs on the pipeline system

that results in the evacuation of four or more residential structures;

(D)

an unplanned/emergency event that occurs on the pipeline system

that results in a service outage of 100 or more customers;

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(E)

an event that requires active soil vapor extraction for a period

exceeding 48 hours as measured from the time the extraction

device is turned on at the site until the operator determines soil

vapor extraction is no longer necessary;

(F)

a MAOP-exceedance event that requires the operator, pursuant to

its procedures, to implement follow-up actions such as a leak

survey; or

(G)

an event that, in the opinion of the operator, requires courtesy

notification to the PSP.

11103.

Submission of Annual Reports.

time the extraction

device is turned on at the site until the operator determines soil

vapor extraction is no longer necessary;

(F)

a MAOP-exceedance event that requires the operator, pursuant to

its procedures, to implement follow-up actions such as a leak

survey; or

(G)

an event that, in the opinion of the operator, requires courtesy

notification to the PSP.

11103.

Submission of Annual Reports.

(a)

On or before March 15 of each year:

(I)

each operator of a distribution pipeline system, excepting MMO/LPG

systems, shall submit the annual report (PHMSA F 7100.1-1) to PHMSA

using its electronic portal at https://portal.phmsa.dot.gov;

(II)

each operator of an MMO/LPG system shall submit the MMO/LPG annual

report to the Commission through its E-Filings System in the repository

proceeding opened for annual reports;

(III)

each operator of a transmission or gathering system (i.e., Types A, B, C,

and R), shall submit the annual report (PHMSA F 7100.2-1 or PHMSA

F7100.2-3, as appropriate) to PHMSA using its electronic portal at

https://portal.phmsa.dot.gov; and

(IV)

each operator of a LNG facility shall submit the annual report (PHMSA F

7100.3-1) to PHMSA using its electronic portal at

https://portal.phmsa.dot.gov.

(b)

On or before March 31, 2025, and March 31 of each year thereafter:

(I)

each operator shall submit to the Commission GIS data according to

paragraph 11100(c); and

(II)

each operator shall submit to the Commission a list of leak detection

technology(ies), including both proven, conventional, and advanced, being

used according to paragraph 11100(e).

(c)

Each operator of an MMO/LPG system shall submit the Small Operator Annual

Report (PSP SOAR) to the Commission through its E-Filings System in the

repository proceeding opened for annual reports.

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leak detection

technology(ies), including both proven, conventional, and advanced, being

used according to paragraph 11100(e).

(c)

Each operator of an MMO/LPG system shall submit the Small Operator Annual

Report (PSP SOAR) to the Commission through its E-Filings System in the

repository proceeding opened for annual reports.

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(d)

Each operator of a transmission or Type A or Type B gathering system (i.e.,

excepting rural gathering), shall submit the Annual Report (PHMSA F 7100.2-1)

to PHMSA using its electronic portal at https://portal.phmsa.dot.gov.

(e)

Each operator of a LNG facility shall submit the Annual Report (PHMSA F

7100.3-1) to PHMSA using its electronic portal at https://portal.phmsa.dot.gov.

11104. – 11199.

[Reserved].

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SAFETY STANDARDS FOR HAZARDOUS GAS PIPELINE SYSTEMS

11200.

Standards – General.

An operator shall comply with these rules and the minimum safety standards for the

transportation of natural gas and other gas by pipeline that are incorporated by

reference in rule 11008, as applicable.

11201.

Pipeline Excavation Damage Prevention.

(a)

All operators must be members of the UNCC/Colorado 811 if any part of the

pipeline system is located in any public or railroad right-of-way.

(b)

All operators, excluding operators of MMO/LPG pipeline systems, must report

underground facility damages to the UNCC/Colorado 811 in accordance with § 9-

1.5-103(7), C.R.S.

(c)

Operators of MMO/LPG must install and maintain pipeline markers, labeled

according to § 192.707(d), at each crossing of a public road or railroad right-of-

way.

system is located in any public or railroad right-of-way.

(b)

All operators, excluding operators of MMO/LPG pipeline systems, must report

underground facility damages to the UNCC/Colorado 811 in accordance with § 9-

1.5-103(7), C.R.S.

(c)

Operators of MMO/LPG must install and maintain pipeline markers, labeled

according to § 192.707(d), at each crossing of a public road or railroad right-of-

way.

(d)

All operators, excluding operators of MMO/LPG, must have written guidelines

regarding when and how civil penalties are pursued under § 9-1.5-104.5, C.R.S.

against persons damaging their pipeline facilities, and when and how penalty

alternatives are implemented. At a minimum, the collection of data on and

subsequent analysis of the causes of excavation damages to comply with 49

C.F.R. § 192.614 (a). These guidelines must provide for:

(I)

recording information about pipeline damages that includes identification

of the responsible party and the probable cause of each excavation

damage in the following categories:

(A)

inadequate excavation practices;

(B)

no locate requested;

(C)

inaccurate/missing locate – Operator located; and

(D)

inaccurate/missing located – Contractor located.

(II)

Analysis of the information in (a) above that allows for the identification of

acute risk parties that have caused multiple pipeline damages in the

preceding 18 months; and

(III)

analysis of the information in (a) above that allows for the identification of

chronic risk parties that have caused multiple pipeline damages over (a)

time period(s) greater than 18 months.

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(e)

Each operator must provide documentation of the deactivation and abandonment

of pipelines to the PSP consistent with rule 11100.

)

analysis of the information in (a) above that allows for the identification of

chronic risk parties that have caused multiple pipeline damages over (a)

time period(s) greater than 18 months.

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(e)

Each operator must provide documentation of the deactivation and abandonment

of pipelines to the PSP consistent with rule 11100.

(f)

The PSP will pursue compliance action against an operator under §

192.614(c)(5) whose excavation damages due to inaccurate or missing locates:

(I)

were found through investigation to be contributory to a pipeline incident;

(II)

were found through investigation to be contributory to a pipeline event

that, in the opinion of the PSP, represented a major threat to public safety;

(III)

were found to represent an excessive risk to the operator’s pipeline by the

analyses required by subparagraphs 11201(d)(II) and (III).

11202.

Direct Sales Pipelines.

Unless otherwise specified in this rule, direct sales pipelines are classified as intrastate

transmission pipelines and subject to these rules and all applicable 49 C.F.R. Part 192

rules, as incorporated.

11203.

Small Operator Systems.

(a)

General requirements.

(I)

Unless otherwise specified in this rule, a small operator system is subject

to these rules and all applicable 49 C.F.R. Part 192 rules, as incorporated.

(II)

Unless otherwise specified in this rule, any operator of a small operator

system may opt into the prescriptive distribution integrity management

provisions of paragraph (h) of this rule via written request to the PSP Chief

or PSP Lead Engineer.

less otherwise specified in this rule, a small operator system is subject

to these rules and all applicable 49 C.F.R. Part 192 rules, as incorporated.

