# NORTHWEST PIPELINE LLC — Notice of Probable Violation

**Citation:** CPF 520071001  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2007-01-29

CLOSED notice of probable violation citing 192.905(a), 192.905(b), 192.907(a), 192.907(b), 192.909(a), 192.911(k), 192.911(m), 192.917(b), 192.917(e)(4), 192.921(b), 192.921(d), 192.925(b), 192.925(b)(1), 192.925(b)(1)(ii), 192.925(b)(2), 192.925(b)(3), 192.925(b)(3)(iii), 192.925(b)(4), 192.927(a), 192.935(a), 192.935(c), 192.937(b).

## Document text

Notice of Probable Violation involving NORTHWEST PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(b),  192.907(a),  192.907(b),  192.909(a),  192.911(k),  192.911(m),  192.917(b),  192.917(e)(4),  192.921(b),  192.921(d),  192.925(b),  192.925(b)(1),  192.925(b)(1)(ii),  192.925(b)(2),  192.925(b)(3),  192.925(b)(3)(iii),  192.925(b)(4),  192.927(a),  192.935(a),  192.935(c),  192.937(b). The case was opened on 2007-01-29 and is reported as closed as of 2012-07-09. Proposed civil penalty: $351,000. Assessed civil penalty: $306,000. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520071001_ notice letter_01292007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_%20notice%20letter_01292007.pdf

520071001_ notice letter_01292007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_%20notice%20letter_01292007_text.pdf

520071001_closure letter_07092012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_closure%20letter_07092012.pdf

520071001_closure letter_07092012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_closure%20letter_07092012_text.pdf

520071001_Final Order_05022011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Final%20Order_05022011.pdf

520071001_Final Order_05022011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Final%20Order_05022011_text.pdf

520071001_Operator_Response_and_Requesting_Hearing_03012007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Operator_Response_and_Requesting_Hearing_03012007.pdf

520071001_Final Order_05022011_text.pdf

MAY 02 2011
Mr. Randy Barnard
President
Williams Gas Pipeline
The Williams Companies, Inc.
2800 Post Oak Boulevard
Houston, TX 77056
RE: CPF No. 5-2007-1001
Dear Mr. Barnard:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $306,000, and specifies actions that need to be
taken by Williams Gas Pipeline to comply with the federal pipeline safety regulations. When the
civil penalty has been paid and the terms of the compliance order completed, as determined by
the Director, Western Region, this enforcement action will be closed. Service of the Final Order
by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49
C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Jeffrey D. Wiese
Associate Administrator
for Pipeline Safety
Enclosure
cc: Mr. Chris Hoidal, Director, Western Region, OPS
Ms. Teresa Silcox Torrey, Senior Counsel, Williams Gas Pipeline
296 Chipeta Way, Salt Lake City, UT 84108
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
_________________________________________
In the Matter of )
Williams Gas Pipeline, ) CPF No. 5-2007-1001
a division of The Williams Companies, Inc., )
)
)
)
Respondent. )
_________________________________________ )
FINAL ORDER
On March 13-17 and March 27-30, 2006, pursuant to 49 U.S.C. § 60117, a representative of the
Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety
(OPS), conducted an on-site pipeline safety inspection of the facilities and records of Williams
Gas Pipeline’s Integrity Management Program (IMP) at its offices in Salt Lake City, Utah.
Williams Gas Pipeline (Williams or Respondent) is a division of The Williams Companies, Inc.,
a global energy company that transports approximately 12 percent of the natural gas consumed in
(1) Northwest Pipeline, with approximately 4,000 miles of pipeline running from Canada to the
Pacific Northwest; (2) Transco Pipeline, with approximately 12,800 miles of pipeline running
the United States.1 The inspection covered three gas transmission systems operated by Williams:
from Texas into the Southeast and Northeast; and (3) Gulfstream Pipeline, with approximately
700 miles of pipeline running from Alabama across the Gulf of Mexico to Florida.
As a result of the inspection, the Director, Western Region, OPS (Director), issued to
Respondent, by letter dated January 29, 2007, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that Respondent committed certain violations of 49 C.F.R. Part 192 and
assessing a civil penalty of $351,000 for the alleged violations. The Notice also proposed that
Respondent be required to take certain measures to correct the alleged violations. It also
proposed finding that Respondent had committed certain other probable violations of 49 C.F.R.
Part 192 and warning Respondent to take appropriate corrective action or be subject to future
enforcement action.
1 The Williams Companies’ website (http://www.williams.com/gas_pipeline/) (last accessed 3/15/11).



2
Williams responded to the Notice by letter dated, March 1, 2007 (Response). Respondent
contested several allegations, offered information and exhibits in support of its position, and
requested mitigation of the proposed penalty. Williams also raised a legal challenge that
PHMSA did not have authority, under the Pipeline Safety Improvement Act of 2002 (PSIA) or
the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES), at the time of
the alleged violations to issue civil penalties or compliance orders in gas integrity management
cases. Respondent argued that the Notice constituted an illegal retroactive application of PSIA
and PIPES not expressly authorized or intended by Congress.
2
Williams requested a hearing, which was subsequently held on May 23, 2007, in Denver,
Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. After the
hearing, Respondent provided a post-hearing submission dated June 21, 2007 (Closing).
Authority of PHMSA to Enforce Integrity Management Regulations
PHMSA to act under § 60109(a)(2) to order an operator to revise its IMP with a Notice of
Amendment type of enforcement action (amend the program plans and procedures). Williams
further argued that the statute precludes or does not give PHMSA the authority to act under any
As a preliminary matter, Respondent argued that 49 U.S.C. § 60109(c)(9)(A)(iii)3 only permits
other section of Chapter 601 to enforce integrity management program regulations by issuing
compliance orders and civil penalties. Respondent also argued that Congress provided operators
a four-year period to go from an IMP framework to a fully thought out, robust IMP.
With the enactment of the PSIA, the U.S. Congress directed the Department of Transportation,
PHMSA, to establish and issue regulations detailing standards for the implementation of an
integrity management program. The PIPES Act of 2006 codified the integrity management
program.
The authority set forth in §§ 60119 and 60122 to enforce pipeline safety standards, laws and
regulations through compliance orders and civil penalties has been codified since 1979 and
nothing in PSIA or the PIPES Act affected this authority.
Any suggestion that, prior to the PIPES Act, section 60109(c)(9)(A)(iii) limited the agency’s
authority with respect to operator conduct and to only require an operator to amend an
inadequate or noncompliant integrity management program is therefore incorrect.
Considering the authority established in §§ 60118 and 60122; the legislative history of both
PSIA of 2002 and PIPES Act of 2006; and the legal issues presented, I find that PHMSA had the
authority and did properly exercise the full spectrum of enforcement tools upon a determination
that a risk analysis or integrity management program is inadequate or noncompliant.
2 Response, at 2-3.
3 Subsection 60109(c)(9)(A)(iii) states: “If the Secretary determines that a risk analysis or integrity management
program does not comply with the requirements of this subsection or regulations issued as described in paragraph
(2), has not been adequately implemented, or is inadequate for the safe operation of a pipeline facility, the Secretary
may conduct proceedings under this chapter.” (emphasis added)



3
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. §§ 192.947(d) and 192.905(a),
which state:
§ 192.947 What records must an operator keep?
An operator must maintain, for the useful life of the pipeline, records that
demonstrate compliance with the requirements of this subpart. At minimum,
an operator must maintain the following records for review during an
inspection.
(a) . . .
(d) Documents to support any decision, analysis and process developed
and used to implement and evaluate each element of the baseline assessment
plan and integrity management program. Documents include those developed
and used in support of any identification, calculation, amendment,
modification, justification, deviation and determination made, and any action
taken to implement and evaluate any of the program elements.
§ 192.905(a) How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator’s transmission
pipeline system are covered by this subpart, an operator must identify the high
consequence areas. An operator must use method (1) or (2) from the
definition in §192.903 to identify a high consequence area. An operator may
apply one method to its entire pipeline system, or an operator may apply one
method to individual portions of the pipeline system. An operator must
describe in its integrity management program which method it is applying to
each portion of the operator’s pipeline system. The description must include
the potential impact radius when utilized to establish a high consequence area.
(See appendix E.I. for guidance on identifying high consequence areas.)
The Notice alleged that Respondent violated 49 C.F.R. §§ 192.947(d) and 192.905(a) by failing
to describe and document in its IMP which method it had applied to each portion of its pipeline
system to identify High Consequence Area (HCA) segments.4
The Notice also alleged that
Williams had failed to maintain records to support any decision, analysis or process developed
and used to implement its IMP. Specifically, it alleged that Respondent failed to keep
documents supporting the process(es) that had been used to identify each HCA segment.
At the hearing, Williams acknowledged that its IMP procedures needed to include stronger
language stating what data and methodology were used for identifying HCAs, yet submitted page
4 A “High Consequence Area” is defined as: 1) an offshore area; or any class location unit that has 10 or fewer
buildings intended for human occupancy; (2) any class location unit that has more than 10 but fewer than 46
buildings intended for human occupancy; (3) any class location unit that has 46 or more buildings intended for
human occupancy; or (ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a
small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public
assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. 49
C.F.R. 192.5 (b)(3); or (4) any class location unit where buildings with four or more stories above ground are
prevalent. 49 C.F.R. 192.5 (b)(4).



4
1 of Chapter 4 of its IMP Overview to demonstrate its compliance with the regulations. OPS
responded by pointing out that while page 1indicated the use of Method 1 in identifying HCAs,5
the OPS inspection team had discovered indications that Method 2 was also used. OPS argued
that the inspection team found inconsistencies between Respondent’s summary and its actual
procedures.
Williams explained that the inconsistencies in Chapter 4 of its IMP Overview resulted from a
typographical error and that in addition to correcting this error, the company had revised its
Baseline Assessment Plan (BAP) to include the correct method being used for each HCA.
However, Respondent did not deny that it had failed to provide the OPS inspection team with
documentation of the methods it had used to identify each HCA segment.
Accordingly, after considering all of the evidence, I find that Williams violated 49 C.F.R.
§§ 192.947(d) and 192.905(a) by failing to describe and document in its IMP which methods it
had applied to each portion of its pipeline to identify HCA segments by the December 17, 2004
deadline (December 2004 Deadline) imposed under 49 C.F.R. § 192.907(a).
Item 2A: The Notice alleged that Respondent violated 49 C.F.R. § 192.905(a), which states:
§ 192.905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator’s transmission
pipeline system are covered by this subpart, an operator must identify the high
consequence areas. An operator must use method (1) or (2) from the
definition in §192.903 to identify a high consequence area. An operator may
apply one method to its entire pipeline system, or an operator may apply one
method to individual portions of the pipeline system. An operator must
describe in its integrity management program which method it is applying to
each portion of the operator’s pipeline system. The description must include
the potential impact radius when utilized to establish a high consequence area.
(See appendix E.I. for guidance on identifying high consequence areas.)
The Notice alleged that Respondent violated 49 C.F.R. § 192.905(a) by failing to describe in its
IMP which method it had applied to each portion of its pipeline to identify HCA segments.
Specifically, it alleged that the system maps and the GIS system used by Respondent failed to
establish a suitable means of documenting segment locations in HCAs. According to the Notice,
5 Operators may identify HCAs using either of two methods:
o Method 1: A pipeline segment is located in a high consequence area if any of the following apply:
 A Class 3 location under 192.5; or
 A Class 4 location under 192.5; or
 Any area outside a Class 3 or Class 4 location where the potential impact radius is greater than 660
feet (200 meters), and the area within a potential impact circle contains 20 or more buildings
intended for human occupancy; or
 The area within a potential impact circle containing an identified site.
o Method 2: A pipeline segment is located in a high consequence area if any of the following apply:
 The area within a potential impact circle contains 20 or more buildings intended for human
occupancy; or
 The area within a potential impact circle contains an identified site.



5
Williams’ personnel acknowledged during the OPS inspection that the accuracy of its pipe-
segment locating process ranged from survey quality to +/- 40 feet and that Respondent had not
taken any action to address these known inaccuracies in its HCA identification process.
At the hearing, Williams posed that it was unnecessary to account for uncertainties in its HCA
identification process. Respondent argued that § 192.905(a) did not require system maps or GIS
systems, nor did it address quality assurance methods. Respondent advised that every year it
performed a structure survey to review data on its GIS.
In response, OPS asserted that, during the March 13, 2006 inspection, Williams’ process for
conversion from legacy alignment sheets and survey notes to GIS was discussed and fully
explained. OPS testified that discussions with Respondent included past and current processes
and activities and focused on continuous improvement of centerline accuracy, including
collection of survey grade points, ortho-photo centerline and ortho-photo structure location
corrections. OPS also testified that Engineering Services Management of Change (MOC) and
annual update processes were shared and discussed on March 16, 2006, to further reinforce
continuous improvement processes related to GIS centerline data integrity and related facility
drawings. OPS explained that the issue was the need to factor uncertainty into HCA
identification and to document a suitable means of delineating segment locations.
In response and in support of its position, Williams introduced INGAA’s letter to Stacey Gerard,
former Associate Administrator of PHMSA, as documentation that the application of uncertainty
factors to the identification of HCAs was “overkill,
” based on the ratio of assessment of non-
covered segments to covered segment miles. Respondent argued that it had discussed and
described this process to the OPS inspection team.
OPS responded that the company’s identification process was inadequate and still under
development, at a time when a more mature process should have been in place. Based upon its
inspection and review of Chapter 4 of Respondent’s IMP Overview, OPS contended that
HCA identification process. OPS staff testified that during the inspection, Respondent had not
described the PIR of the method used to establish HCAs and that the inspection team had found
no documentation that Williams had considered additional buffers to account for potential
pipeline location inaccuracies. Furthermore, OPS explained that many HCAs had not been
Williams had applied no safety factors to the calculation of potential impact radii6 (PIRs) in the
identified when inspectors reviewed the company’s alignment sheets.
Accordingly, after considering all the evidence, I find that Williams violated 49 C.F.R.
§ 192.905(a) by failing to describe in its IMP which method it had applied to each portion of its
pipeline to identify HCA segments, in that the inaccurate maps and electronic GIS system used
by the company failed to properly document segment locations.
Item 2B: The Notice alleged that Respondent violated 49 C.F.R. § 192.905(b), which states:
6 “Potential impact radius” is defined in § 191.903 as the radius of a circle within which the potential failure of a
pipeline could have significant impact on people or property.