(II)

Unless otherwise specified in this rule, any operator of a small operator

system may opt into the prescriptive distribution integrity management

provisions of paragraph (h) of this rule via written request to the PSP Chief

or PSP Lead Engineer.

(b)

Standards applied to de minimis gas systems.

(I)

Unless otherwise specified in this rule, de minimis gas systems are

exempt from these rules and 49 C.F.R. Part 192 rules, as incorporated.

(II)

System expansion.

(A)

Operators of de minimis gas systems must apply for Commission

approval prior to any system expansion.

(B)

Operators of de minimis gas systems are prohibited from

expanding the system unless proper permits are issued by the

appropriate plumbing inspection authority.

(III)

Leak surveys.

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(A)

De minimis gas systems must be leak surveyed with equipment

using instruments and techniques suitable for detecting fugitive

natural gas, or LPG in gaseous/vapor form, as applicable, once

every two years.

(B)

Records and results of all leak surveys will be kept for the life of the

system.

(IV)

System repairs.

(A)

An operator of a de minimis gas system must repair all pipeline

leaks that represent an existing or probable hazard to persons or

property immediately upon discovery.

(B)

An operator of a de minimis gas system must repair all other

pipeline system leaks within 45 days of discovery.

(C)

All system repairs must be completed by a plumber, gas utility

technician, or utility contractor qualified to install and repair

underground gas systems.

(D)

Prior to any leak repair, the operator of a de minimis gas system

must acquire a plumbing permit issued by the appropriate plumbing

inspection authority

s gas system must repair all other

pipeline system leaks within 45 days of discovery.

(C)

All system repairs must be completed by a plumber, gas utility

technician, or utility contractor qualified to install and repair

underground gas systems.

(D)

Prior to any leak repair, the operator of a de minimis gas system

must acquire a plumbing permit issued by the appropriate plumbing

inspection authority. If a leak has been repaired immediately due to

a public safety hazard, the repair must be permitted after the fact

and will be left exposed for inspection by the appropriate plumbing

inspection authority or a PSP Inspector.

(c)

Standards applied to SSAG systems.

(I)

Any SSAG system is compliant with these rules if the system has been

inspected and passed a system safety inspection within the last five years

by one of the following means:

(A)

inspection by the PSP;

(B)

inspection by the Fire Department or Fire Marshall using NFPA 54

(National Fuel Gas Code), NFPA 101 (Life Safety Code), or a

written equivalent standard; or

(C)

inspection by the plumbing entity using the International Fuel Gas

Code or a written equivalent standard.

(II)

Record of the final, approved inspection of the gas system installation

shall be kept for the life of the system.

(III)

Records of all subsequent inspections shall be maintained and available

for PSP inspection for a minimum of ten years from the date of inspection.

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(d)

Standards applied to LPG systems.

(I)

The PSP will deem any LPG tank – CDLE OPS Inspected to be compliant

with these rules, subject to the following restrictions:

(A)

the tank has passed the CDLE OPS inspection; and

(B)

the tank has been inspected within the last five calendar years.

(II)

Leak surveys and leak pinpointing must use instruments and techniques

suitable for detecting fugitive LPG in gaseous/vapor form.

to LPG systems.

(I)

The PSP will deem any LPG tank – CDLE OPS Inspected to be compliant

with these rules, subject to the following restrictions:

(A)

the tank has passed the CDLE OPS inspection; and

(B)

the tank has been inspected within the last five calendar years.

(II)

Leak surveys and leak pinpointing must use instruments and techniques

suitable for detecting fugitive LPG in gaseous/vapor form.

(e)

Standards applied to Major MMO/LPG systems.

(I)

Major MMO/LPG systems must acquire a PHMSA Operator Identification

Number.

(II)

Major MMO/LPG systems are subject to the P-DIMP of paragraph

11203(h).

(f)

Standards applied to Minor MMO/LPG systems.

(I)

Minor MMO/LPG systems are subject to the P-DIMP of paragraph

11203(h).

(g)

Standards applied to threshold MMO/LPG systems.

(I)

Threshold MMO/LPG systems are subject to the P-DIMP of paragraph

11203(h).

(h)

Prescriptive distribution integrity management program (P-DIMP).

(I)

Operators subject to this rule shall be subject to a P-DIMP consisting of an

evaluation and a plan.

(II)

Operators subject to this rule shall have a P-DIMP evaluation performed

by the PSP at least once every five years; sooner when system history or

PSP inspection indicates a change in any operating condition that

necessitates a new P-DIMP evaluation.

(III)

The P-DIMP shall explicitly consider, prioritize, and rank system risks

based on the following:

(A)

number of affected persons;

(B)

physical system parameters including but not limited to:

(i)

materials;

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(ii)

delivered system pressure, including whether the system is a

low-pressure distribution system; and

(iii)

leak and leak repair history.

(C)

Operational system parameters including, but not limited to:

e following:

(A)

number of affected persons;

(B)

physical system parameters including but not limited to:

(i)

materials;

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(ii)

delivered system pressure, including whether the system is a

low-pressure distribution system; and

(iii)

leak and leak repair history.

(C)

Operational system parameters including, but not limited to:

(i)

compliance history of the current legal operator;

(ii)

system records;

(iii)

availability of appropriate tools and equipment to operate

gas pipeline system;

(iv)

availability of trained and/or qualified personnel to operate

and maintain the system during normal operations; and

(v)

availability of trained and/or qualified personnel to operate

the system during emergencies.

(IV)

All physical and operational parameters that are unknown at the time of

the P-DIMP evaluation shall be considered by the PSP to pose the

maximum public safety risk that is reasonably associated with the

unknown parameter.

(V)

Following a completed P-DIMP evaluation, all operators of a Threshold

MMO/LPG system or Minor MMO/LPG system shall be subject to P-DIMP

unless the operator opts out of a P-DIMP as allowed in subparagraph

11203(h)(VII).

(VI)

The P-DIMP shall prescribe operations and maintenance activities

appropriate to maximize system integrity and minimize the public safety

risk posed by the operation of the system.

11204.

Conversion to Service.

A pipeline previously used in service not subject to 49 C.F.R. Part 192 qualifies for

service subject to 49 C.F.R. Part 192 if the operator prepares and follows a written

procedure addressing the requirements of 49 C.F.R. § 192.14. The operator shall make

its written procedures and applicable records available to PSP Staff upon request.

CUSTOMER-OWNED YARD LINES

11205.

Definitions.

ion to Service.

A pipeline previously used in service not subject to 49 C.F.R. Part 192 qualifies for

service subject to 49 C.F.R. Part 192 if the operator prepares and follows a written

procedure addressing the requirements of 49 C.F.R. § 192.14. The operator shall make

its written procedures and applicable records available to PSP Staff upon request.

CUSTOMER-OWNED YARD LINES

11205.

Definitions.

(a)

“Customer-owned gas line” means the portion of the gas line that extends from

the outlet of the gas meter to the customer’s structure (which is referred to as

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“downstream” from the gas meter because that is the direction of the flow of the

gas).

(b)

“Customer-owned yard line” is a customer-owned gas line in which the gas meter

is located remotely from (i.e., not immediately adjacent to) the structure and at

least a portion of the pipe between the gas meter and the structure is buried. This

definition excludes master meters and fuel lines serving industrial customers

(e.g., power plants).

(c)

“Gas meter” means the meter that measures the transfer of gas from an operator

to a customer.

11206. Division of Responsibility for Maintenance and Repairs.

(a)

The process for determining whether a customer or operator is responsible for

maintenance and repairs of a gas line is to locate the outlet of the gas meter. The

pipe that extends downstream from the outlet of the gas meter is the customer-

owned gas line. The gas meter and the pipe upstream from the meter are owned

by the operator.

(b)

Customers are responsible for maintenance and repairs of customer-owned gas

lines, including without limitation customer-owned gas lines installed on or after

August 14, 1995.

(c)

Operators are responsible for maintenance and repairs of gas meters and all

other pipe upstream from gas meters.

11207.

Operator Duties.

. The gas meter and the pipe upstream from the meter are owned

by the operator.

(b)

Customers are responsible for maintenance and repairs of customer-owned gas

lines, including without limitation customer-owned gas lines installed on or after

August 14, 1995.

(c)

Operators are responsible for maintenance and repairs of gas meters and all

other pipe upstream from gas meters.

11207.

Operator Duties.

(a)

In addition to the requirements outlined in 49 C.F.R. § 192.16, an operator that

distributes natural gas to a customer-owned yard line installed by the operator on

or after March 1, 2024, shall provide written notice to the customer within ninety

days after installation that, at a minimum, informs the customer that the customer

is responsible for maintaining and repairing the customer-owned yard line.

(I)

The operator shall use best efforts to obtain a copy of the written notice

described in paragraph (a) of this rule with the customer’s signature within

90 days after installation of the customer-owned yard line.

(II)

With respect to the copy of the written notice described in paragraph (a) of

this rule that includes the customer’s signature in accordance with

subparagraph (a)(I) of this section, the operator shall:

(A)

provide a copy to the customer for the customer’s records;

(B)

maintain a copy for the operator’s records for the duration of the

lifetime of the customer-owned yard line;

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escribed in paragraph (a) of

this rule that includes the customer’s signature in accordance with

subparagraph (a)(I) of this section, the operator shall:

(A)

provide a copy to the customer for the customer’s records;

(B)

maintain a copy for the operator’s records for the duration of the

lifetime of the customer-owned yard line;

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(C)

provide a copy to a pipeline safety inspector upon request; and

(D)

if the property on which the customer-owned yard line is located

changes ownership, the operator must use best efforts to obtain a

new copy of the written notice described in paragraph (d) of this

rule with the new property owner’s signature from the new property

owner within ninety days after the change of ownership if the

operator is aware of the change.

(III)

If, after best efforts, the operator fails to obtain a copy of the written notice

described in paragraph (a) of this rule with the customer’s signature from

the customer in accordance with subparagraph (a)(I) of this rule, the

operator must either maintain proof of efforts to obtain the customer’s

signature or document the customer’s refusal to provide a signature.

(b)

In addition to the requirements outlined in 49 C.F.R. §§ 192.353 and 192.355,

operators must ensure that service regulator vents and relief vents installed or

reinstalled on or after the effective date of this rule are at least 12 inches above

ground level at the time of installation or reinstallation and located in an area that

is protected from external blockage.

usal to provide a signature.

(b)

In addition to the requirements outlined in 49 C.F.R. §§ 192.353 and 192.355,

operators must ensure that service regulator vents and relief vents installed or

reinstalled on or after the effective date of this rule are at least 12 inches above

ground level at the time of installation or reinstallation and located in an area that

is protected from external blockage.

(c)

In addition to the requirements outlined in 49 C.F.R. § 192.481, a visual

inspection of gas meters and service regulators is required by a qualified

individual no less frequently than every five calendar years with intervals not to

exceed 63 months. The documentation of each inspection shall be recorded and

the operator of the gas meter or service regulator shall retain the documentation

for the lifetime of the gas meter or service regulator.

BEST PRACTICES

11208.

Best Practices.

(a)

These rules are not intended to prohibit or foreclose the use of best practices and

standards accepted in the industry. To the extent any such best practices and/or

standards exist at the adoption of these rules, or subsequently develop, that are

believed to be prohibited by these rules, these rules shall be construed to allow

the use of such best practices and standards.

11209.

Advanced Leak Detection Survey Requirements.

Effective January 1, 2027, in addition to the requirements incorporated by references in

paragraph 11008(b), an operator shall comply with the following subsections.

Operators shall perform all leak detection surveys with the use of advanced leak

detection technology, as identified in subparagraph 11103(b)(II) annual reporting

requirement. In cases where a leak survey cannot be performed in the prescribed

interval, the operator shall submit notification and documentation to the PSP Chief.

raph 11008(b), an operator shall comply with the following subsections.

Operators shall perform all leak detection surveys with the use of advanced leak

detection technology, as identified in subparagraph 11103(b)(II) annual reporting

requirement. In cases where a leak survey cannot be performed in the prescribed

interval, the operator shall submit notification and documentation to the PSP Chief.

(a)

Transmission and gathering pipelines.

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(I)

For transmission and gathering pipelines in Class 1, 2, and 3 locations

outside High Consequence Areas (HCAs), an operator shall perform a

leak detection survey at intervals not exceeding 15 months, but at least

once each calendar year.

(II)

For transmission and gathering pipelines in Class 1, 2, and 3 locations

within HCAs, an operator shall perform a leak detection survey at intervals

not exceeding 7.5 months, but at least twice a calendar year.

(III)

For transmission and gathering pipelines in Class 4 locations, including

Class 4 locations within HCAs, an operator shall perform a leak detection

survey at intervals not exceeding four and half months, but at least four

times each calendar year.

(b)

Distribution pipelines.

(I)

For distribution pipelines inside business districts, operators shall perform

a leak detection survey annually, not to exceed 15 months, but at least

once each calendar year.

(II)

For distribution pipelines outside business districts that are steel pipelines

without cathodic protection, are known to leak based on material, design,

or past operations and maintenance history, or are distributed anode

protected pipelines with a historically deficient reading, operators shall

perform a leak detection survey annually, not to exceed 15 months, but at

least once each calendar year.

(III)

For all other distribution pipelines outside of business districts, operators

shall perform a leak detection survey at intervals not to exceed 39 months,

but at least once every three calendar years

stributed anode

protected pipelines with a historically deficient reading, operators shall

perform a leak detection survey annually, not to exceed 15 months, but at

least once each calendar year.