6
§ 192.905 How does an operator identify a high consequence area?
(a) . . .
(b)(1) Identified sites. An operator must identify an identified site, for
purposes of this subpart, from information the operator has obtained from
routine operation and maintenance activities and from public officials with
safety or emergency response or planning responsibilities who indicate to the
operator that they know of locations that meet the identified site criteria.
These public officials could include officials on a local emergency planning
commission or relevant Native American tribal officials.
(2) If a public official with safety or emergency response or planning
responsibilities informs an operator that it does not have the information to
identify an identified site, the operator must use one of the following sources,
as appropriate, to identify these sites.
(i) Visible marking (e.g., a sign); or
(ii) The site is licensed or registered by a Federal, State, or local
government agency; or
(iii) The site is on a list (including a list on an internet web site) or map
maintained by or available from a Federal, State, or local government agency
and available to the general public.
The Notice alleged that Respondent violated 49 C.F.R. § 192.905(b) by failing to use certain
information available to it in cases where public officials with safety or emergency response or
planning responsibilities had informed the company that they did not have information
delineating identified sites. Specifically, the Notice alleged that Williams had failed, by the
December 2004 Deadline, to use visible markings, licensing or registration by a governmental
agency, or listing on the Internet or other public available maps maintained by governmental
entities to delineate identified sites in lieu of obtaining relevant information from public officials.
In addition, it alleged that Williams did not have procedures on how it located identified sites
using such alternative sources of information. During the OPS inspection, the inspector
conducted a review of Respondent’s procedures, including IM Procedure 10.09.01.10,
Establishing Class and HCA Location, Section 8.1.10, and alleged that they did not address the
need to use these other information sources.
As for the first allegation, Williams acknowledged at the hearing that it had not been able, by the
December 2004 Deadline, to secure information on potential identified sites with its April 2005
mail-out to public officials having safety or emergency response or planning responsibilities.
Respondent argued nevertheless that the regulation did not require that a mail-out be undertaken
to public officials for the purposes of obtaining identified site information. It also reiterated its
position that it had not been informed by any public official that it lacked sufficient information
to identify an identified site. Respondent further advised that it had completed a pilot project to
192), which is a query from available lists, and had found the results to be insufficiently
accurate.
evaluate the use of Standard Industrial Classification (SIC)7 codes (Method 3 suggested in Part
7 SIC Codes are used to create targeted mailing lists by industry type.



7
I find that although Williams had some documentation showing potential identified sites through
the use of alignment sheets, there were no dates on these sheets earlier than 2006; therefore,
these sheets are not probative of whether or not the company used such information prior to the
December 2004 Deadline. I also find that even if Respondent had other marked-up alignment
sheets prior to 2006, they were not provided at the time of the inspection, during the hearing, or
with the Closing.
There is no evidence in the record that Respondent had made any effort to obtain information
from public officials to gather data on potential identified sites prior to the December 2004
Deadline. Williams testified that it had used “visible markings such as signs” to delineate
identified sites; however, such information is only allowed under the regulation to be used to the
extent that the operator is unable to obtain information from public officials. The intent of the
regulation is to require operators to seek information from public officials who are better
informed than operators about where identified sites are located, how to avoid damaging such
sites, how to recognize and report emergencies that may arise, and how to protect isolated
population areas located near pipelines. It is only when such information is unavailable from
public officials that operators may use other data sources to delineate identified sites.
As for the second allegation that it lacked proper procedures for using alternative information
§ 192.905 defining the term “identified sites” and stating: “This year we’ll also have to locate
“high consequence areas”
called identified sites. We will be required to locate these all the way
out to the 660” line.” These Field Instructions, however, do not contain detailed procedures
describing the use of alternative information sources.
sources, Williams submitted a copy of its 2004 Field Instructions,8 which quoted language from
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.905(b), by failing to use alternative sources of information to identify HCAs after being
unable to obtain information from public officials regarding identified sites, by the December
2004 Deadline.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.907(a), which states:
§ 192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered
pipeline segment must develop and follow a written integrity management
program that contains all the elements described in § 192.911 and that
addresses the risks on each covered transmission pipeline segment. The initial
integrity management program must consist, at a minimum, of a framework
that describes the process for implementing each program element, how
relevant decisions will be made and by whom, a time line for completing the
work to implement the program element, and how information gained from
experience will be continuously incorporated into the program. The
framework will evolve into a more detailed and comprehensive program. An
operator must make continual improvements to the program.
8 Closing, DVD, at 47.



8
Item 3 of the Notice alleged that Respondent violated 49 C.F.R. § 192.907(a) by failing to meet
the December 2004 Deadline for developing and following a written IMP that contained all the
elements described in § 192.911 and that addressed the risks on each covered transmission
pipeline segment. Specifically, the Notice alleged that Williams’ records revealed that, as of
April and May 2005, the company’s HCA identification process was still incomplete. For
example, it alleged that public officials had not been contacted for the location of identified sites
until April 2005.
At the hearing, Respondent repeated its response to Item 2B above and argued that as of the
December 2004 Deadline, public officials had not provided any information on identified sites.
It further argued that § 192.907(a) did not require that a mail-out be undertaken to public
officials for the purposes of obtaining identified site information. Instead, the company indicated
that it had identified HCAs in Class 1 and 2 areas by the December 2004 Deadline using
information obtained from routine operation and maintenance activities.
OPS responded that Williams did not even start to contact public officials until 2005, after the
December 2004 Deadline. OPS argued that because Respondent had not sought information on
identified sites from public officials in a timely manner, its delineation of identified sites was
incomplete as of the December 2004 Deadline.
After considering all the evidence, I find that none of the documentation submitted by
Respondent during the hearing or in the company’s Closing demonstrates that the identified sites
were properly delineated prior to the December 2004 Deadline. Therefore, I find Respondent
violated 49 C.F.R. § 192.907(a), by failing to develop and follow a written IMP by the December
2004 Deadline that contained all the elements described in § 192.911 and that addressed the risks
on each covered transmission pipeline segment.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.905(a), as quoted above,
by failing to properly identify HCA areas using one of the methods described in paragraphs (1)
or (2) (Methods 1 and 2) below from the definition of “High Consequence Area” provided in
§ 192.903. That section states, in relevant part:
§ 192.903 What definitions apply to this subpart?
The following definitions apply to this subpart: . . .
High consequence area means an area established by one of the methods
described in paragraphs (1) or (2) as follows:
(1) An area defined as
(i) A Class 3 location under §192.5; or
(ii) A Class 4 location under §192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact
radius is greater than 660 feet (200 meters), and the area within a potential
impact circle contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact
circle contains an identified site.
(2) The area within a potential impact circle containing
(i) 20 or more buildings intended for human occupancy, unless the
exception in paragraph(4) applies; or
(ii) An identified site.



9
(3) Where a potential impact circle is calculated under either method (1) or
(2) to establish a high consequence area, the length of the high consequence
area extends axially along the length of the pipeline from the outermost edge of
the first potential impact circle that contains either an identified site or 20 or
more buildings intended for human occupancy to the outermost edge of the last
contiguous potential impact circle that contains either an identified site or 20 or
more buildings intended for human occupancy. (See figure E.I.A. in appendix
E.)….
Identified site means each of the following areas:
(a) An outside area or open structure that is occupied by twenty (20) or
more persons on at least 50 days in any twelve (12)-month period. (The days
need not be consecutive.) Examples include but are not limited to, beaches,
playgrounds, recreational facilities, camping grounds, outdoor theaters,
stadiums, recreational areas near a body of water, or areas outside a rural
building such as a religious facility; or
(b) A building that is occupied by twenty (20) or more persons on at least
five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The
days and weeks need not be consecutive.) Examples include, but are not
limited to, religious facilities, office buildings, community centers, general
stores, 4-H facilities, or roller skating rinks;…
Item 4A of the Notice alleged that Respondent violated 49 C.F.R. § 192.905(a) by failing to
properly apply Method 1 in delineating HCAs, insofar as the full length of Class 3 and 4
locations9 was not included in the HCAs. Specifically, the Notice alleged that the OPS
full length of its Class 3 and 4 locations within HCA boundaries and that therefore these
inspection10 had revealed that, in an effort to use Method 1, Williams had failed to include the
locations were not properly scheduled for assessment or repairs.
At the hearing, Respondent asserted that it had correctly applied Method 1, but acknowledged
that not all HCAs had been identified as of the OPS IMP audit in March 2006. The company
advised that data was still being analyzed and HCA determinations were still pending.
Williams also acknowledged that the HCA boundaries were shorter than the Class 3 dimensions
but disagreed with OPS’ assertion that a portion of the HCAs had therefore not been properly
scheduled for assessment or repair. Williams contended that when it undertook External
Corrosion Direct Assessment (ECDA), it would visit each site to confirm the actual, required
9 A Class 3 location is defined as: (i) any class location unit that has 46 or more buildings intended for human
occupancy; or (ii) an area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-
defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that
is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and
weeks need not be consecutive.) 49 C.F.R. § 192.5 (b)(3).
A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.
49 C.F.R. § 192.5(b)(4).
10 The OPS inspection included a review of Respondent’s Alignment Sheet, Location Class Determination and
Qualification Record, MP 1782.125 to 1783.750, Somerset and Middlesex Counties, NJ Main Line, and DOT-NJ-8.
Pipeline Safety Violation Report, at 10.



10
length of pipe to be inspected. At that point, the company would assess the entire length of the
HCA. Respondent further contended that when using in-line inspection (ILI), it analyzed data
for the entire ILI run, not just for the HCA areas.
In its Closing, Williams posed that not correctly identifying the length of the Class 3 and 4
locations used in Method 1 was irrelevant since it visited each site to confirm the actual, required
length of the pipe to be inspected and then the entire length of the HCA would be assessed. For
ECDA, Respondent stated that the length of the HCA segments was also irrelevant because the
company performed actual field measurements. The company further posed that it treated
immediate repair conditions in non-covered segments the same as those in covered segments.
OPS countered that the issue was not whether Williams took alternative measures to protect the
integrity of the pipeline, but, rather, whether the company properly used Method 1 under
§ 192.905(a) to identify HCAs. In addition, OPS noted that the company’s repair procedures did
not include a specific timeframe for repairing immediate conditions in non-covered segments.
Therefore, if an immediate condition were located just outside an HCA segment that should have
included the condition, then the condition would not get repaired in a timely manner.
Accordingly, based upon the company’s own admission and a review of all of the evidence, I
find that Williams violated 49 C.F.R. § 192.905(a), by failing to adequately establish HCA areas
using Method 1, as described in § 192.903.
Item 4B of the Notice alleged that Respondent violated 49 C.F.R. § 192.905(a), as quoted above,
by failing to properly identify HCA areas using Method 1, as described in the definition of “High
Consequence Area” under § 192.903. Specifically, the Notice alleged that Williams failed to
properly identify HCAs under that portion of Method 1 which calls for the identification of areas
“in a Class 1 or Class 2 location where the potential impact circle contains an identified site.”
sites on Williams’ Transco system that the company had failed to include in HCAs. The Notice
alleged that the HCA identification process was flawed insofar as the company’s field personnel
were not even trained in the HCA identification process until well after the December 2004
According to the Notice, documentation reviewed during the inspection 11 showed identified
Deadline.
At the hearing, Williams indicated that training was an ongoing part of its continuous
improvement process and that in February 2004, its field personnel had been given instructions
on locating and reporting structures along the pipeline. The company further contended that it
had completed company-wide training that restated IMP requirements such as collecting
information on identified sites and that the April-June 2005 training mentioned by the OPS
inspection team was additional training that covered the entire IM program. In its Closing,
Respondent provided a copy of its 2004 Field Instructions.
12
11 Respondent’s Alignment Sheet, Location Determination and Pipeline Qualification Record, MP 1408.000 to
1410.87, Pittsylvania County, VA, Main Line, DOT-V-9. Respondent’s Alignment Sheet, Location Determination
and Pipeline Qualification Record, MP 1457.375 to 1459.375, Appomattox, VA, Main Line, and DOT-V-25B.
Violation Report, pp. 12 and 45.
12 Closing, at 47.



11
OPS responded that although the 2004 Field Instructions acknowledged identified sites must be
identified, Williams did not provide evidence at the time of the inspection that any identified
sites had actually been identified. OPS testified that its inspection had revealed a company e-
mail sent in February 2004, entitled “2004 House Count Instructions.” OPS asserted that an
examination of the document showed that the 2004 Field Instructions were not training materials
and did not indicate that Respondent’s employees had actually been trained to delineate
identified sites.
After considering all the evidence, I find that the field instructions that were provided as part of
the Closing were not provided to the OPS inspection team at the time of the audit. Although
Respondent’s 2004 Field Instructions acknowledged that identified sites must be identified, I see
no evidence showing that any sites had actually been identified or that actual training had been
provided to company personnel, as would be reflected by sign-in sheets or similar
documentation. I also find that Respondent’s personnel collected information on identified sites
prior to being properly trained.
As a result, Respondent failed to properly identify HCA areas using Method 1 in its HCA
identification process, as there was no evidence that Williams considered identified sites that lay
within the potential impact circle of the Class 1 and 2 locations. Accordingly, upon review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 192.905(a) by failing to properly use
Method 1, as described in § 192.903, to include certain identified sites in its HCAs.
Item 4C of the Notice alleged that Respondent violated 49 C.F.R. § 192.905(a), as quoted
above, by failing to properly identify HCA areas using Method 1, as described in the definition
of “High Consequence Area” under § 192.903. Specifically, it alleged that Williams improperly
applied Method 1 by failing to designate certain outdoor areas and buildings as “identified sites.”
Section 192.903 provides that “[a]n outside area or open structure that is occupied by twenty (20)
or more persons on at least 50 days in any twelve (12)-month period” shall be considered an
“identified site.” In addition, it provides that “[a] building that is occupied by twenty (20) or
more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month
period” shall also be considered an identified site.
The Notice alleged that Williams’ procedure, WGP IMP Overview Chapter 4, Section 4.8,
defined the term “day” as a continuous 8-hour period, for purposes of determining whether
structures or outdoor areas qualified as identified sites. This definition, OPS asserted, was
inconsistent with the regulation, insofar as the 20-or-more-persons criterion applied to the
presence of people at a particular location at any point in time, not just for a continuous 8-hour
period. For example, using the definition of “day” set forth in Respondent’s procedure, a picnic
area would have to sustain 20 or more persons on site for eight hours a day, five days a week, for
10 weeks (i.e., 50 days) in any 12-month period.
At the hearing, Respondent argued that its current Procedure 10.09.01.10 met the requirements
of §§ 192.903 and 192.905, which do not specify the length of a day. The company argued that
the terms “day” and “occupied” in the regulation were nebulous and not clearly defined in 49
C.F.R. Part 192. In support of its position, Williams suggested that PHMSA’s published
guidance document, FAQ #211, directly asked for clarification but that the agency had pointedly
steered clear of the issue and declined to define the length of a day.