(III)

For all other distribution pipelines outside of business districts, operators

shall perform a leak detection survey at intervals not to exceed 39 months,

but at least once every three calendar years.

(IV)

All operators classified as MMO or LPG are exempt from this rule.

11210.

Leak Classification and Repair Requirements.

Advanced leak detection technology that is not concentration based is intended to

provide the operator with overall system health information and will provide indications

of leaks. The use of such advanced leak detection technology does not replace the role

of conventional leak detection equipment needed to pinpoint a leak for purposes of

investigation and classification.

(a)

Effective January 1, 2027, each operator shall classify all reported leaks within

48 hours of confirmed discovery. Each classification shall be performed by an

individual with appropriate qualifications.

(I)

Leak classification shall use the following definitions.

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(A)

Grade 1 – A leak that represents an existing or probable hazard to

persons or property, requires immediate repair or continuous action

until the conditions are no longer hazardous.

(B)

Grade 2 – A leak that is recognized as being non-hazardous at the

time of detection, but justified scheduled repair based on probable

future hazard. Grade 2 leaks include:

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(A)

Grade 1 – A leak that represents an existing or probable hazard to

persons or property, requires immediate repair or continuous action

until the conditions are no longer hazardous.

(B)

Grade 2 – A leak that is recognized as being non-hazardous at the

time of detection, but justified scheduled repair based on probable

future hazard. Grade 2 leaks include:

(i)

any leak of LPG, hydrogen gas, or carbon dioxide that does

not qualify as a Grade 1 leak; or

(ii)

any leak that, in the judgement of operating personnel, is of

sufficient magnitude to justify scheduled repair within six

months or less.

(C)

Grade 3 – A leak that is non-hazardous at the time of detection and

is reasonably expected to remain non-hazardous. Grade 3 leaks

include any leak that does not meet the criteria of Grades 1 or 2.

(II)

Any above grade, non-hazardous leak that can be resolved by tightening,

lubrication, or minor adjustment shall not be graded and is beyond the

scope of this rule 11210.

(b)

Effective January 1, 2027, minimum requirements for response to each grade of

leak are as follows:

(I)

a Grade 1 leak requires immediate repair or continuous action until the

conditions are no longer hazardous;

(II)

a Grade 2 leak shall be repaired within 12 months after confirmed

discovery. When the ground is frozen or otherwise inaccessible, the

Grade 2 leak shall be monitored and evaluated at least every 6 months

after confirmed discovery to ensure that the leak will not become a Grade

1 leak prior to repair, and shall be repaired within 12 months after

confirmed discovery; and

(III)

a Grade 3 leak shall be monitored and evaluated at least every 12 months

after confirmed discovery to ensure the leak will not become a Grade 1 or

Grade 2 leak prior to repair or abandonment, as applicable.

(A)

If the pipeline is not scheduled for abandonment within five years of

the confirmed discovery date, the leak shall be repaired within 24

months after confirmed discovery

iscovery; and

(III)

a Grade 3 leak shall be monitored and evaluated at least every 12 months

after confirmed discovery to ensure the leak will not become a Grade 1 or

Grade 2 leak prior to repair or abandonment, as applicable.

(A)

If the pipeline is not scheduled for abandonment within five years of

the confirmed discovery date, the leak shall be repaired within 24

months after confirmed discovery.

(B)

If the pipeline is scheduled for abandonment within five years of the

confirmed discovery date, the operator may monitor and evaluate

the leak at least every 12 months instead of repairing.

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(IV)

A repair can include repair, replacement, or abandonment.

(V)

All operators classified as MMO or LPG shall classify all leaks as Grade 1

and repair immediately.

11211. – 11299.

[Reserved].

SAFETY STANDARDS FOR LIQUEFIED NATURAL GAS (LNG) SYSTEMS

11300.

Standards – General.

An operator shall comply with the safety standards for liquefied natural gas facilities that

are incorporated by reference in paragraph 11008(c).

11301. – 11399.

[Reserved].

SAFETY STANDARDS FOR PIPELINE OPERATOR DRUG AND ALCOHOL

PROGRAMS

11400.

Standards – General.

An operator shall comply with the standards for pipeline operator drug and alcohol

programs that are incorporated by reference in paragraph 11008(d).

11401. – 11499.

[Reserved].

RULE VIOLATIONS, CIVIL PENALTIES, AND COMPLIANCE ACTIONS

11500.

Violations - General.

(a)

Violations of these rules are determined by inspections, audits, and/or testing

performed under rule 11013 that indicate a compliance deficiency or deficiencies

with respect to rule requirement(s).

(b)

Violations will be examined by the PSP Chief to determine the impact category

resulting from the violation: no immediate safety impact, incident, public

endangerment, operator endangerment, or a loss/reduction of pipeline integrity.

rmined by inspections, audits, and/or testing

performed under rule 11013 that indicate a compliance deficiency or deficiencies

with respect to rule requirement(s).

(b)

Violations will be examined by the PSP Chief to determine the impact category

resulting from the violation: no immediate safety impact, incident, public

endangerment, operator endangerment, or a loss/reduction of pipeline integrity.

(c)

Alleged rule violations are deemed “probable” until completion of an appropriate

enforcement action, including any Commission hearing or proceeding.

(d)

The PSP Chief or PSP Staff may use the determination in paragraph (a) as a

prima facie basis for opening a complaint proceeding pursuant to paragraph

1302(g) of the Commission’s Rules of Practice and Procedure.

11501.

Violations – Civil Penalties.

(a)

This rule shall apply to violation(s) that would have otherwise been discovered by

a prudent operator in the normal course of business. This is the lowest degree of

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culpability for which operators may be penalized and does not limit the

Commission from penalizing operators for higher degrees of culpability.

(b)

An operator who violates these rules or an order of the Commission issued under

these rules may be subject to civil penalties as follows:

(I)

civil penalties shall not exceed $200,000 per instance of violation;

(II)

each day of a continuing violation constitutes a separate instance of

violation; and

(III)

in the case of a group or series of related violations, the aggregate amount

of such penalties shall not exceed $2,000,000.

(c)

Civil penalties – general. The PSP Chief may propose that the Commission

assess civil penalties against an operator following a PSP inspection and/or

investigation that has established specific pipeline safety rule violation(s) and a

time-dependent or time-independent nature of the violations(s).

series of related violations, the aggregate amount

of such penalties shall not exceed $2,000,000.

(c)

Civil penalties – general. The PSP Chief may propose that the Commission

assess civil penalties against an operator following a PSP inspection and/or

investigation that has established specific pipeline safety rule violation(s) and a

time-dependent or time-independent nature of the violations(s).

(d)

Civil penalties – calculation. To provide consistency and specificity, civil penalties

shall be calculated through the formulaic method as follows.

(I)

Time-dependent/history based activity violations.