12
Respondent’s argument is specious. While it is correct that § 192.903 does not specify how
many hours constitute a “day” for purposes of designating identified sites,13 such detail is
unnecessary. The FAQ #211 guidance document explicitly states that a site is considered an
identified site if 20 or more persons occupy it for any length of time, unless they are in transit. I
fail to see any ambiguity in the regulation. If a site is normally occupied for one hour or 23
hours per day, it is still considered a “day” for purposes of determining whether to classify the
area as an identified site. By requiring that a site be occupied for at least eight hours per day,
Respondent’s procedure greatly reduces the number of sites with outdoor gathering areas or
buildings that qualify for the additional protections required for HCAs. I do not believe such a
procedure is consistent with the purpose or intent of the term “identified site” in § 192.903.14
Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49
C.F.R. § 192.905(a) by failing to adequately use Method 1, as described in the definition of
“High Consequence Area” under § 192.903, to designate certain outdoor areas and buildings as
identified sites.
Item 4D of the Notice alleged that Respondent violated 49 C.F.R. § 192.905(a), as quoted above,
by failing to properly designate HCA areas, as defined under § 192.903. Specifically, it alleged
that Williams failed to apply the axial extension of the potential impact circle along the length of
the pipeline, from the outermost edge of the first potential impact circle containing either an
identified site or 20 or more buildings intended for human occupancy, to the outermost edge of
the last contiguous potential impact circle containing such sites. The Notice alleged, for
example, that for HCA 1401 - Ft. Lewis to Sumner MP 1346.844, the company’s GIS showed
the HCA length as being 0.174 miles, but that if the potential impact circle were properly
extended, the length would be 0.42 miles.
At the hearing, Respondent acknowledged that its HCAs with identified sites from its 2004
survey failed to include the proper axial extensions and indicated that a detailed review of all its
HCAs would be completed by April or May 2006. The company further advised that its baseline
assessment HCA lengths would be adjusted as necessary following such comprehensive
review.15
13 FAQ-211 states: “Time limit for gathering of 20 people. If a building or outside area is typically or normally
occupied by 20 or more people while in use, then the location is considered an identified site. The rule provides that
operators can rely on information from local public officials with emergency response or planning responsibilities to
make these determinations. Operators need not consider persons who merely pass through an area, since these
persons are considered to be in transit and cannot truly be said to ‘occupy’ the location.”
14 In support of its position, OPS cited two other guidance documents, Advisory Bulletin ABD-03-03, dated July 17,
2003, and FAQ #18, which states: “Practical Limits on Searching for Identified Sites. Are there practical limits on
an operator’s search for identified sites? Yes. An operator is expected to make a reasonable effort to identify sites
meeting the criteria for ‘identified sites.’ The rule requires that operators consider information they have gleaned
from routine operations and maintenance activities along the pipeline and from public officials responsible for safety
or emergency response/planning who indicate to the operator that they know of locations near the pipeline meeting
these criteria. If no public officials have such knowledge, then the operator must identify facilities that either: (1)
have visible signs; (2) are licensed by a Federal, State, or local government agency; or (3) appear on a list or map
available from such an agency.”
15 Although Respondent acknowledged that some of the HCA boundaries listed in the Notice needed to be extended,
the company questioned the suggestion that a portion of its HCA has not been scheduled for assessment or repair.
See Violation Report, at 16.



13
Respondent provided two other rationales for the process it had used to delineate identified sites.
First, the company explained that when using ILI, it had analyzed data for the entire ILI run, not
just for HCAs, and that its procedures did not differentiate responses based on whether an
anomaly was located in an HCA or not. Second, it argued that a significant factor contributing to
the abbreviated length of the HCAs was that paragraph 3 of the definition of “High Consequence
Area” in § 192.903 was actually missing from the published 2004, 2005, and 2006 Code of
Federal Regulation (CFR). Respondent stated that its employee who initially identified the
HCAs made an error by interpreting the code without the benefit of this paragraph.
As to the first argument, OPS responded that Respondent’s misapplication of the process for
identifying covered segments was the issue, not the methodology by which Williams read its
own ILI data, and that if the company had performed the HCA determination process correctly, it
would have picked up many additional HCAs. As for the second, I would note that the Federal
Register is the main source for U.S. government agencies to promulgate proposed rules through
official publication, for seeking comment from the public, for responding to those comments,
and for issuing Final Rules that are incorporated into the CFR. The Supreme Court has held that
the appearance of rules and regulations in the Federal Register gives legal notice of their content
and they are accordingly binding, regardless of whether actual knowledge of their content or of
hardship resulting from innocent ignorance, thus approving the principle of constructive notice
with regard to rules and regulations and placing them on a par with statutory law.
16 Everyone is
charged with knowledge of federal laws and United States Statutes at Large. Congress has
provided that the publication of rules and regulations in the Federal Register gives sufficient
legal notice of their contents.17
Finally, I would note that even if the wrong version of § 192.903 were, in fact, published in the
CFR, Respondent’s argument would serve only to potentially mitigate the seriousness of the
offense, not to negate it altogether. Therefore, I have addressed this argument in the
“Assessment of Penalty” section below.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.905(a) by failing to properly designate the length of HCA areas, as defined under
§ 192.903, by extending the potential impact circle axially along the length of the pipeline, as
more fully described above.
Item 5A: The Notice alleged that Respondent violated 49 C.F.R. § 192.917, which states, in
relevant part:
§ 192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?
(a) Threat identification . . .
(b) Data gathering and integration. To identify and evaluate the potential
16 Federal Crop Ins. Corporation v. Merrill et al., 332 U.S. 380, 68 S.Ct. 1, 175 A.L.R. 1075, 92 L.Ed. 10 (Nov. 10,
1947).
17 49 Stat. 502, 44 U.S.C. § 307, 44 U.S.C.A. § 307 (appearing in its present form at 44 U.S.C. § 1507 (1976)). 332
U.S. at 384-85, 68 S.Ct. at 3.



14
threats to a covered pipeline segment, an operator must gather and integrate
existing data and information on the entire pipeline that could be relevant to
the covered segment. In performing this data gathering and integration, an
operator must follow the requirements in ASME/ANSI B31.8S, section 4. At
a minimum, an operator must gather and evaluate the set of data specified in
Appendix A to ASME/ANSI B31.8S, and consider both on the covered
segment and similar non-covered segments, past incident history, corrosion
control records, continuing surveillance records, patrolling records,
maintenance history, internal inspection records and all other conditions
specific to each pipeline...
(e) Actions to address particular threats. If an operator identifies any of
the following threats, the operator must take the following actions to address
the threat.
(1) Third party damage . . .
(4) ERW pipe. If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW), lap welded pipe or other pipe that
satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3
and A4.4, and any covered or non-covered segment in the pipeline system
with such pipe has experienced seam failure, or operating pressure on the
covered segment has increased over the maximum operating pressure
experienced during the preceding five years, an operator must select an
assessment technology or technologies with a proven application capable of
assessing seam integrity and seam corrosion anomalies. The operator must
prioritize the covered segment as a high risk segment for the baseline
assessment or a subsequent reassessment . . . .
Item 5A of the Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(4) by failing to
develop and follow procedures for identifying whether its covered pipeline segments contained
low frequency electric resistance welded (ERW) pipe, lap welded pipe, or other pipe that
satisfied the conditions specified in ASME B31.8S-2001 (ASME Standard), Appendices A4.3
and A4.4, and whether any covered or non-covered segments in its system with such pipe had
experienced seam failure, or whether the operating pressure on any covered segment had
increased over the maximum operating pressure experienced during the preceding five years.
Specifically, it alleged that Williams did not have procedures in place to verify that the
assessment method(s) it had selected for such pipe were proven to be capable of assessing seam
integrity and detecting seam corrosion anomalies.18
Respondent contested this Item, asserting that it did indeed have procedures requiring its
employees to review certain checklists to determine whether the selected assessment method(s)
were capable of assessing seam integrity and detecting seam corrosion. The company also
asserted that it had provided the OPS inspection team with an example of its checklist and
explained that it had reviewed pressure tests, ILIs, and the checklists to gather information for
the purpose of determining whether there was a threat posed by ERW pipe.
18 Evidence: Procedure 10.25.01.02, Performing WGP Risk Assessment and Threat Analysis, Section 7.1.1, and
Procedure 70.17.01.16, Pigging-Inline Inspection; Violation Report, at 18.



15
OPS rejected this evidence and presented testimony that Respondent’s procedures were no more
than a bullet checklist, requiring the marking of boxes and including a statement that if no data
were available, then it should be assumed that ERW pipe was not present. OPS further asserted
that the checklist Respondent referred to as its “procedures” contained no detailed step-by-step
information to provide guidance for its employees.
I agree with OPS. The unavailability of identified data elements is not a justification for the
exclusion of a threat from an operator’s integrity management program. Depending on the
importance of the data, additional inspection actions or filed data collection efforts may be
the minimum requirements of the ASME Standard or to provide a rigorous risk analysis process
required.19 The checklists and rudimentary procedures Williams had in place both failed to meet
that could determine whether an actual threat existed from ERW pipe.
Accordingly, upon consideration of all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.917(e)(4) by failing to develop and follow adequate procedures for identifying whether its
covered pipeline segments contained ERW pipe, lap welded pipe, or other pipe that satisfied the
conditions specified in the ASME Standard, Appendices A4.3 and A4.4, and whether any
covered or non-covered segments in its system with such pipe had experienced seam failure, or
whether operating pressure on the covered segments had increased over the maximum operating
pressure experienced during the preceding five years.
Item 5B of the Notice alleged that Respondent violated 49 C.F.R. § 192.917(b), as quoted above,
by failing to develop and implement an IMP that adequately identified and evaluated the
potential threats to its covered pipeline system by gathering and integrating existing data and
information on the entire pipeline that could be relevant to the covered segments. Specifically,
the Notice alleged that Williams failed to properly integrate the required data by the December
2004 Deadline. The regulation requires that individual data elements be brought together and
analyzed to determine the relevance of specific threats.
20
At the hearing, Respondent contended that it had procedures in place, prior to the December
2004 Deadline, to fully integrate and analyze the required data for risk assessment and threat
analysis. Respondent explained that, during the inspection, there may have been
miscommunication during the discussion with the OPS team about Respondent’s old risk model,
as opposed to its new one. The company indicated that it had produced GIS sheets and a
business plan, with schematics, for a more robust data integration system, prior to the December
2004 Deadline.
OPS acknowledged that while Williams did have a method to aggregate data, the company
failed to have procedures in place to actually analyze individual data elements, to determine the
relevance of specific threats and to support an improved analysis of overall risk. OPS explained
that during the inspection, the company had indicated that it planned to perform this activity,
using its GIS/risk assessment model, by December 2006, two years after the December 2004
Deadline.
19 ASME Standard, Appendices A4.3 and A4.4
20 Evidence: Procedures 10.25.01.02, Performing WGP Risk Assessment and Threat Analysis, Section 4.0;
Violation Report, at 19.



16
I find that Respondent provided GIS sheets to the OPS inspection team for review and that the
company was in the midst of an ongoing process for developing a GIS that would
comprehensively integrate all relevant data. However, I further find that the record does not
contain sufficient evidence to show that Respondent had the required data integration process in
place as of the December 2004 Deadline. Accordingly, after considering all of the evidence, I
find that Respondent violated 49 C.F.R. § 192.917(b) by failing to develop and implement an
IMP that adequately identified and integrated the individual data elements needed to determine
the potential threats to its covered pipeline system.
Item 5D of the Notice alleged that Respondent violated 49 C.F.R. § 192.917(b), as quoted
above, by failing to have a process in its IMP for verifying data quality, insofar as the company’s
procedures did not require conservative assumptions to be applied if certain data were missing or
been applied. For example, pipeline sections containing ERW pipe defaulted to a non-
conservative value without verifying that operating pressures had actually been at the maximum
allowable operating pressure (MAOP). The Notice also alleged that Respondent failed to
maintain records showing how unsubstantiated data was used and failed to specify that additional
inspections or field data collection efforts were necessary if data were missing or suspect.
suspect.21 The Notice also alleged that it was not clear whether conservative values had actually
At the hearing, Respondent contended that its Procedures 10.25.01.02, Section 4, and 70.18
called for the use of a “Threats Checklist,
” which was used by subject matter experts (SMEs) to
determine where conservative assumptions should be applied, based upon the SMEs’ skill,
experience and work on the job on a daily basis. Williams further contended that all of its ERW
pipelines were treated as high-risk lines.
OPS reiterated that § 192.917(b) requires operators to gather data and integrate existing data and
information on their entire pipelines and not just on covered segments. According to the agency,
Williams acknowledged that all of the data required by the ASME Standard had not been
captured or integrated into its GIS system. OPS further contended that the ASME Standard
requires that if a data element is missing for a particular threat, then the operator must assume
that the threat applies.
conservative assumptions in such situations.
22 I can find nothing in the record to show that Williams actually applied
Accordingly, upon consideration of all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.917(b) by failing to have an adequate process in its IMP for gathering and integrating data
on its entire pipeline, insofar as it lacked processes for verifying data quality or for applying
conservative assumptions if data were missing or suspect.
Item 6B: Item 6B of the Notice alleged that Respondent violated 49 C.F.R. § 192.921(d), which
states:
21 Evidence: Procedures 10.25.01.02, Performing WGP Risk Assessment and Threat Analysis, Section 4.0; Items
C.02.d ii, and iv listed as NA in WGP’s Protocol Cross Reference List.
22 ASME Standard, Appendix A4.2.1. Once data is collected, it must be turned into transparent information.
Operators can refer to the OPS Gas Integrity Management Advisory Bulletin ADB-03-07 of November 17, 2003 (68
FR 64948) for an explanation of how OPS interprets the statutory requirement “to begin assessments” and for
guidance on what steps OPS considers to be acceptable for conducting the baseline assessment process.



17
§ 192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. . . .
(b) Prioritizing segments. An operator must prioritize the covered
pipeline segments for the baseline assessment according to a risk analysis that
considers the potential threats to each covered segment. The risk analysis
must comply with the requirements in § 192.917. . .
(d) Time period. An operator must prioritize all the covered segments for
assessment in accordance with § 192.917 (c) and paragraph (b) of this section.
An operator must assess at least 50% of the covered segments beginning with
the highest risk segments, by December 17, 2007. An operator must complete
the baseline assessment of all covered segments by December 17, 2012.
The Notice alleged that Respondent violated 49 C.F.R. § 192.921(d) by failing to prioritize all its
covered pipeline segments for the baseline assessment in such a manner that its assessment
schedule could be properly verified. Specifically, the Notice alleged that Williams had made
numerous errors in its initial HCA identification process, which resulted in an inability to verify
that the assessment schedule set forth in its BAP met the requirements in the regulation. The
Notice further alleged that the company’s BAP failed to include certain HCA segment mileage
that had been erroneously omitted, as discussed in Item 4D above, and that Method I had been
improperly applied to the Transco system such that the full length of Class 3 and 4 locations
were not included in HCA boundaries. These errors resulted in a failure to properly prioritize
and set an assessment schedule for these lines. At the hearing, Respondent did not contest these
allegations. Accordingly, after considering all of the evidence, I find Respondent violated 49
C.F.R. § 192.921(d).
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.907(b), which states:
§ 192.907 What must an operator do to implement this subpart?
(a) . . . .
(b) Implementation Standards. In carrying out this subpart, an operator
must follow the requirements of this subpart and of ASME/ANSI B31.8S
(incorporated by reference, see §192.7) and its appendices, where specified.
An operator may follow an equivalent standard or practice only when the
operator demonstrates the alternative standard or practice provides an
equivalent level of safety to the public and property. In the event of a conflict
between this subpart and ASME/ANSI B31.8S, the requirements in this
subpart control.
The Notice alleged that Respondent violated 49 C.F.R. § 192.907(b) by failing to follow the
requirements of Subpart O of 49 C.F.R. Part 192 and the ASME Standard in the development
and implementation of its IMP. Specifically, it alleged that Williams failed to identify and
evaluate all potential threats to each covered pipeline segment as described in 49 C.F.R.
§ 192.917(a) by the December 2004 Deadline.23
According to OPS, Respondent’s initial risk
23 This subsection states:
“(a) Threat identification. An operator must identify and evaluate all potential threats to
each covered pipeline segment. Potential threats that an operator must consider include, but are
not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by reference, see §192.7),
section 2, which are grouped under the following four categories:



18
assessment and subsequent baseline assessment decisions were based on a risk model that failed
to document the basis for threat-weighting factors, that failed to consider interacting threats, and
that failed to document the elimination of certain threats until after the risk ranking had been
completed. It also alleged that there was a lack of certain documented procedures, including
required activity steps, responsibilities, data inputs and outputs, and documentation requirements.
At the hearing, Respondent argued that its initial risk assessment and subsequent baseline
assessment decisions were based on a viable and industry-accepted risk model known as the
“Bass-Trigon Integrity Assessment Program” (B-T Model). Respondent argued that the B-T
Model used at the time of its BAP development was fully supported and implemented, with 10
years of operational history, and that it addressed all of the data requirements of the ASME
Standard, Appendix A. Respondent further argued that it had procedures in place that included
activity steps, responsibilities, data inputs as documented in the algorithm, and data outputs, as
documented in the risk assessment reports and its BAP. Lastly, it argued that the use of a risk
model was not required by the rule and that the ASME Standard listed SMEs as an acceptable
risk assessment approach.
Respondent defended its risk assessment process by arguing that no threats had been eliminated,
that all threats had been considered as potential threats, and that the interactive nature of various
threats had been considered in determining the relativity of the risks. The results of the relative
risk assessment were then used to prioritize the covered segments, in conjunction with SME
review and validation. The most significant risk factors were then determined through the
completion of a “Threats Checklist” by SMEs that provided criteria for the elimination of threats
from further consideration. Then the appropriate integrity assessment method was determined,
based on the threats to which a particular segment was susceptible.
In response, OPS argued that the B-T Model being used at the time of the inspection failed to
cover all of the threats enumerated in the ASME Standard, most notably stress corrosion
cracking (SCC).
SCC and yet failed to consider that SCC could be present along its system. OPS also asserted
that the Threats Checklists was developed and implemented in 2006 and that Williams had failed
to present any evidence that it had a documented process to identify threats as of the December
2004 Deadline. OPS also testified that there was no indication that the default weightings used
by Williams in the B-T Model were ever modified using an SME approach.
24 OPS asserted that Williams had a history of leaks and failures attributed to
I agree with OPS. In particular, I find that the B-T Model used by Williams did not cover all of
the threats identified in the ASME Standard, including SCC, which is a known condition on
portions of Respondent’s pipeline. Accordingly, based upon a review of all of the evidence, I
find that Respondent violated 49 C.F.R. § 192.907(b) by failing to identify and evaluate all
potential threats to each covered pipeline segment as described in 49 C.F.R. § 192.917(a) by the
December 2004 Deadline.
(1) Time dependent threats such as internal corrosion, external corrosion, and stress
corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;
(3) Time independent threats such as third party damage and outside force damage; and
(4) Human error.”
24 ASME Standard, Section 2.2, Integrity Threat Classification.



19
Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 192.925, which states:
§ 192.925 What are the requirements for using External Corrosion
Direct Assessment (ECDA)?
(a) Definition. is a four-step process that combines preassessment,
indirect inspection, direct examination, and post assessment to evaluate the
threat of external corrosion to the integrity of a pipeline.
(b) General requirements. An operator that uses direct assessment to
assess the threat of external corrosion must follow the requirements in this
section, in ASME/ANSI B31.8S (incorporated by reference, see § 192.7),
section 6.4, and in NACE [Recommended Practice (RP)] 0502-2002
(incorporated by reference, see § 192.7). An operator must develop and
implement a direct assessment plan that has procedures addressing
preassessment, indirect examination, direct examination, and post-assessment.
If the ECDA detects pipeline coating damage, the operator must also integrate
the data from the ECDA with other information from the data integration
(§ 192.917(b)) to evaluate the covered segment for the threat of third party
damage, and to address the threat as required by §192.917(e)(1).
(1) Preassessment. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 3, the plan’s procedures
for preassessment must include-
(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment; and
(ii) The basis on which an operator selects at least two different, but
complementary indirect assessment tools to assess each ECDA Region. If an
operator utilizes an indirect inspection method that is not discussed in
Appendix A of NACE RP 0502-2002, the operator must demonstrate the
applicability, validation basis, equipment used, application procedure, and
utilization of data for the inspection method.
(2) Indirect examination. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 4, the plan's procedures
for indirect examination of the ECDA regions must include-
(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment;
(ii) Criteria for identifying and documenting those indications that must
be considered for excavation and direct examination. Minimum identification
criteria include the known sensitivities of assessment tools, the procedures for
using each tool, and the approach to be used for decreasing the physical
spacing of indirect assessment tool readings when the presence of a defect is
suspected; ... .
(3) Direct examination. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 5, the plan's procedures
for direct examination of indications from the indirect examination must
include:
(i) ...
(iii) Criteria and notification procedures for any changes in the ECDA
Plan, including changes that affect the severity classification, the priority of



20
direct examination, and the time frame for direct examination of indications;
and
(iv) Criteria that describe how and on what basis an operator will
reclassify and reprioritize any of the provisions that are specified in section
5.9 of NACE RP 0502-2002.
(4) Post assessment and continuing evaluation. In addition to the
requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002,
section 6, the plan's procedures for post assessment of the effectiveness of the
ECDA process must include-
(i) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in covered segments; and
(ii) Criteria for evaluating whether conditions discovered by direct
examination of indications in each ECDA region indicate a need for
reassessment of the covered segment at an interval less than that specified in
§ 192.939. (See Appendix D of NACE RP 0502-2002.)
Item 8A of the Notice alleged that Respondent violated 49 C.F.R. § 192.925(b) by failing to use
direct assessment to assess the threat of external corrosion in a manner that followed the
requirements of the ASME Standard, section 4.2, and NACE RP 0502-2002 (NACE Standard),
section 3.2. Specifically, it alleged that Williams failed to follow its own Procedure
20.19.01.02, which required the company to use the data requirements from ASME Standard,
section 4.2, and NACE Standard, section 3.2, to address the four elements constituting an ECDA
program, namely, preassessment, indirect examination, direct examination, and post-assessment.
It also alleged that there was no documentation showing what assumptions had been made or
what information was required to assure the feasibility of each ECDA project.
At the hearing, Respondent asserted that it had used all data sets required by the rule during the
ECDA preassessment process, but acknowledged the need to have a form explicitly listing all the
data requirements. Respondent stated that it would develop a new form for Procedure 20.19.01
that would be completed for all ECDA projects25 and that it would include all of the information
listed in the ASME Standard, section 4.2.2 Table 1, section 4.4, Table 2, and in the NACE
Standard, section 3.2.2, Table 1. Respondent further acknowledged in its Closing26 that it had
not “met expectations” in regard to the implementation of its ECDA procedures but disagreed
with PHMSA’s assertion that the company had failed to put forth a good-faith effort to achieve
compliance.
performing ECDA.
27 Williams also acknowledged that it had not met PHMSA’s “expectations” for
After considering all the evidence, I find that Respondent failed to follow its own ECDA
procedures for preassessment, indirect examination, direct examination, and post-assessment.
Although Respondent has since developed new ECDA procedures and has retroactively applied
25 Closing, DVD, Sections 2 and 3, at 8-38.
26 Closing, DVD, at 160.
27 Violation Report, at 29. Respondent may have misinterpreted the Violation Report, which asserted that there was
no basis to support a reduction in a civil penalty based upon the reasonableness of the operator’s understanding of
the regulatory requirements.



21
them to completed ECDAs, the record indicates that at the time of the inspection, Williams failed
to demonstrate compliance with the regulation. Accordingly, I find that Respondent violated 49
C.F.R. § 192.925(b) by failing to use ECDA in a manner that followed the requirements of the
ASME Standard, section 4.2, and the NACE Standard.
Item 8B of the Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1), as quoted
above, by failing to implement an ECDA plan that included preassessment procedures meeting
the requirements of ASME Standard, section 6.4, and the NACE Standard, section 3.
Specifically, it alleged that Williams failed to follow its own Procedure 20.19.01.02, sections
3.1.1 and 3.1.2, for conducting feasibility assessments on each ECDA performed. Under the
NACE Standard, section 3,
28 an operator must conduct a feasibility assessment to determine
whether conditions exist on the pipeline that would allow ECDA to be used.
alleged that the ECDAs performed by Respondent and reviewed by OPS included no documents
showing that any feasibility assessments had been performed.
29 The Notice
At the hearing, Respondent contended that it did, in fact, conduct feasibility studies that met the
requirements of the NACE Standard, section 3.3. The company advised that it had used the term
“applicability” in its procedures, rather than “feasibility,” and that it had performed a field study
for each segment before any indirect inspections were performed. Respondent explained that
after the OPS 2006 audit, it had revisited each ECDA project, using the guidelines set out in its
new ECDA procedure. Williams further contended that all previously-performed ECDA
pipeline segments continued to be viable candidates for ECDA implementation and that it
intended to develop a form to document each feasibility assessment.
OPS responded that the feasibility studies, if performed at all by Williams, had not been
documented and that its inspection revealed no documentation to indicate that a single ECDA
meeting the requirements of § 192.925(b)(1) had been completed or initiated.. For example,
OPS referenced the preassessment documentation for the MERCA ECDA,
identify regions, tools, etc. OPS also pointed out that the MERCA ECDA did not document the
parameters required by Respondent’s own Procedure 20.19.01.02, Corrosion Control.
30 noting that it did not
I have given full consideration to all of the evidence and arguments presented by OPS and
Respondent. I find, despite Williams’ contention that it conducted feasibility studies, the
company failed to document or demonstrate that such studies were actually conducted. This is
substantiated by the company’s own acknowledgment that it intended in the future to develop a
form to document each such feasibility study. I further find that Respondent failed to
demonstrate that it followed its own Procedure 20.19.01.02, sections 3.1.1 and 3.1.2, to conduct
feasibility assessments for each ECDA performed. It is immaterial whether Respondent
retroactively determined that ECDA was applicable to a particular segment. Accordingly, I find
Respondent violated 49 C.F.R. § 192.925(b)(1) by failing to implement an ECDA plan that
28 According to NACE Standard, section 3.3.1, a pipeline operator shall integrate and analyze the data collected
above to determine whether conditions exist for which indirect inspection tools cannot be used or that would
preclude ECDA application.
29 NACE Standard, section 3.3.
30 Closing, DVD, Pre-Assessment and site visit report, at 292. MERCA: 16” pipeline with 1.25 miles of HCA.



22
included preassessment procedures meeting the requirements of ASME Standard, section 6.4,
and the NACE Standard, section 3.
Item 8I of the Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(3), as quoted
above, by failing to implement ECDA procedures that met the requirements of the NACE
Standard, section 5, for all required excavations. Specifically, the Notice alleged that OPS’
review of several ECDA projects showed that Williams performed only half the number of
excavations that were required under the NACE Standard and the company’s own ECDA
procedure.31
At the hearing, Respondent acknowledged that the number of digs selected for some ECDA
direct inspections did not meet PHMSA expectations. The company contended that there was a
difference between PHMSA’s interpretation of the NACE Standard and its own, but that it had
revised its ECDA Procedure 20.19.01.02 to clarify the required number of digs and that it had
scheduled subsequent excavations on previously completed ECDA projects.
I find no evidence in the record that Respondent had ECDA procedures in place at the time of the
OPS inspection that followed the NACE Standard, which provides detailed guidance for an
violation stemmed from a difference in interpretation of the regulatory requirements is
unpersuasive for purposes of determining whether a violation occurred. Accordingly, after
initial ECDA inspection by an operator.32 consideration of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.925(b)(3) by
failing to implement ECDA procedures that met the requirements of the NACE Standard, section
5, for all required excavations.
The company’s argument that the allegation of
Item 8K of the Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(4), as quoted
above, by failing to develop and implement procedures that met the NACE Standard for post-
assessment and continuing evaluation. Specifically, it alleged that Williams used the wrong
NACE formula for its remaining life calculations, thereby creating a high probability that some
anomalies in HCA segments would not be excavated or repaired, as required, prior to the next
assessment.
NACE default corrosion rate, actual corrosion rates were not documented. The Notice specified
one particular ECDA project reviewed during the OPS inspection, where the incorrect formulas
and default values were used.
33 It further alleged that although the company’s ECDA procedure included the
At the hearing, Williams acknowledged that it had used the incorrect formula in its ECDA
procedure, that this error had been pointed out by the inspector during the OPS audit, and that the
company had corrected it at that time.
31 Excavation Procedure 20.19.01, Performing External Corrosion Direct Assessment (ECDA); WGP Transco,
ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch Lateral, and Harrison 10 Inch Lateral; ECDA Glenn’s
Ferry 1400 Buhl to Mt. Home, MP 756.6128; ECDA Glenn’s Ferry 1401 Buhl to Mt. Home, MP 756.6155.
32 NACE RP 0502, Section 1 and Section 5.10.
33 WGP Procedure 20.19.01.02, Performing External Corrosion Direct Assessment (ECDA).



23
After considering all the evidence and arguments, I find that Respondent is correct about the
typographic error in the NACE formula. However, in March 2004, NACE published an errata
sheet, correcting the published error. I find that although Williams subsequently used the
appropriate formula, the substantive outcome did not change. I further find that although
Williams made corrections during the OPS audit, the company did not made the necessary
recalculations on anomalies that had already been, or should have been, excavated. Accordingly,
after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 192.925(b)(4)
by failing to use the correct NACE Standard formula for determining remaining life and the
correct default corrosion rate where the actual one had not been documented.
Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.927 (a), which states:
§ 192.927 What are the requirements for using Internal Corrosion Direct
Assessment (ICDA)?
(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a process
an operator uses to identify areas along the pipeline where fluid or other
electrolyte introduced during normal operation or by an upset condition may
reside, and then focuses direct examination on the locations in covered
segments where internal corrosion is most likely to exist. The process
identifies the potential for internal corrosion caused by microorganisms, or
fluid with CO2, O2, hydrogen sulfide or other contaminants present in the gas.
Item 9A of the Notice alleged that Respondent violated 49 C.F.R. § 192.927(a) by failing to
identify areas along its pipeline where water or other electrolyte might be introduced during
normal operation, to determine if internal corrosion were likely to exist, and by failing to provide
an analysis or justification for eliminating internal corrosion as a threat. Specifically, the Notice
alleged that Williams did not have a technical justification for eliminating the threat of internal
corrosion in those areas where ECDA was being utilized and therefore should have been using
ICDA or some other assessment method for internal corrosion.
At the hearing, Respondent argued that it did have a technical justification for eliminating
internal corrosion as a threat. Respondent posed that it had considered nine potential threats,
34
that such threats all existed as a continuum, that they could not be totally eliminated, and that all
such threats existed on all pipeline sections to some degree. On the other hand, Williams argued
that not all segments had to be assessed for all threats if a particular threat were so minimal as to
be irrelevant. The company argued that it had real-time monitoring equipment and scrubbers to
ensure that no “wet gas” entered the system and therefore there was no threat of internal
corrosion.
The company contended that it also used a “Threats Checklist” to establish a minimum threat
threshold. It asserted that it had used this Checklist to eliminate internal corrosion as a threat for
34 Evidence: WGP IM Overview Chapter 8, Section 8.2.2.; Internal Corrosion Threat Checklist, HCA 2436, MP
27.1 to 27.28; Internal Corrosion Threat Checklist, HCA 2436, MP 27.29 to 27; Internal Corrosion Threat
Checklist, HCA 2479, MP 27.1 to 27.28; Internal Corrosion Threat Checklist, HCA, 2479, MP 27.29 to 27.72;
Internal Corrosion Threat Checklist, HCA 0030 Harrison, MP 1.59 to 1.9.