(A)

Violations determined by an action or activity not performed or

failure to be performed in accordance with rule or procedure:

(i)

the penalty is assessed by individual action or activity

required by rule or procedure;

(ii)

the penalty amount is calculated by the equation:

B x t x Fph x Fhh x Fi ,

where:

B = Base penalty of $1 per day for the activity associated with the

violation

t = Timeframe of non-compliance, in days

Fph = Pertinent/related system history factor, as determined in the Time-Dependent

Violation Impact Factor Table

Fhh = Hazardous history factor, as determined in the Time-Dependent Violation Impact

Factor Table

Fi = Incident history factor, as determined in the Time-Dependent Violation

Impact Factor Table

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(B)

Time-dependent violation impact factor table:

(II)

Time-independent/outcome-based violations.

(A)

Violations determined by a failure to follow or inadequate/missing

operator procedures:

ependent Violation Impact

Factor Table

Fi = Incident history factor, as determined in the Time-Dependent Violation

Impact Factor Table

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(B)

Time-dependent violation impact factor table:

(II)

Time-independent/outcome-based violations.

(A)

Violations determined by a failure to follow or inadequate/missing

operator procedures:

(i)

the penalty is assessed by individual or group actions or

activities required by rule or procedure;

(ii)

the penalty amount is calculated by the equation:

B x Fimpact, where

B = $5,000 base penalty per instance of violation

Fimpact = Time-independent Impact Factor as determined in the Time-Independent

Violation Impact Factor Table

Time-Dependent Violation Impact Factor Table

FACTO

THRESHOLD

Factor

multiplier if

threshold

NOT met

Factor

multiplier if

threshold met

Fph

The violation was associated with

other inspection findings that

indicated related effects on pipeline

system integrity (e.g., leaks,

corrosion, PHMSA Advisory Bulletin,

missing records, etc.)

Fhh

The violation was associated with

other inspection findings that

indicated related effects on public

safety (e.g., hazardous leaks, safety-

critical activity, safety-related

condition, etc.)

The violation was associated with

other inspection findings that

indicated the violation contributed to

an Incident

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(B)

Violations determined by an unqualified worker performing

operations, maintenance, or construction tasks:

(i)

the penalty is assessed per worker and specific individual

qualification required by rule or procedure; and

(ii)

the penalty amount is calculated by the equation:

B x Fimpact, where

B = $5,000 base penalty per instance of violation

Fimpact = Time-independent Impact Factor as determined in the Time-Independent

Violation Impact Factor Table

(C)

Rule 11201 violations:

ance, or construction tasks:

(i)

the penalty is assessed per worker and specific individual

qualification required by rule or procedure; and

(ii)

the penalty amount is calculated by the equation:

B x Fimpact, where

B = $5,000 base penalty per instance of violation

Fimpact = Time-independent Impact Factor as determined in the Time-Independent

Violation Impact Factor Table

(C)

Rule 11201 violations:

(i)

the penalty is assessed per applicable paragraph of rule

11201;

(ii)

the penalty amount is calculated by the equation:

B x Fimpact, where:

B = $5,000 base penalty per instance of violation

Fimpact = Time-independent Impact Factor as determined in the Time-Independent

Violation Impact Factor Table

(D)

Missing or incomplete records:

(i)

the penalty is assessed by grouped action or activity

required by rule or procedure;

(ii)

the penalty is assessed by applicable inspection focus, i.e.,

district operating area, operating unit, or total operator

system;

(iii)

the penalty is calculated based on the estimated volume of

missing or incomplete records:

(1)

Gross Incompletion (Record incompletion/absence ≥

10 percent for complete record absence for a required

code segment) = $10,000/code/segment/calendar

year;

(2)

Major Incompletion (Record incompletion/absence ≥ 5

percent and < 10 percent for a required code

segment) = $5,000/code/segment/calendar year; and

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plete records:

(1)

Gross Incompletion (Record incompletion/absence ≥

10 percent for complete record absence for a required

code segment) = $10,000/code/segment/calendar

year;

(2)

Major Incompletion (Record incompletion/absence ≥ 5

percent and < 10 percent for a required code

segment) = $5,000/code/segment/calendar year; and

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(3)

Significant Incompletion (Record

incompletion/absence ≥ 2 percent and < 5 percent for

a required code segment) =

$2,500/code/segment/calendar year.

(E)

Time-independent violation impact factor table:

Time-Independent Violation Impact Factor Table

THRESHOLD

Factor

multiplier if

threshold

met

The violation resulted in no immediate

safety impact

The violation resulted in operator

endangerment; operator property loss

> $10,000; or emergency (versus

precautionary) actions by the operator

necessary to protect system integrity

The violation resulted in public

endangerment; non-operator property

loss > $10,000; or a loss of pipeline

integrity

The violation resulted in an Incident

(e)

Multiple calculated penalties will be summed to compute a final civil penalty.

(f)

The PSP Chief may propose to the Commission the assessment of a revised

final civil penalty lower than the summed calculated penalties based on the

operator’s documented and verifiable efforts to mitigate the violations(s) and

improve overall system safety and integrity.

(g)

The calculated and final civil penalty amounts shall be illustrated in the NPV to

the operator.

(h)

Nothing in this rule shall prohibit the Commission from the calculation and/or

assessment of a new final civil penalty during a formal hearing process.

nalties based on the

operator’s documented and verifiable efforts to mitigate the violations(s) and

improve overall system safety and integrity.

(g)

The calculated and final civil penalty amounts shall be illustrated in the NPV to

the operator.

(h)

Nothing in this rule shall prohibit the Commission from the calculation and/or

assessment of a new final civil penalty during a formal hearing process.

(i)

The Commission may assess doubled or tripled civil penalties against any public

utility, as provided by § 40-7-113.5(3), C.R.S., § 40-7-113.5(4), C.R.S., and this

rule.

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(I)

The Commission may assess any public utility a civil penalty containing

doubled penalties only if:

(A)

the public utility has admitted liability by paying the proposed final

civil penalty for, or has been adjudicated by the Commission in an

administratively final written decision to be liable for, engaging in

prior conduct that constituted an intentional violation of a statute in

Articles 1 to 7 and 15 of Title 40, C.R.S., a Commission rule, or a

Commission order;

(B)

the conduct for which doubled civil penalties are sought violates the

same statute, rule, or order as conduct for which the public utility

has either admitted liability by paying the civil penalty assessment,

or been adjudicated by the Commission in an administratively final

written decision to be liable; and

(C)

the conduct for which doubled civil penalties are sought occurred

within one year after conduct for which the public utility has either

admitted liability by paying the civil penalty assessment, or been

adjudicated by the Commission in an administratively final written

decision to be liable

or been adjudicated by the Commission in an administratively final

written decision to be liable; and

(C)

the conduct for which doubled civil penalties are sought occurred

within one year after conduct for which the public utility has either

admitted liability by paying the civil penalty assessment, or been

adjudicated by the Commission in an administratively final written

decision to be liable.