24
all these ECDA projects. If a SME responded “yes” to any of four questions on the Checklist,
then an assessment was required.
35
OPS responded that the checklists reviewed by OPS showed that Williams had dismissed the
during a teleconference with the Transco Operations Center, company personnel had indicated
that Transco’s process equipment had been taken out of service due to damage from Hurricane
Katrina and that unprocessed gas possibly exceeding the water quantity limits had been
introduced into the system. The record also shows that the company had also provided moisture
possibility of internal corrosion on all the ECDA projects reviewed by OPS.36 OPS stated that
data from Station 150 - Mooresville, NC, for the period 6/1/2005 to 12/28/2005; from Station
120 – Stockbridge, GA, for the period 1/1/2005 to 5/1/2007; from Station 150 - Mooresville, NC,
from 1/1/2005 to 5/1/2007; from Station 160 - Moore, SC, from 1/1/2005 to 5/1/2007; and from
Station 165 - Pittsylvania, VA, from 1/1/2005 to 5/1/2007.
Williams argued that the four questions on its Checklist were sufficient to eliminate internal
corrosion as a threat. The company maintained that its gas contained less than 7 lb/MMSCF
water vapor and therefore that internal corrosion was not a threat and an ICDA procedure
unnecessary. Respondent argued that the one Transco ECDA project referenced (0030 Harrison,
MP 1.59 to 1.9) was over 1,000 miles downstream from the Gulf, that the gas transported
through this HCA had gone through numerous scrubbers and compressors, and that gas-quality
data indicated that gas quality at the ECDA site was well within acceptable limits.
OPS countered that during its inspection, it had requested, but had not been provided,
documentation showing that the line had been dried out and liquid subsequently introduced.
OPS asserted that the unprocessed gas would have been introduced in Louisiana and that the
closest measurement provided was in South Carolina, more than 700 plus downstream from
where the gas came ashore. OPS asserted that this would not be considered adequate technical
justification to conclude that the pipeline system south of this location was free of liquids. OPS
asserted that Respondent had been transporting unprocessed gas for approximately six to seven
months, yet the company’s IM team lacked an accurate picture of what the operating conditions
were for that part of the system.
Accordingly, after considering all of the evidence and arguments, I find that Respondent violated
49 C.F.R. § 192.927(a) by failing to identify areas along its pipeline where water or other
electrolyte might be introduced during normal operation, to determine if internal corrosion were
likely to exist, and by failing to provide an analysis or justification for eliminating internal
corrosion as a threat .
35 The Threats Checklists included the following questions: 1) Has internal corrosion ever been found in this pipe
segment or a parallel segment operating under similar conditions within 100 miles of this HCA? 2) Is this segment
in a portion of the system where gas is ever expected to contain more than 7 lb/MMscf water vapor? 3) Has free
water ever been found in the station scrubbers located within 100 miles or less of this HCA? and 4) Are there other
issues to warrant an integrity assessment?
36 WGP IM Overview Chapter 8, Section 8.2.2; Internal Corrosion Threat Checklist, HCA 2436, MP 27.1 to 27.28;
Internal Corrosion Threat Checklist, HCA 2436, MP 27.29 to 27.72; Internal Corrosion Threat Checklist, HCA
2479, MP 27.1 to 27.28; Internal Corrosion Threat Checklist, HCA 2479, MP 27.29 to 27.72; Internal Corrosion
Threat Checklist, HCA 0030 Harrison, MP 1.59 to 1.9.



25
Item 11A: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(a), which states:
§ 192.935 What additional preventive and mitigative measures must an
operator take?
(a) General requirements. An operator must take additional measures
beyond those already required by Part 192 to prevent a pipeline failure and to
mitigate the consequences of a pipeline failure in a high consequence area. An
operator must base the additional measures on the threats the operator has
identified to each pipeline segment. (See §192.917) An operator must conduct,
in accordance with one of the risk assessment approaches in ASME/ANSI
B31.8S (incorporated by reference, see §192.7), section 5, a risk analysis of its
pipeline to identify additional measures to protect the high consequence area
and enhance public safety. Such additional measures include, but are not
limited to, installing Automatic Shut-off Valves or Remote Control Valves,
installing computerized monitoring and leak detection systems, replacing pipe
segments with pipe of heavier wall thickness, providing additional training to
personnel on response procedures, conducting drills with local emergency
responders and implementing additional inspection and maintenance programs.
Item 11A of the Notice alleged that Respondent violated 49 C.F.R. § 192.935(a) by failing to
take additional measures beyond those already required by Part 192 to prevent pipeline failures
and to mitigate the consequences of failures in HCAs. Specifically, it alleged that Williams
failed to take additional preventive and mitigative (P&M) measures required by its own IMP
Procedure 10.25.01.02, Performing WGP Risk Assessment and Threat Analysis, Section 9.
At the hearing, Respondent acknowledged that it had not provided documentation for additional
P&M measures it had implemented as of the date of the inspection. Respondent advised that it
had discussed additional measures with an SME, including the possibility of burying pipe deeper
than required and testing 100% of welds. Respondent also advised that it intended to inspect and
assess nearly 4,000 miles of pipeline by the end of 2007, far exceeding the approximate 700
miles required by the rule. The company further asserted that it had implemented or was already
doing many of the P&M measures listed in its Procedure 10.25.01, section 9, including: 1)
computerized monitoring with a SCADA system that continuously measured thousands of data
points and was manned 24 hours; 2) improved pipe design; 3) additional emergency response
training, including a web-based training module; 4) public education; and 5) increased
surveillance by inspecting pipeline via aircraft on a weekly basis.
OPS pointed out that the activities outlined by Williams were basic measures generally required
under 49 C.F.R. Part 192. OPS explained that the purpose of the Gas IMP rule was to require
additional P&M measures in higher-risk HCA areas.
After considering all the evidence and arguments, I find that Respondent’s explanation and
response to the allegation confirm the findings of the OPS inspection team that no additional
P&M activities had been undertaken or considered by the Respondent. I find that Respondent
violated 49 C.F.R. § 192.935(a) by failing to employ additional preventive and mitigative
measures to reduce risk of incidents in HCA areas, as required by the regulation and the
company’s own procedures.



26
Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 192.911, which states, in
relevant part:
§ 192.911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a
framework (see § 192.907) and evolves into a more detailed and
comprehensive integrity management program, as information is gained and
incorporated into the program. An operator must make continual
improvements to its program. The initial program framework and
subsequent program must, at minimum, contain the following elements.
(When indicated, refer to ASME/ANSI B31.8S (incorporated by reference,
see § 192.7) for more detailed information on the listed element.)
(a) . . .
(k) A management of change process as outlined in ASME/ANSI
B31.8S, section 11. . .
(m) A communication plan that includes the elements of ASME/ANSI
B31.8S, section 10, and that includes procedures for addressing safety
concerns raised by-
(1) OPS; and
(2) A State or local pipeline safety authority when a covered segment is
located in a State where OPS has an interstate agent agreement. . . .
Item 13C of the Notice alleged that Respondent violated 49 C.F.R. § 192.911(m) by failing to
have an IMP that included an internal communication procedure. Specifically, it alleged that
Williams’ IMP did not have a communication plan having the elements listed in the ASME
Standard, section 10.3.37
At the hearing, Respondent argued that both § 192.911(m) and section 10 of B31.8S required
operators merely to have an internal communication “plan,” not a “procedure,” as alleged in the
Notice. In support of it position, Respondent asserted that the ASME Standard states: “Operator
management and operations personnel must understand and support the integrity program.” The
company contended that its “Other Documentation” listed the methods it was using to comply
with the IMP requirements and that its internal communication plan was described in Chapter 12
of the IMP Overview. It further argued that a summary of its plan had been communicated on
the company’s WGP’s webpage and that, as an example of its internal communications, the
company’s president, Mr. Phil Wright, had declared on Williams’ intranet and at the end of
chapter 1 a commitment to the program. Finally, Respondent asserted that it had performed
comprehensive training on the company’s IMP for its operations personnel.
OPS responded by asserting that while Section 12.3 of the company’s IMP Overview stated that
“an internal communication process has been developed,
” no documented plan or procedure was
ever provided to the OPS Inspection Team, nor was one presented as evidence in this
proceeding. Section 10.3 of the ASME Standard states:
37 Item 13C in the Notice included a typographical error that improperly cited 49 C.F.R. § 192.911(k), instead of
§ 192.911(m); the latter requires that operators have a communication plan. Because both the substantive text of the
Notice and the operator’s Response treated Item 13C as an alleged violation of § 192.911(m), I find such error in the
Notice to be harmless.



27
10.3 Internal Communications
Operator management and other appropriate operator personnel must
understand and support the integrity management program. This should be
accomplished through the development and implementation of an internal
communications aspect of the plan. Performance measures reviewed on a
periodic basis and resulting adjustments to the integrity management program
should also be part of the internal communications plan.
According to this standard, an IMP needs to have an internal communications component that
includes “performance measures” and “resulting adjustments” that need to be made to the IMP
and how these will be communicated to company personnel. I fail to see that Williams has
presented any evidence demonstrating that it actually had developed or implemented any sort of
specific internal communications element as part of its IMP, as required by the ASME Standard.
Accordingly, upon a review of all of the evidence, I find that Respondent violated 49 C.F.R.
§ 192.911(m) by failing to develop an IMP with an internal communication plan that included
the elements of ASME Standard, section 10.3.
Item 13D of the Notice alleged that Respondent violated 49 C.F.R. § 192.911(m) by failing to
have an IMP that contained a communication plan that included procedures for addressing safety
concerns raised by OPS and state or local regulatory authorities. At the hearing, Respondent did
not contest this allegation. Accordingly, based upon a review of all of the evidence, I find that
Respondent violated 49 C.F.R. § 192.911(m).
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any
related series of violations. In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; the Respondent’s
ability to pay the penalty and any effect that the penalty may have on its ability to continue doing
business; and the good faith of Respondent in attempting to comply with the pipeline safety
regulations. In addition, I may consider the economic benefit gained from the violation without
any reduction because of subsequent damages, and such other matters as justice may require.
The Notice proposed a total civil penalty of $351,000 for the violations cited above.
Item 1A: The Notice proposed a civil penalty of $26,000 for Respondent’s violation of 49
C.F.R. §§ 192.947(d) and 192.905(a), for failing to describe and document in the company’s
IMP which method it applied to each portion of the its pipeline system to identify HCA
segments. The Notice also alleged that Williams failed to maintain records demonstrating
compliance with the integrity management regulations. As discussed above, I found that
Williams did not mention Northwest Pipeline in its description of the methods used prior to the
December 2004 Deadline, nor did the company provide OPS with proper documentation at the



28
time of the inspection. Maintaining such documentation of compliance with the integrity
management regulations is important to enable OPS to determine if a company is in compliance.
Without documentation to verify which method has been used to identify HCAs, it is nearly
impossible to verify that all HCAs have, in fact, been identified. Respondent has not produced
any evidence or put forth any argument that would warrant a reduction in the penalty.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $26,000 for the violation of 49 C.F.R. §§ 192.947(d) and
192.905(a).
Item 2A: The Notice proposed a civil penalty of $26,000 for Respondent’s violation of 49
C.F.R. § 192.905(a), for failing to describe in the company’s IMP which method it was applying
to each portion of its pipeline system to identify each HCA segment. The Notice also alleged
that the system maps and the GIS system used by Respondent failed to establish a suitable means
of documenting segment locations in HCAs. As discussed above, I found that Williams not only
failed to describe which methods it was applying to each portion of its system, but also found
that the company failed to take action to address known inaccuracies in its HCA identification
process and to describe the PIRs of the methods used to establish HCAs. If left uncorrected,
such an error would diminish the effectiveness of the other risk-based requirements imposed by
the IMP regulations and create a potential threat to public safety. Therefore, having reviewed the
record and considered the gravity of the violation and other assessment criteria, I assess
Respondent a civil penalty of $26,000 for the violation of 49 C.F.R. § 192.905(a).
Item 2B: The Notice proposed a civil penalty of $26,000 for Respondent’s violation of 49
C.F.R. § 192.905(b)(2), for failing to use certain alternative information in cases where public
officials with safety or emergency response or planning responsibilities had informed the
company that they did not have information delineating identified sites. As noted above, I found
that Williams failed to demonstrate that it had a process in place to use such alternative sources
by the December 2004 Deadline. There is no evidence in the record that contradicts the OPS
inspection report. Failure to identify those HCA segments having the highest potential for
failure by the deadline increased the risk of harm to the public. Accordingly, having reviewed
the record and considered the gravity of the violation and other assessment criteria, I assess
Respondent a civil penalty of $26,000 for the violation of 49 C.F.R. § 192.905(b)(2).
Item 3: The Notice proposed a civil penalty of $43,000 for Respondent’s violation of 49 C.F.R.
§ 192.907(a), for failing to meet the December 2004 Deadline for developing and following a
written IMP that contained all the elements described in § 192.911 and that addressed the risks
on each covered pipeline segment. As noted above, I found that that none of the documentation
submitted by Respondent during the hearing or in the Closing demonstrated that it had
determined any identified sites prior to the December 2004 Deadline. Respondent objected to
the proposed civil penalty for this Item, contending that the gravity of the violation was minimal,
that it had made a good-faith effort to comply with the IMP regulations, and that it had an
ongoing commitment to structure identification along the pipeline. On the contrary, I find that
mitigation of the civil penalty is not warranted. Williams asserted that it made a good-faith
effort to comply with the regulation, yet I can find no evidence in the record that the company
made a concerted effort to complete a rigorous HCA identification process by the December
2004 Deadline. Respondent has not provided any evidence that would justify mitigation of the
proposed civil penalty. Therefore, having reviewed the record and considered the gravity of the