(II)

The Commission may assess any public utility a civil penalty containing

tripled penalties only if:

(A)

the public utility has admitted liability by paying the proposed final

civil penalty for, or has been adjudicated by the Commission in an

administratively final written decision to be liable for, engaging in

prior conduct that constituted two or more intentional violations of a

statute in Articles 1 to 7 and 15 of Title 40, C.R.S., a Commission

rule, or a Commission order;

(B)

the conduct for which tripled civil penalties are sought violates the

same statute, rule, or order as conduct for which the public utility

has either admitted liability by paying the civil penalty assessment,

or conduct for which the public utility has been adjudicated by the

Commission in an administratively final written decision to be liable,

in at least two prior instances; and

(C)

the conduct for which tripled civil penalties are sought occurred

within one year after the two most recent instances of conduct for

which the public utility has either admitted liability by paying the civil

penalty assessment, or been adjudicated by the Commission in an

administratively final written decision to be liable.

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11502.

Compliance Action - General.

(a)

Initiation. Upon discovery of a probable violation of these rules, the PSP Chief

will initiate a compliance action intended to remediate and prevent recurrence of

the violation.

sessment, or been adjudicated by the Commission in an

administratively final written decision to be liable.

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11502.

Compliance Action - General.

(a)

Initiation. Upon discovery of a probable violation of these rules, the PSP Chief

will initiate a compliance action intended to remediate and prevent recurrence of

the violation.

(b)

Intent. A compliance action is intended to minimize the realized or potential

impacts of the violation on public safety and/or the integrity of the pipeline system

or LNG facility and will be consistent with the intent of § 40-7-117, C.R.S. After

the Commission issues a notice, an operator shall have the opportunity to

respond and to cure any violation of these rules.

(c)

Structure. All compliance action notices to a pipeline operator must include:

(I)

a statement of the law, rule(s), or order(s) that the operator is alleged to

have violated; and

(II)

a statement of the facts upon which the determination of violation is based

and recommendations on actions that may be taken by the operator to

remedy further noncompliance.

(d)

Service of process. Service of process shall be undertaken pursuant to rule 1205

of the Commission’s Rules of Practice and Procedure and § 40-6-108, C.R.S.

11503.

Compliance Action – Warning Notice.

In the instance of a probable violation of these rules that has no previous enforcement

history and poses a low risk to public safety and/or pipeline/LNG facility integrity, as

determined by current regulation, industry standard, or other relevant objective technical

standard, or if the operator provides advance notice, the PSP Chief may issue a

warning notice to an operator

tion – Warning Notice.

In the instance of a probable violation of these rules that has no previous enforcement

history and poses a low risk to public safety and/or pipeline/LNG facility integrity, as

determined by current regulation, industry standard, or other relevant objective technical

standard, or if the operator provides advance notice, the PSP Chief may issue a

warning notice to an operator. The warning notice will advise the operator of the

probable violation, require the operator to correct the probable violation or be subject to

further enforcement action under these rules, and may require a formal written response

from the operator on their corrective action plan so that a follow-up inspection can be

scheduled.

11504.

Notice of Probable Violation (NPV).

(a)

In the instance of a probable violation of these rules that has a previous

enforcement history or poses a moderate to severe risk to public safety or

pipeline or LNG facility integrity, as determined by current regulation, industry

standard, or other relevant objective technical standard, the PSP Chief may issue

a NPV to an operator. The NPV will advise the operator of the probable violation

and include the following sections:

(I)

a statement of inspection findings that incorporates the requirements of

rule 11502, above;

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(II)

a statement of the regulatory interpretation upon which the determination

of probable violation is based;

(III)

a civil penalty calculation using rule 11501 stating separately for each

probable violation the maximum penalty amount provided and a total

penalty;

(IV)

the PSP Chief’s civil penalty assessment evaluation consistent with § 40-

7-117, C.R.S. that includes a conclusion for or against assessment of the

civil penalty in whole or in part;

(V)

a final recommended civil penalty assessment;

(VI)

as appropriate, the NPV will offer the operator a proposed alternative

enforcement in lieu of the civil penalties, in whole or in part

d and a total

penalty;

(IV)

the PSP Chief’s civil penalty assessment evaluation consistent with § 40-

7-117, C.R.S. that includes a conclusion for or against assessment of the

civil penalty in whole or in part;

(V)

a final recommended civil penalty assessment;

(VI)

as appropriate, the NPV will offer the operator a proposed alternative

enforcement in lieu of the civil penalties, in whole or in part. The proposed

alternative enforcement will describe the process in sufficient detail to

explain how it will provide for the improvement of public safety;

(VII)

as appropriate, the NPV will include a compliance directive that prescribes

specific actions to be taken by the operator within a specific timeframe to

correct the violation; and

(VIII) a description of the operator’s response options.

(b)

The NPV shall be filed in a new proceeding and shall serve as notice of the

alleged probable violation and potential actions to be taken by the Commission.

(c)

Within 30 days after receipt of a NPV issued pursuant to the rule, an operator

shall file in the proceeding its response with one of the following options.

(I)

The operator may admit the NPV through the following filings and actions:

(A)

the operator shall pay any proposed final civil penalty in full; and

(B)

the operator shall agree to any proposed compliance directive.

(II)

The operator may request the Commission consider an offer in

compromise to the NPV through the following filings and actions:

(A)

the operator may request reconsideration, reissuance, or dismissal

of the initial NPV through submittal of a written explanation,

information, or other material in response to the allegations

contained in the NPV; in objection to the proposed compliance

directive; or in mitigation of the proposed final civil penalty; or

(B)

the operator and the PSP Chief may jointly file a stipulation and

settlement agreement pursuant to rule 11508, resolving the

allegations in the NPV for the Commission’s consideration.

written explanation,

information, or other material in response to the allegations

contained in the NPV; in objection to the proposed compliance

directive; or in mitigation of the proposed final civil penalty; or

(B)

the operator and the PSP Chief may jointly file a stipulation and

settlement agreement pursuant to rule 11508, resolving the

allegations in the NPV for the Commission’s consideration.

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(III)

The operator may oppose the NPV, or any part thereof. The operator shall

file its response opposing the allegations in the NPV in the proceeding and

provide all relevant information it finds addresses the issues raised. If an

operator opposes any alleged violation in the NPV, the matter shall be set

for hearing. When applicable and appropriate, such appeal will stay the

duration of the noncompliance for purposes of any penalty calculation

contingent upon interim operator actions to cure the alleged violation(s).

(d)

If the operator fails to respond as provided in this rule within 30 days of the NPV,

the NPV shall be deemed opposed by the operator and shall be set for hearing

as prescribed by subparagraph (c)(III) above.

(e)

If a violator does not remit the assessed penalty or the lesser amount agreed

upon pursuant to this rule, the Commission may recover the amount due plus

court costs in a civil action in any court of competent jurisdiction.

s provided in this rule within 30 days of the NPV,

the NPV shall be deemed opposed by the operator and shall be set for hearing

as prescribed by subparagraph (c)(III) above.

(e)

If a violator does not remit the assessed penalty or the lesser amount agreed

upon pursuant to this rule, the Commission may recover the amount due plus

court costs in a civil action in any court of competent jurisdiction.

(f)

Any civil penalty authorized by this rule may be reduced by the Commission

based on consideration of factors and metrics, as follows:

(I)

an evaluation of the severity of the violation, in terms of its actual or

potential effects on the public safety or pipeline system integrity;

(II)

the extent to which the violation and any underlying conditions that may

have contributed to the likelihood or severity of the violation have been

remedied;

(III)

the extent to which the violator agrees to spend, in lieu of the payment of

part of the civil penalty, a specified amount on Commission-approved

measures to reduce the overall risk to the pipeline system safety or

integrity; except that the amount of the penalty payable to the Commission

shall be no less than $5,000; and

(IV)

whether or not the violation was self-reported by the operator.

(g)

The remedy provided in this rule is an addition to any other remedies available to

the Commission under the constitution or laws of the state or of the United

States.

11505.

Request for Amendment (RFA).

(a) If an inspection, audit, or investigation reveals that an operator’s plans or

procedures required by these rules may be insufficient to ensure the

compliant operation of a pipeline or LNG facility, the PSP Chief may issue an

RFA.

an addition to any other remedies available to

the Commission under the constitution or laws of the state or of the United

States.

11505.

Request for Amendment (RFA).

(a) If an inspection, audit, or investigation reveals that an operator’s plans or

procedures required by these rules may be insufficient to ensure the

compliant operation of a pipeline or LNG facility, the PSP Chief may issue an

RFA.

(b)

The RFA shall serve as notice from the Commission of potential inadequacies

and serve to facilitate and expedite necessary plan or procedure revision(s) and

implementation so that pipeline operation, maintenance, training, or emergency

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response is not compromised. The RFA shall specify the potential inadequacies

and may:

(I)

specify a proposed timeline for revised plan implementation based on the

impact to pipeline operations; and

(II)

provide an opportunity for response.

11506.

Notice of Amendment (NOA).

(a)

If an inspection, audit, or investigation reveals that an operator’s plans or

procedures required by these rules are inadequate to ensure the safe operation

of a pipeline or LNG facility, the PSP Chief may issue a NOA.

(b)

The NOA shall be filed in a new proceeding and shall serve as notice from the

Commission of the alleged inadequacies and to facilitate and expedite plan or

procedure revision and implementation so that public safety is not compromised.

The NOA shall:

(I)

specify the alleged inadequacies and the proposed action(s) for revision of

the plans and procedures;

(II)

specify a proposed timeline for revised plan/procedure implementation

based on the impact to public safety; and

(III)

provide an opportunity for response.

and to facilitate and expedite plan or

procedure revision and implementation so that public safety is not compromised.

The NOA shall:

(I)

specify the alleged inadequacies and the proposed action(s) for revision of

the plans and procedures;

(II)

specify a proposed timeline for revised plan/procedure implementation

based on the impact to public safety; and

(III)

provide an opportunity for response.

(c)

Within 30 days after receipt of a NOA issued pursuant to the rule, unless a longer

period is otherwise specified in the NOA or a different time period is agreed to

mutually, an operator shall file in the proceeding its response with one of the

following options.

(I)

The operator may admit the NOA through the following filings and actions:

(A)

the operator shall pay any proposed final civil penalty in full; and

(B)

the operator shall agree to any proposed compliance directive.

(II)

The operator may request the Commission consider an offer in

compromise to the NOA through the following filings and actions:

(A)

the operator may request reconsideration and reissuance of the

initial NOA through submittal of a written explanation, information,

or other material in response to the allegations contained in the

NOA; in objection to the proposed compliance directive; or in

mitigation of the proposed final civil penalty; or

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(B)

the operator and the PSP Chief may jointly file a stipulation and

settlement agreement pursuant to rule 11507, resolving the

allegations in the NOA for the Commission’s consideration.

(III)

The operator may oppose the NOA, or any part thereof. The operator shall

file its response opposing the allegations in the NOA in the proceeding

and provide all relevant information it finds addresses the issues raised. If

an operator opposes any alleged violation in the NOA, the matter shall be

set for hearing.

11507, resolving the

allegations in the NOA for the Commission’s consideration.

(III)

The operator may oppose the NOA, or any part thereof. The operator shall

file its response opposing the allegations in the NOA in the proceeding

and provide all relevant information it finds addresses the issues raised. If

an operator opposes any alleged violation in the NOA, the matter shall be

set for hearing.

(d)

If the operator fails to respond as provided in this rule within 30 days of the NOA,

the NOA shall be deemed opposed by the operator and shall be set for hearing

as prescribed by subparagraph (c)(III) above.

11507.

Compliance Action – Hazardous Facilities Order (HFO).

(a)

If an inspection, audit, investigation, or test reveals that the continued operation

of a pipeline or LNG facility may pose a severe and imminent risk to public

safety, as determined by current regulation, industry standard, or other relevant

objective technical standard, the PSP Chief may consider the pipeline or LNG

facility to be a hazardous facility and file a formal complaint with the Commission

against the operator of the facility. The complaint shall allege facts sufficient to

establish the existence of a hazardous facility and to support an HFO issued

upon conclusion of a Commission proceeding, or, if justified, a summary HFO

pursuant to paragraph (i) of this rule.

(b)

A formal complaint by PSP staff shall be issued, and a hearing shall be

conducted in accordance with the Commission’s Rules of Practice and

Procedure and Article 6 of Title 40, C.R.S.

(c)

Except as provided in paragraph (i) of this rule, if the Commission finds, after

hearing, that a pipeline facility or a LNG facility is hazardous to life or property,

the Commission shall issue an order directing the operator to take corrective

action. Corrective action may include, without limitation, suspension or restriction

of the use of the pipeline facility or LNG facility, physical inspection, testing,

repair, or replacement.

of this rule, if the Commission finds, after

hearing, that a pipeline facility or a LNG facility is hazardous to life or property,

the Commission shall issue an order directing the operator to take corrective

action. Corrective action may include, without limitation, suspension or restriction

of the use of the pipeline facility or LNG facility, physical inspection, testing,

repair, or replacement.

(d)

In making a determination that a pipeline facility or a LNG facility is hazardous to

life or property, the following shall be considered, as appropriate:

(I)

the characteristics of the pipe used in the pipeline facility or the LNG

facility involved, including (without limitation) its age; manufacturer;

physical properties, including its resistance to corrosion and deterioration;

and the method of its manufacture, construction or assembly;

(II)

the nature of the gas transported by the pipeline facility or the LNG facility,

including its corrosive and deteriorative qualities; the sequence in which

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the gas is transported; and the pressure required for transportation of the

gas;

(III)

the characteristics of the areas in which the pipeline facility or the LNG

facility is located, in particular the climatic and geotechnical or geologic

conditions associated with the areas, the population, the population

density, and the community growth patterns of the areas;

(IV)

any recommendation of the NTSB issued in connection with any

investigation conducted by that Board; and

(V)

such other factors as may be relevant.