29
violation and the other assessment criteria, I assess Respondent a civil penalty of $43,000 for
violation of 49 C.F.R. § 192.907(a).
Item 4A: The Notice proposed a civil penalty of $43,000 for Respondent’s violation of 49
C.F.R. § 192.905(a), for failing to properly establish HCA areas using Method 1 from the
definition of “HCA” in § 192.903. As noted above, I found that Williams failed to properly
identify all HCAs using Method 1 and that its HCA boundaries were shorter than the Class 3 and
Class 4 dimensions required under § 192.903. As a result, the HCA sites referenced in the
Notice did not have the correct length of pipe within their boundaries. Properly identifying
HCAs is important in mitigating the consequences of pipeline failures in HCAs and reducing the
risk of harm to the public. Accordingly, having reviewed the record and considered the gravity
of the violation and other assessment criteria, I assess Respondent a civil penalty of $43,000 for
violation of 49 C.F.R. § 192.905(a).
Item 4B: The Notice proposed a civil penalty of $43,000 for a separate violation of 49 C.F.R.
§ 192.905(a), for failing to properly establish HCA areas using Method 1 from the definition of
“HCA” in § 192.903. Specifically, the Notice alleged that the OPS inspection revealed sites on
the Transco system that met the definition of “Identified sites” in § 192.903 but had not been
included among the system’s HCAs. Despite the fact that the company’s own documentation
showed sites that appeared to qualify as HCAs, I found that the company had failed to actually
identify where Method 1 called for the inclusion of Class 1 or Class 2 locations. Such omissions
results in a greater risk of harm to the public in those areas where Respondent failed to
adequately identify HCAs. Having reviewed the record and considered the gravity of the
violation and other assessment criteria, I assess Respondent a civil penalty of $43,000 for
violation of 49 C.F.R. § 192.905(a).
Item 4C: The Notice proposed a civil penalty of $26,000 for another violation of 49 C.F.R.
§ 192.905(a), for failing to properly identify HCA areas using Method 1 from the definition of
“HCA” under § 192.903. Specifically, it alleged that Williams improperly applied Method 1 by
failing to designate certain outdoor areas and buildings as “Identified sites.” As noted above, I
found that the company improperly applied the term “day” for purposes of identifying outdoor
areas as HCAs, with the result that certain areas were improperly omitted as HCAs. Having
reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of
$26,000 for violation of 49 C.F.R. § 192.905(a).
Item 4D: The Notice proposed a civil penalty of $43,000 for Respondent’s violation of 49
C.F.R. § 192.905(a), for failing to apply the axial extension of the potential impact circle along
the length of the pipeline from the outermost edge of the first potential impact circle containing
either an identified site or 20 or more buildings intended for human occupancy to the outermost
edge of the last contiguous potential impact circle containing either an identified site or 20 or
more buildings intended for human occupancy. Respondent contended that a mitigating factor
contributing to the abbreviated length of the HCAs was that paragraph 3 of the definition of a
“High Consequence Area” in § 192.903 was actually missing from the 2004, 2005, and 2006
Code of Federal Regulation (CFR) books. I find that even if the wrong version of § 192.903
were, in fact, published in the CFR, it still does not justify Respondent’s failure to comply with
the regulation or mitigate the seriousness of the offense. If left uncorrected, the failure to
properly identify HCAs diminishes the effectiveness of other risk-based requirements imposed
by the IMP regulations and creates a potential threat to public safety. Having reviewed the



30
record and considered the gravity of the violation and other assessment criteria, I assess
Respondent a civil penalty of $43,000 for violation of 49 C.F.R. § 192.905(a).
Item 5A: The Notice proposed a civil penalty of $15,000 for Respondent’s violation of 49
C.F.R. § 192.917(e)(4) for failing to have a procedure in place to verify that the selected
assessment method(s) are proven to be capable of assessing seam integrity and detecting seam
corrosion. As discussed above, I found that Respondent failed to meet the minimum
requirements of the ASME Standard or to provide a rigorous risk analysis process that could
determine whether an actual threat existed from ERW pipe. Respondent argued that the penalty
for this Item should be withdrawn. Although Williams failed to have an adequate procedure in
place, OPS agrees that the violation is adequately addressed through a compliance order.
Accordingly, the proposed civil penalty for Item 5A is withdrawn.
Item 5B: The Notice proposed a civil penalty of $15,000 for Respondent’s violation of 49
C.F.R. § 192.917(b) for failing to identify and evaluate the potential threats to a covered pipeline
segment by gathering and integrating existing data and information on the entire pipeline that
could be relevant to the covered segment. As discussed above, I found that Williams lacked
adequate processes for verifying data quality or for applying conservative assumptions if data
were missing or suspect. Respondent argued that the penalty for this Item should be withdrawn.
Although the company failed to have adequate processes in place, OPS agrees that the violation
is adequately addressed through a compliance order. Accordingly, the proposed civil penalty for
Item 5B is withdrawn.
Item 5D: The Notice proposed a civil penalty of $15,000 for Respondent’s violation of 49
C.F.R. § 192.917(b) for failing to have adequate processes in its IMP for verifying data quality.
As discussed above, I found that Williams failed either to properly verify data or apply
conservative assumptions if data were missing or suspect. Respondent argued that the penalty
for this Item should be withdrawn. Although the company failed to have adequate processes in
place, OPS agrees that the violation is adequately addressed through a compliance order.
Accordingly, the proposed civil penalty for Item 5D is withdrawn.
Item 6B: The Notice proposed a civil penalty of $6,000 for Respondent’s violation of 49 C.F.R.
§ 192.921(d), for failing to prioritize all its covered pipeline segments for the baseline
assessment in such a manner that its assessment schedule could be properly verified. During the
hearing, Respondent conceded that the allegation was true. Accordingly, having reviewed the
record and considered the assessment criteria, I assess Respondent a civil penalty of $6,000 for
violation of 49 C.F.R. § 192.921(d).
Item 7: The Notice proposed a civil penalty of $6,000 for Respondent’s violation of 49 C.F.R.
§ 192.907(b), for failing to follow the requirements of this subpart and of the ASME Standard
and its appendices to identify and evaluate all potential threats to each covered pipeline segment.
As noted above, I found that Respondent failed to properly identify and evaluate all potential
threats to each covered pipeline segment by the December 2004 Deadline. The risk model used
by Williams failed to satisfy all of the requirements of the regulation, For example, the model
eliminated SCC as a threat, but without engineering data to confirm that SCC did not exist as a
threat or that it had been considered under the SME approach. Furthermore, the record shows
that the company had suffered a number of leaks and failures attributed to SCC in the past.



31
An effective integrity management program depends upon the use of risk models that are
comprehensive and accurate in their consideration of all threats applicable to a particular pipeline
system. The risk model used in this case failed to meet the ASME Standard. Respondent has
failed to present any evidence that would warrant a reduction in the proposed penalty.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $6,000 for violation of 49 C.F.R. § 192.907(b).
Item 8A: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49 C.F.R.
§ 192.925(b) for failing to use direct assessment to assess the threat of external corrosion in
accordance with the ASME Standard, section 4.2, and the NACE Standard, section 3.2. As
discussed above, I found that Williams failed to follow these standards and its own ECDA
procedures for pre-assessment, indirect examination, direct examination, and post-assessment.
Respondent has failed to present any evidence that would warrant a reduction in the amount of
the proposed penalty. Accordingly, having reviewed the record and considered the assessment
criteria, I assess Respondent a civil penalty of $3,000 for violation of 49 C.F.R. § 192.925(b).
Item 8B: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49 C.F.R.
§ 192.925(b)(1) to follow its ECDA Procedure 20.19.01.02, sections 3.1.1 and 3.1.2, to conduct
feasibility assessments for each ECDA performed. It is irrelevant that Respondent retroactively
determined that ECDA was applicable. The NACE guidelines are clear that a feasibility study is
required prior to conducting the assessment as does Respondent’s procedures. Accordingly,
having reviewed the record and considered the assessment criteria, I assess Respondent a civil
penalty of $3,000 for violation of 49 C.F.R. § 192.925(b)(1).
Item 8I: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49 C.F.R.
§ 192.925(b)(3) for failing to have ECDA procedures that follow NACE RP0502 for all required
excavations. Respondent advised that it had revised its ECDA Procedure 20.19.01.02 to clarify
the required number of digs and to meet or exceed those stated in NACE RP 0502. The fact that
Respondent had changed its procedure and had scheduled additional digs further support a
finding of violation. Respondent has failed to present any evidence that would warrant a
reduction in the amount of the proposed penalty. Accordingly, having reviewed the record and
considered the assessment criteria, I assess Respondent a civil penalty of $3,000 for violation of
49 C.F.R. § 192.925(b)(3).
Item 11A: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49
C.F.R. § 192.935(a) for failing to employ additional preventive and mitigative measures to
reduce risk of incidents in HCA areas, as required by the regulation and Respondent’s
procedures. An operator must provide protection for pipeline segments to prevent a pipeline
failure and to mitigate the consequences of failures in HCAs. Respondent has failed to present
any evidence that would warrant a reduction in the amount of the proposed penalty.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $3,000 for violation of 49 C.F.R. § 192.935(a).
Item 13C: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49
C.F.R. § 192.911(m) for failing to include in its management of change process, as outlined in
the ASME Standard, section 10.3, procedures on when, where, and how information is internally
communicated. Whatever information an operator relies on to constitute compliance with the
integrity management requirements, the operator must provide sufficient detail to demonstrate



32
compliance so that OPS cannot readily determine what those documents are and where they
might be located. Accordingly, having reviewed the record and considered the assessment
criteria, I assess Respondent a civil penalty of $3,000 for violation of 49 C.F.R. § 192.911(m).
Item 13D: The Notice proposed a civil penalty of $3,000 for Respondent’s violation of 49
C.F.R. § 192.911(m) for failing to have procedures for addressing safety concerns raised by
PHMSA and local regulatory authorities. At the hearing, Respondent did not dispute this
allegation. Accordingly, having reviewed the record and considered the assessment criteria, I
assess Respondent a civil penalty of $3,000 for violation of 49 C.F.R. § 192.911(m).
In summary, having reviewed the record and considered the assessment criteria for all the Items
above, I assess Respondent a total civil penalty of $306,000.
Respondent has provided no information that indicates payment of this penalty would adversely
affect its ability to continue in business.
Payment of the civil penalty must be made within 20 days of service. Federal regulations
(49 C.F.R. § 89.21(b)(3)) require this payment be made by wire transfer, through the Federal
Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed
instructions are contained in the enclosure. Questions concerning wire transfers should be
directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike
Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, OK 73125; (405) 954-8893.
Failure to pay the $306,000 civil penalty will result in accrual of interest at the current annual
rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a United
States District Court.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 5A, 5B, 5D, 6B, 7, 8I, 8K, 9A,
13C and 13D in the Notice for violations of 49 C.F.R. §§ 192.917(e)(4), 192.917(b), 192.917(b),
192.921(d), 192.907(b), 192.925(b)(3), 192.925(b)(4), 192.927(a), 192.911(m), and 192.911(m),
respectively.
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns
or operates a pipeline facility is required to comply with the applicable safety standards
established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R.
§ 190.217, Respondent is ordered to take the following actions to ensure compliance with the
pipeline safety regulations applicable to its operations:
1. With respect to the violation of § 192.917(e)(4) (Item 5A), Respondent must
conduct a study of all pipeline segments located within each HCA to
determine if it contains any pipe meeting the criteria set forth in



33
§ 192.917(e)(4). This study must evaluate any covered or non-covered
segment in the pipeline system having such pipe and that has experienced
seam failure or that the operating pressure pipe on the covered segment has
experienced an increase over the maximum operating pressure during the
preceding five years.
2. With respect to the violation of § 192.917(b) (Item 5B), Respondent must
perform a complete data integration of all known information about the entire
Northwest and Transco Pipeline systems in conjunction with each HCA area.
3. With respect to the violation of § 192.917(b) (Item 5D), Respondent must
define and justify any conservative assumptions made during its risk analysis
process. Respondent must also develop a program and process to obtain
missing data for future risk analysis determinations.
4. With respect to the violation of § 192.921(d) (Item 6B), Respondent must
conduct its initial HCA identification process all over again, using revised
procedures produced pursuant to this Final Order.
5. With respect to the violation of § 192.907(b) (Item 7), Respondent must
conduct a completely new risk analysis, using a new risk model that considers
all risks factors applicable to each HCA segment.
6. With respect to the violation of § 192.925(b)(3) (Item 8I), Respondent must
re-examine all of its ECDA projects and conduct all of the excavations
required by Part 192.
7. With respect to the violation of § 192.925(b)(4) (Item 8K), Respondent must
re-evaluate and re-calculate the remaining life for each corrosion anomaly
based on the correct values. Williams must then determine if any additional
excavations are required and report the number of increased excavations to
PHMSA.
8. With respect to the violation of § 192.927(a) (Item 9A), Respondent must
develop an ICDA plan and process to evaluate the threat of internal corrosion.
In addition, Williams must either conduct an assessment for ICDA on all areas
where ECDA has been used or is planned to be used, or develop a sound
technical justification for each HCA area describing why internal corrosion is
not a threat.
9. With respect to the violation of § 192.911(m) (Item 13C), Respondent must
develop a communication plan meeting the requirements of the ASME
Standard, section 10.3.
10. With respect to the violation of § 192.911(m) (Item 13D), Respondent must
develop a communication plan that includes a process for handling requests
and addressing safety concerns raised by PHMSA and local regulatory
authorities.



34
11. Within 60 days of receipt of this Final Order, Williams must complete the
work required compliance terms in paragraphs 1-10 above.
12. Respondent is requested to maintain documentation of the safety improvement
costs associated with fulfilling this Compliance Order and submit the total to
Chris Hoidal, Director, Western Region, Pipeline and Hazardous Materials
Safety Administration, 12300 W. Dakota Avenue, Suite 110, Lakewood, CO
80228. It is requested that these costs shall be reported in two categories: 1)
total cost associated with preparation/revision of plans, procedures, studies
and analyses, and 2) total costs associated with replacement, additions and
other changes to pipeline infrastructure.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent demonstrating good cause for an extension.
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $100,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
WARNING ITEMS
With respect to Items 5C, 6A, 8C, 8D, 8E, 8F, 8G, 8H, 8J, 10, 11B, 12, 13A, and 13B, the Notice
alleged probable violations of Part 192 but did not propose a civil penalty or compliance order
for these items. Therefore, these are considered to be warning items. The warnings were for:
49 C.F.R. § 192.917(b) (Notice Item 5C) ─ Respondent’s alleged failure to have
defined processes for assigning responsibilities for data collection or how data
sets are assembled, how their accuracy is verified, how data is maintained, or
what sets of data must be collected; and
49 C.F.R. § 192.921(b) (Notice Item 6A) ─ Respondent’s alleged failure to
prioritize covered pipeline segments for the baseline assessment according to a
risk analysis that considers the potential threats to each covered segment.
Respondent’s BAP has several segments at the bottom of the prioritization
schedule that have not been analyzed for risk; and
49 C.F.R. § 192.925(b)(1) (Notice Item 8C) ─ Respondent’s alleged failure to
maintain and provide documentation on the indirect inspection tool selective
criteria. Tool selection followed ECDA region determinations, rather than
preceding them.
49 C.F.R. § 192.925(b)(1)(ii) (Notice Item 8D) ─ Respondent’s alleged failure to
use a NACE-recognized assessment tool for ECDA indirect inspections.
49 C.F.R. § 192.925(b)(1)(ii) (Notice Item 8E) ─ Respondent’s alleged failure to
follow its own ECDA procedures specifying that casings and other areas are



35
separate regions. Specifically, in one of the ECDAs reviewed (1400 line, Glenn’s
Ferry), a cased crossing was part of the single ECDA region, along with road
crossings and other areas.
49 C.F.R. § 192.925(b)(1)(i) (Notice Item 8F) ─ Respondent’s alleged failure to
include and document in its ECDA Procedures 20.19.01.02 a requirement that
initial ECDA assessments include more restrictive criteria for the initial pre-
assessment conducted.
49 C.F.R. § 192.925(b)(2) (Notice Item 8G) ─ Respondent’s alleged failure to
provide documentation in its completed assessments that the start and finish of
each ECDA region is properly marked and the amount of overlap for each tool.
49 C.F.R. § 192.925(b)(2) (Notice Item 8H) ─ Respondent’s alleged failure to
follow its own ECDA Procedure 20.19.01.02, section 5.1.4, requiring that indirect
inspection results be integrated with other data obtained in the pre-assessment
process, such as encroachments and foreign line crossings.
49 C.F.R. § 192.925(b)(3)(iii) (Notice Item 8J) ─ Respondent’s alleged failure to
provide documentation that internal notifications were made based on the results
of what was learned in the ECDA projects completed as of January 29, 2007.
49 C.F.R. § 192.937(b) (Notice Item 10) ─ Respondent’s alleged failure to
complete an annual review to determine the reassessment interval of completed
baseline assessments, as required by Respondent’s own procedures.
49 C.F.R. § 192.935(c) (Notice Item 11B) ─ Respondent’s alleged failure to
delineate a process for evaluating the potential safety impact on individual
covered segments of installing automatic shut-off valves and remote control
valves.
49 C.F.R. § 192.909(a) (Notice Item 12) ─ Respondent’s alleged failure to
include in its IMP change log a detailed description of changes made to its IMP.
49 C.F.R. § 192.911(k) (Notice Item 13A) ─ Respondent’s alleged failure to
report to its IMP team important system changes that could affect pipeline
integrity. In a teleconference with the Transco Operations Center, Respondent
indicated that the process equipment was taken out of service due to damage from
Hurricane Katrina and unprocessed gas was being introduced into the Transco
pipeline system that may exceed the water quantity limits.
49 C.F.R. § 192.911(k), the ASME Standard, section 11(d) (Notice Item 13B) ─
Respondent’s alleged failure to follow its own MOC Procedure 10.29.01.02, that
required an approval process for startups/changes.
Respondent presented information in its Response showing that it had taken certain actions to
address the cited items. Having considered such information, I find, pursuant to 49 C.F.R.



36
§ 190.205, that probable violations of 49 C.F.R. § 192.917(b) (Notice Item 5C), 49 C.F.R.
§ 192.921(b) (Notice Item 6A), 49 C.F.R. § 192.925(b)(1) (Notice Item 8C), 49 C.F.R.
§ 192.925(b)(1)(ii) (Notice Item 8D), 49 C.F.R. § 192.925(b)(1)(ii) (Notice Item 8E), 49 C.F.R.
§ 192.925(b)(1)(i) (Notice Item 8F), 49 C.F.R. § 192.925(b)(2) (Notice Item 8G), 49 C.F.R.
§ 192.925(b)(2) (Notice Item 8H), 49 C.F.R. § 192.925(b)(3)(iii) (Notice Item 8J), 49 C.F.R.
§ 192.937(b) (Notice Item 10), 49 C.F.R. § 192.935(c) (Notice Item 11B), 49 C.F.R.
§ 192.909(a) (Notice Item 12), 49 C.F.R. § 192.911(k) (Notice Item 13A) and 49 C.F.R.
§ 192.911(k) (Notice Item 13B) have occurred and Respondent is hereby advised to correct such
conditions. In the event that OPS finds a violation for any of these items in a subsequent
inspection, Respondent may be subject to future enforcement action.
Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC
20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA
will accept petitions received no later than 20 days after receipt of service of this Final Order by
the Respondent, provided they contain a brief statement of the issue(s) and meet all other
requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of
any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all
other terms and conditions of this Final Order are effective upon service in accordance with 49
C.F.R. § 190.5.
___________________________________ __________________________
Jeffrey D. Wiese Date Issued
Associate Administrator
for Pipeline Safety

520071001_ notice letter_01292007_text.pdf

U. S. Department
of Transportation
Pipeline and
Hazardous Materials Satety
Administration
12300 W Dakota Ave, Sutta 110
Lakewood, CO 80228
SENT TO COMPLIANCE REGISTRY
Hardcopy Electronicallg~
0 of Copies l / Date M
NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT RE UESTED
January 29, 2007
Mr. Randy Barnard
VP Operations and Gas Control
Williams Gas Pipeline
2800 Post Oak Blvd
P. O. Box 1396
Houston, TX 77056
CPF 5-2007-1001
Dear Mr. Barnard:
On March 13-17 and March 27 — 30, 2006, a representative of the Pipeline and Hazardous
Materials Safety Administration {PHMSA) pursuant to Chapter 601 of 49 United States Code
inspected your Integrity Management Program in Salt Lake City, Utah.
As a result of the inspection, it appears you have committed probable violations of the Pipeline
Safety Regulations, Title 49, Code of Federal Regulations The items inspected and the probable
violation{s) are:
$192. 947%'hat records must an operator keep?
)192. 947 {d) Documents to support any decision, analysis and process developed and
used to implement and evaluate each element of the baseline assessment plan and
integrity management program. Documents include those developed and used in
support of any identification, calculation, amendment, modification, justification,
deviation and determination made, and any action taken to implement and evaluate
any of the program elements;



$192. 905 (a) General. To determine which segments of an operator's transmission
pipeline system are covered by this subpart, an operator must identify the high
consequence areas. An operator must use method (1) or (2) from the definition in g
192. 903 to identify a high consequence area. An operator may apply one method to
its entire pipeline system, or an operator may apply one method to individual
portions of the pipeline system. An operator must describe in its integrity
management program which method it is applying to each portion of the operator's
pipeline system. The description must include the potential impact radius when
utilized to establish a high consequence area. (See appendix K. I. for guidance on
identifying high consequence areas. )
~ Item 1A: $192. 947(d) A $192. 905 (a)
At the time of inspection documentation demonstrating what methods were used for
identification of each HCA segment was not available [A. Ol. b]
Evidence: Williams did not produce documents demonstrating the method used for
identification of each HCA.
$192. 905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator's transmission pipeline
system are covered by this subpart, an operator must identify the high consequence
areas. An operator must use method (1) or (2) from the definition in g 192. 903 to
identify a high consequence area. An operator may apply one method to its entire
pipeline system, or an operator may apply one method to individual portions of the
pipeline system. An operator must describe in its integrity management program
which method it is applying to each portion of the operator's pipeline system. The
description must include the potential impact radius when utilized to establish a high
consequence area. (See appendix E. I. for guidance on identifying high consequence
areas. )
(b)(1) Identified sites. . .
(2) If a public official with safety or emergency response or planning responsibilities
informs an operator that it does not have the information to identify an identified
site, the operator must use one of the following sources, as appropriate, to identify
these sites.
(i) Visible marking (e. g. ,
a sign); or
(ii) The site is licensed or registered by a Federal, State, or local government
agency; or
(iii) The site is on a list (including a list on an internet web site) or map
maintained by or available from a Federal, State, or local government agency
and available to the general public.



~ Item 2A: )Part 192. 905 {a)
System maps and the GIS system used by WGP have not established a suitable means of
documenting segment locations in high consequence areas. WGP has indicated that
pipeline location accuracy ranges from survey quality up to +I- 40 feet WGP has not
taken action to address these known inaccuracies in its HCA identification process which
could lead to existing HCAs not being identified. No additional buffers have been
considered to account for potential pipeline location inaccuracies. Quality assurance
methods are not defined for assuring collected data is accurately integrated mto either the
GIS or onto HCA identification alignment sheets. [A. Ol. c]
Evidence: WGP IMP Overview Chapter 4, High Consequence Areas, Appendix A
~ Item 2B: )Part 192. 905 (b)(2)
In the absence of public official input, the operator must use one of the following in order
to identify an identified site: 1) Visible markings such as signs, 2) Facility licensing or
registration data on file with Federal, State, or local government agencies, or 3) Lists or
maps maintained by or available from a Federal, State, or local government agency and
available to the general public. However, WGP has not used these other sources of
information in support of the December 17, 2004 deadline for locating identified sites,
Additionally, WGP does not have procedures governing the performance of locating
identified sites using these types of other sources mformation. [A. 03 b]
Evidence: WGP' s IM procedure 10. 09. 01. 10, Establishing Class and HCA Location,
Section 8. 1. 10
3. $192. 907 What must an operator do to implement this subpart?
$192. 907 (a) General. No later than December 17, 2004, an operator of a covered
pipeline segment must develop and follow a written integrity management program
that contains all the elements described in g 192. 911 and that addresses the risks on
each covered transmission pipeline segment. The initial integrity management
program must consist, at a minimum, of a framework that describes the process for
implementing each program element, how relevant decisions will be made and by
whom, a time line for completing the work to implement the program element, and
how information gained from experience will be continuously incorporated into the
program. The framework will evolve into a more detailed and comprehensive
program. An operator must make continual improvements to the program.
~ Item 3A: $192. 907{a)
The rule requires that HCA identification be completed by December 17, 2004. However,
certain activities necessary to comply with this completion date were not initiated until
Spring 2005. The HCA identification process to locate identified sites in Class I and II



locations (Method l) was still ongoing as of April and May 2005. Public officials were
not contacted for the location of identified sites until April 2005. Follow-up activities
required to be taken in the event that public officials do not provide identified site
information using other required sources does not appear to have been undertaken.
[A. Ol. d]
Evidence: Letter to Emergency Responder, 3/2005 (First issuance of this letter)
4. $192. 905 How does an operator identify a high consequence area?
$192. 905 (a) General. To determine which segments of an operator's transmission pipeline
system are covered by this subpart, an operator must identify the high consequence areas.
An operator must use method (1) or (2) from the definition in $192. 903 to identify a high
consequence area. An operator may apply one method to its entire pipeline system, or an
operator may apply one method to individual portions of the pipeline system. An operator
must describe in its integrity management program which method it is applying to each
portion of the operator's pipeline system. The description must include the potential impact
radius when utilized to establish a high consequence area. (See appendix K. I. for guidance
on identifying high consequence areas. )
$192. 903 What definitions apply to this subpart?
The following definitions apply to this subpart:
Assessment is the use of testing techniques as allowed in this subpart to ascertain the
condition of a covered pipeline segment.
Confirmatory direct assessment is an integrity assessment method using more focused
application of the principles and techniques of direct assessment to identify internal and
external corrosion in a covered transmission pipeline segment.
Covered segment or covered pipeline segment means a segment of gas transmission pipeline
located in a high consequence area. The terms gas and transmission line are defined in g
192. 3.
Direct assessment is an integrity assessment method that utilizes a process to evaluate
certain threats (i. e.
,
external corrosion, internal corrosion and stress corrosion cracking) to
a covered pipeline segment's integrity. The process includes the gathering and integration of
risk factor data, indirect examination or analysis to identify areas of suspected corrosion,
direct examination of the pipeline in these areas, and post assessment evaluation.
High consequence area means an area established by one of the methods described in
paragraphs {1) or {2) as follows:
(1) An area defined as-
{i) A Class 3 location under $192. 5; or



(ii) A Class 4 location under $192. 5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is
greater than 660 feet (200 meters), and the area within a potential impact circle
contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle
contains an identified site.
(2) The area within a potential impact circle containing-
(i) 20 or more buildings intended for human occupancy, unless the exception in
paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either method (1) or (2) to
establish a high consequence area, the length of the high consequence area extends
axially along the length of the pipeline from the outermost edge of the first potential
impact circle that contains either an identified site or 20 or more buildings intended for
human occupancy to the outermost edge of the last contiguous potential impact circle
that contains either an identified site or 20 or more buildings intended for human
occupancy. (See Figure E. I. A. in appendix E. )
(4) If in identifying a high consequence area under paragraph (1)(iii) of this definition
or paragraph (2)(i) of this definition, the radius of the potential impact circle is greater
than 660 feet (200 meters), the operator may identify a high consequence area based on
a prorated number of buildings intended for human occupancy within a distance 660
feet (200 meters) from the centerline of the pipeline until December17, 2006. If an
operator chooses this approach, the operator must prorate the number of buildings
intended for human occupancy based on the ratio of an area with a radius of 660 feet
{200 meters) to the area of the potential impact circle (i. e.
,
the prorated number of
buildings intended for human occupancy is equal to [20 x (660 feet [or 200 meters ]/
potential impact radius in feet [or meters])**2]).
Identified site means each of the following areas:
{a) An outside area or open structure that is occupied by twenty (20) or more persons
on at least 50 days in any twelve (12)-month period. (The days need not be
consecutive. ) Examples include but are not limited to, beaches, playgrounds,
recreational facilities, camping grounds, outdoor theaters, stadiums, recreational areas
near a body of water, or areas outside a rural building such as a religious facility; or
{b) A building that is occupied by twenty {20) or more persons on at least five {5) days
a week for ten (10) weeks in any twelve (12)- month period. (The days and weeks need
not be consecutive. ) Examples include, but are not limited to, religious facilities, office
buildings, community centers, general stores, 4-H facilities, or roller skating rinks; or
(c) A facility occupied by persons who are confined, are of impaired mobility, or would
be difficult to evacuate. Examples include but are not limited to hospitals, prisons,
schools, day-care facilities, retirement facilities or assisted-living facilities.
Potential impact circle is a circle of radius equal to the potential impact radius (PIR).