(e)

A Commission decision finding that a pipeline facility or a LNG facility is a

hazardous facility shall contain a description of the corrective action required of

the operator and the date by which the operator shall complete the ordered

corrective action.

(f)

The Commission shall dismiss the complaint if it determines that the pipeline

facility or the LNG facility is not hazardous to life or property.

mmission decision finding that a pipeline facility or a LNG facility is a

hazardous facility shall contain a description of the corrective action required of

the operator and the date by which the operator shall complete the ordered

corrective action.

(f)

The Commission shall dismiss the complaint if it determines that the pipeline

facility or the LNG facility is not hazardous to life or property.

(g)

Upon a showing that the ordered corrective action has been completed and has

eliminated the condition(s) that made a pipeline facility or a LNG facility a severe

and imminent risk to public safety, the Commission shall issue an order of

satisfaction. Prior to issuing an order of satisfaction, the Commission may hold a

hearing to determine whether the operator has completed the corrective action

and whether the corrective action has eliminated the conditions(s) that made the

pipeline facility or the LNG facility hazardous to life or property. The order of

satisfaction shall be issued in the complaint docket in which the hazardous

facilities order was entered.

(h)

The Commission may bring a formal complaint alleging the existence of a

hazardous facility supporting the issuance of an HFO and an NPV in the same

proceeding, but is not required to do so.

(i)

If the Commission determines that the delay inherent in holding a hearing may

result in, and significantly increases the likelihood of, serious harm to life or

property, the Commission may issue an expedited or summary HFO before

holding a hearing. The provisions of paragraph (b) of this rule shall apply to a

hearing held pursuant to this paragraph. The purpose of a hearing held pursuant

to this paragraph is to determine whether the summary HFO should remain in

effect, should be amended, or should be rescinded. The summary HFO shall

include the following:

(I)

the findings that support the determination that a summary HFO is

appropriate;

(II)

the corrective or remedial actions required of the operator; and

ring held pursuant to this paragraph. The purpose of a hearing held pursuant

to this paragraph is to determine whether the summary HFO should remain in

effect, should be amended, or should be rescinded. The summary HFO shall

include the following:

(I)

the findings that support the determination that a summary HFO is

appropriate;

(II)

the corrective or remedial actions required of the operator; and

CODE OF COLORADO REGULATIONS

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Public Utilities Commission

(III)

a statement informing the operator of its right to a hearing, upon request,

as soon as practicable after issuance of the order.

11508.

Consent Stipulations.

(a)

If a matter has been set for hearing at any time before the issuance of a decision

by the Commission, the PSP Chief and the operator may agree to dispose of the

matter by a consent stipulation. The consent stipulation shall be submitted to the

Commission for approval or rejection.

(b)

A consent stipulation executed under this rule shall include the following:

(I)

an admission by the operator of facts;

(II)

an express waiver by the operator of further procedural steps, including

(without limitation) its right to a hearing; its right to seek judicial review, or

otherwise to challenge or to contest the validity of the consent stipulation;

and its right to seek judicial review of the Commission order accepting the

consent stipulation;

(III)

an acknowledgment by the operator that the NPV may be used to

construe the terms of the consent stipulation; and

(IV)

a statement of the actions that the operator will take and the date by which

such actions shall be completed.

e to challenge or to contest the validity of the consent stipulation;

and its right to seek judicial review of the Commission order accepting the

consent stipulation;

(III)

an acknowledgment by the operator that the NPV may be used to

construe the terms of the consent stipulation; and

(IV)

a statement of the actions that the operator will take and the date by which

such actions shall be completed.

(c)

As appropriate, a consent stipulation executed under this rule may include a civil

penalty.

11509.

Subpoenas.

The Commission and Administrative Law Judge, or the Director may issue a subpoena

in accordance with rule 1406 of the Commission’s Rules of Practice and Procedure.

11510.

Injunctive Relief.

The Commission may request that the Attorney General bring an action in an

appropriate district court for injunctive or other relief as provided in Article 7 of Title 40,

C.R.S. whenever the Commission is of the opinion that an operator has engaged in, is

engaging in, is about to engage in, or willfully permits any act or practice that

constitutes, a violation of 49 U.S.C. §§ 60101 et seq., these rules, or an order of the

Commission.

11511. – 11999.

[Reserved].

GLOSSARY OF ACRONYMS

C.F.R. - Code of Federal Regulations

CODE OF COLORADO REGULATIONS

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Public Utilities Commission

HFO - Hazardous Facilities Order

LP - Liquid Petroleum

LNG - Liquefied Natural Gas

LPG - Liquid Petroleum Gas

MMO -

Master Meter Operator

NFPA -

National Fire Protection Association

NOA -

Notice of Amendment

NPV - Notice of Probable Violation

NRC - National Response Center

P-DIMP - Prescriptive Distribution Integrity Management Program

PSP - Pipeline Safety Program (of the Colorado PUC)

PHMSA - U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety

Administration

RFA - Request for Amendment

RFI - Request for Information

SSAG -

Single Structure Above Ground (gas pipeline system)

U.S.C. - United States Code

CODE OF COLORADO REGULATIONS

4 CCR 723-11

Public Utilities Commission

ion Integrity Management Program

PSP - Pipeline Safety Program (of the Colorado PUC)

PHMSA - U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety

Administration

RFA - Request for Amendment

RFI - Request for Information

SSAG -

Single Structure Above Ground (gas pipeline system)

U.S.C. - United States Code

CODE OF COLORADO REGULATIONS

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Public Utilities Commission

Editor’s Notes

History

New rule eff. 03/17/2021.

Rules 11000.(a), 11001, 11008, 11010.(c), 11011.(d), 11012.(b), 11013, 11100,

11101.(d), 11103, 11201, 11203.(e)-(g), 11500.(b), 11501.(b),

11501.(d)(II)(D)(iii), 11503, 11504.(c)(II)(B), 11504(e)-(g), 11507.(a)-(c) eff.

05/30/2024.

Rules 11001 (h)-(ggg), 11008, 11205-11208 eff. 03/02/2025.

Rules 11001, 11008(b), 11008(e), 11009, 11012(b), 11100(c), 11100(e)(I)(I)-(K),

11101(b)(III)-(IV), 11101(b)(VI), 11102(b)(I), 11102(b)(III)(G)-(H), 11103(b)(II),

11201(b)-(d), 11203(b)(IV)(A), 11209-11211 emer. rules eff. 10/31/2025.

Rules 11001 (a)-(b), 11100(c), 11100(e), 11502(b), 11201(b), 11209-11210 eff.

05/30/2026.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.