Potential impact radius (PIR) means the radius of a circle within which the potential failure
of a pipeline could have significant impact on people or property. PIR is determined by the
formula r = 0. 69* (square root of (p*d Qh)), where 'r' is the radius of a circular area in feet
surrounding the point of failure, 'p' is the maximum allowable operating pressure (MAOP)
in the pipeline segment in pounds per square inch and 'd' is the nominal diameter of the
pipeline in inches.
Note: 0. 69 is the factor for natural gas. This number will vary for other gases depending
upon their heat of combustion. An operator transporting gas other than natural gas must
use section 3. 2 of ASME/ANSI B31. 8S-2001 (Supplement to ASME B31. 8; ibr, see g 192. 7)
to calculate the impact radius formula.
Remediation is a repair or mitigation activity an operator takes on a covered segment to
limit or reduce the probability of an undesired event occurring or the expected
consequences from the event.
~ Item 4A: )Part 192. 903 High consequence area means an area established by one of
the methods described in paragraphs (1) or (2) as follows: (1)
Method 1 used on the Transco system was applied incorrectly in that the full length of
Class 3 and. 4 locations have not been included in HCA boundaries. [A. 04. a]
Evidence: Alignment Sheet, Location Class Determination and Qualification Record, MP
1782. 125 to 1783. 750, Somerset and Middlesex Counties, NJ Main Line, DOT-NJ-8.
~ Item 4B: )Part 192. 903 High consequence area means an area established by one of
the methods described in paragraphs (1) or (2) as follows: (1)(iv)
The IMP rule requires that a high consequence area be established for areas in Class 1 and
Class 2 piping locations where the potential impact circle contains an identified site. Field
personnel were tasked with collectmg mformation on identified sites prior to being trained
on the requirements. Field personnel were not trained until April to June of 2005 For the
Transco system (MD, VA k, NJ), documentation showed apparent identified sites that
were not included in the HCAs. The reviews for HCAs on some of the Transco areas were
not started until the March of 2005 timeframe. [A. 04. c]
Evidence: Alignment Sheet, Location Determination and Pipeline Qualification Record,
MP 1408. 000 to 1410 87, Pittsylvania County, VA, Main Line, DOT-V-9
Alignment Sheet, Location Determination and Pipeline Qualification Record, MP
1457. 375 to 1459. 375, Appomattox, VA, Main Line, DOT-V-25B
~ Item 4C: $192, 903 Identified site means each of the following areas: (a) dk, (b)
WGP IMP Overview Chapter 4, Section 4. 8 defines a day as a continuous 8-hour period
when analyzing structures to determine if they qualify as identified sites. For example a
picnic area would have to sustain 20 or more persons on site for 8 hours a day, 5 days a
week, and 10 weeks in any 12 month period. This definition of a day is inconsistent with
rule requirements as the 20 or more persons criteria applies to their presence at a location
at any point in time. [A. 03. a]



Evidence: WOP IMP Overview Chapter 4, High Consequence Areas, Section 4. 8
~ Item 4D: $192. 903 High consequence area means an area established by one of the
methods described in paragraphs (1) or (2) as follows: (3)
HCAs defined for the Northwest Gas system do not include the axial extension of the
potential impact circle along the length of the pipeline from the outermost edge of the first
potential impact circle that contains either an identified site or 20 or more buildings
intended for human occupancy to the outermost edge of the last contiguous potential
impact circle that contains either an identified site or 20 or more buildings intended for
human occupancy (e. g. ,
HCA 1401 Ft Lewis to Sumner MP 1346. 844 — GIS shows HCA
length as 0. 174 miles but if axial extension is considered the length is 0. 42 miles).
[A. 02. b]
Evidence: WOP's procedure 10. 19. 01. 10, Establishing Class and HCA Locations,
Section 8. 1. 5
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1401
Northwest Pipeline HCA list — HCA 1401 MP1346. 844 (shows length as . 7 miles)
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Lava Hot Springs to Pocatello, MP 591. 9958 to 592. 6174
OIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Soda Springs to Lava Hot Springs, MP 541. 1691 to 541. 7532
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Soda Springs to Lava Hot Springs, MP 542. 6616 to 542 9956
GIS overview showing covered segment length of HCA, Northwest Pipehne, Line 1400—
Lava Hot Springs to Pocatello, MP 573. 3549 to 573. 917
OIS overview showing covered segment length of HCA, Northwest Pipehne, Line 1400—
Lava Hot Springs to Pocatello, MP 590. 8329 to 591. 1995
5. $192. 917 How does an operator identify potential threats to pipeline integrity and use
the threat identification in its integrity program?
(a) Threat identification. . .
(b) Data gathering and integration. To identify and evaluate the potential threats to a
covered pipeline segment, an operator must gather and integrate existing data and
information on the entire pipeline that could be relevant to the covered segment. In
performing this data gathering and integration, an operator must follow the requirements
in ASME/ANSI B31. SS, section 4. At a minimum, an operator must gather and evaluate the
set of data specified in Appendix A to ASME/ANSI B31. SS, and consider both on the
covered segment and similar non-covered segments, past incident history, corrosion control
records, continuing surveillance records, patrolling records, maintenance history, internal
inspection records and all other conditions specific to each pipeline. . .
(e) Actions to address particular threats. If an operator identifies any of the following
threats, the operator must take the following actions to address the threat.
7



(1) Third party damage. . .
(4) ERW pipe. If a covered pipeline segment contains low frequency electric resistance
welded pipe (ERW), lap welded pipe or other pipe that satisfies the conditions specified
in ASME/ANSI B31. 8S, Appendices A4. 3 and A4. 4, and any covered or noncovered
segment in the pipeline system with such pipe has experienced seam failure, or
operating pressure on the covered segment has increased over the maximum operating
pressure experienced during the preceding five years, an operator must select an
assessment technology or technologies with a proven application capable of assessing
seam integrity and seam corrosion anomalies. The operator must prioritize the covered
segment as a high risk segment for the baseline assessment or a subsequent
reassessment
~ Item 5A: $192. 917(e)(4)
WGP does not have procedures to evaluate if a covered pipeline segment contains low
frequency electric resistance welded pipe {ERW), lap welded pipe, or other pipe that
satisfies the conditions specified in ASME B31. 8S-2001, Appendix A4, 3 and ASME
B31. 8S-2001, Appendix A4. 4, and any covered or non-covered segment in the pipeline
system with such pipe has experienced seam failure, or operating pressure on the covered
segment has increased over the maximum operating pressure experienced during the
preceding five years. Procedures are not in place to verify that the selected assessment
method{s) are proven to be capable of assessing seam integrity and detectmg seam
corrosion anomalies. [B. 01. d]
Evidence: Procedure 10. 25. 01. 02, Performing WGP Risk Assessment and Threat
Analysis, Section 7. 1. 1 and Procedure 70. 17. 01. 16, Pigging — Inline Inspection
~ Item 5B: $192. 917(b)
The rule requires that individual data elements be brought together and analyzed in their
context such that the integrated data can provide improved confidence with respect to
determining the relevance of specific threats and can support an improved analysis of
overall risk. However, this required data mtegration has not occurred WGP plans to
perform this activity using their GIS / risk assessment model that is scheduled for
implementation in December 2006 [C 02. f]
Evidence: Procedure 10. 25. 01. 02, Performing WGP Risk Assessment and Threat
Analysis, Section 4. 0
~ Item 5C: $192. 917(b)
Processes have not been defined for the responsibilities for data collection or how the data
sets are assembled, how accuracy is verified, how the data is maintained, or defining the
sets of data that must be collected WGP has the intent and is in the process of developing
a GIS that they will use to integrate data comprehensively by the end of 2006. [C. 02 b]
Evidence: Procedure 10. 25. 01. 02, Performing WGP Risk Assessment and Threat
Analysis, Section 4. 0



e Item 5D: $192. 917(b)
WGP does not have processes for verifymg data quality. Procedures do not require that
conservative assumptions be applied if data is missing or suspect. It is not clear that
conservative values have actually been applied; for example, pipe line sections containmg
LFERW pipe default to a non-conservative value without verifying operating pressures
have actually been at MAOP. Records are not maintained that identify how
unsubstantiated data are used. The program does not specify that additional inspections or
field data collection efforts must be initiated for missing / suspect data [C 02 d]
Evidence: Procedure 10 25. 01, 02, Performing WGP Risk Assessment and Threat
Analysis, Section 4. 0; Items C. 02. d ii, and iv listed as NA in the WGP Protocol Cross
Reference list
6. $192. 921 How is the baseline assessment to be conducted?
(a) Assessment methods. . .
(b) Prioritizing segments. An operator must prioritize the covered pipeline segments for
the baseline assessment according to a risk analysis that considers the potential threats to
each covered segment. The risk analysis must comply with the requirements in g 192. 917. . .
(d) Time period. An operator must prioritize all the covered segments for assessment in
accordance with g 192. 917 and paragraph (b) of this section. An operator must assess at
least 50% of the covered segments beginning with the highest risk segments, by December
17, 2007. An operator must complete the baseline assessment of all covered segments by
December 17, 2012. . .
Item 6A: $192. 921(b)
The Transco BAP includes several segments at the bottom of the prioritization schedule
that have not been analyzed for risk These segments have been prioritized as the lowest
risk on the BAP schedule based solely on SME input The basis for this prioritization
without a risk analysis has not been documented. [B. 02. b]
Evidence: TRANSCO Baselme Assessment Plan
Item 6B: $192. 921(d)
There were numerous errors in the initial HCA identification process; as such verification
that the BAP schedule meets the rule completion schedule requirements cannot be made.
The BAP has not been updated to reflect new HCAs and identified sites identified in the
March — May 2005 field surveys that were conducted to locate identified site mformation
that was not collected in support of the December 17, 2004 requirement for HCA
identification. Additionally, the BAP does not include HCA segment mileage that was
erroneously left out on the Northwest system since the axial extension of potential impact
circles was not included in the defined HCAs. Furthermore, Method 1 used on the Transco



system appears to be applied incorrectly in that the full length of Class 3 and 4 locations
have not been included in HCA boundaries. [B. 02. d]
Evidence: GIS overview showing covered segment length of HCA 1401 Ft. Lewis to
Sumner
GIS overview showing covered segment length of HCA, Northwest Pipeline, Lme 1400—
Lava Hot Springs to Pocatello, MP 591. 9958 to 592. 6174
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Soda Springs to Lava Hot Springs, MP 541. 1691 to 541. 7532
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Soda Springs to Lava Hot Springs, MP 542. 6616 to 542. 9956
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Lava Hot Springs to Pocatello, MP 573, 3549 to 573. 917
GIS overview showing covered segment length of HCA, Northwest Pipeline, Line 1400—
Lava Hot Springs to Pocatello, MP 590. 8329 to 591. 1995
Alignment Sheet Location Class Determination and Pipehne Qualification Record, MP
1782. 125 to 1783. 750, Somerset and Middlesex Counties, NJ, Main Line, DOT-NJ-8
Revision Histories for the Northwest, Transco, and Gulfstream Baseline Assessment Plans
7. )192. 917 How does an operator identify potential threats to pipeline integrity and use
the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all potential threats to
each covered pipeline segment. Potential threats that an operator must consider include, but
are not limited to, the threats listed in ASMK/ANSI B31. 8S (ibr, see $192. 7), section 2,
which are grouped under the following four categories:
(1) Time dependent threats such as internal corrosion, external corrosion, and stress
corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;
(3) Time independent threats such as third party damage and outside force damage;
and
(4) Human error.
$192. 907 What must an operator do to implement this subpart?
(b) Implementation Standards. In carrying out this subpart, an operator must follow the
requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see $192. 7) and its
appendices, where specified. An operator may follow an equivalent standard or practice
only when the operator demonstrates the alternative standard or practice provides an
equivalent level of safety to the public and property. In the event of a conflict between this
subpart and ASME/ANSI B31. 8S, the requirements in this subpart control.
ASMK B31. 8S-2001 Managing System Integrity of Gas Pipelines
Section 2. 2 Integrity Threat Classification
(a) Time-Dependent
(1) External Corrosion
10



{2) Internal Corrosion
(3) Stress Corrosion Cracking
(b) Stable
(1) Manufacturing Related Defects
(2) Welding/Fabrication Related
{3) Equipment
(c) Time-Independent
(1) Third Party/Mechanical Damage
(2) Incorrect Operations
(3) W'cather Related and Outside Force
. . . The interactive nature of threats (i. e.
,
more than one threat occurring on a section
of pipeline at the same time) shall also be considered. An example of such an
interaction is corrosion at a location that also has third party damage. . . .
~ Item 7A: $192. 907(b)
The initial risk assessment and subsequent basehne assessment decisions were based on a
risk model that is no longer supported. This risk model is being replaced by an in-house
model that will not be in place until December 2006. The initial model fails to satisfy rule
requirements. There is a lack of documented procedures that include required activity
steps, responsibilities, data inputs and outputs, and documentation requirements. There is
no documented basis for threat weightings factors used in the initial risk model that was
used for development of their BAP; documentation of interacting threats have not been
considered, and documentation of the elimination of threats is not conducted until after the
completion of risk ranking. [C. O l. a]
Evidence: Procedure 10. 25. 01, 02, Performing WGP Risk Assessment and Threat
Analysis, Section 3. 2
Procedure 70. 18. 01. 03, Minimizing, Mitigating, and Monitoring Stress Corrosion
Cracking, Appendix A, WGP Assessment Plans, and Appendix B, Monitoring Pipeline for
SCC
Stress Corrosion Cracking Checklist, HCA 2436, MP 27. 1 to 27. 28
Stress Corrosion Cracking Checklist, HCA 2436 MP 27, 29 to 27. 72
Stress Corrosion Cracking Checklist, HCA 2479 MP 27 1 to 27. 28
Stress Corrosion Cracking Checklist, HCA 2479 MP 27. 29 to 27. 72
Stress Corrosion Cracking Checklist, HCA 1401 MP 865. 52 to 865. 99
Stress Corrosion Cracking Checklist, HCA 0030, Mam Line A, MP 303. 38 to 307. 38
8. )192. 925 What are the requirements for using External Corrosion Direct Assessment
(ECDA)?
(a) Definition. ECDA is a four-step process that combines preassessment, indirect
inspection, direct examination, and post assessment to evaluate the threat of external
corrosion to the integrity of a pipeline.
(b) General requirements. An operator that uses direct assessment to assess the threat of
external corrosion must follow the requirements in this section, in ASME/ANSI B31. 8S (ibr,
11



see g 192. 7), section 6. 4, and in WACK RP 050Z-ZOOZ (ibr, see g 19Z. 7). An operator must
develop and implement a direct assessment plan that has procedures addressing
preassessment, indirect examination, direct examination, and post-assessment. If the ECDA
detects pipeline coating damage, the operator must also integrate the data from the ECDA
with other information from the data integration (g 19Z. 917(b)) to evaluate the covered
segment for the threat of third party damage, and to address the threat as required by g
192. 917(e)(l).
(1) Preassessment. In addition to the requirements in ASMK/ANSI B31. 8S section 6. 4
and NACE RP 050Z-2002, section 3, the plan's procedures for preassessment must
include-
(i) Provisions for applying more restrictive criteria when conducting KCDA for the
first time on a covered segment; and
(ii) The basis on which an operator selects at least two different, but complementary
indirect assessment tools to assess each KCDA Region. If an operator utilizes an
indirect inspection method that is not discussed in Appendix A of NACE RP0502-
2002, the operator must demonstrate the applicability, validation basis, equipment
used, application procedure, and utilization of data for the inspection method.
{2) Indirect examination. In addition to the requirements in ASMK/ANSI B31. 8S
section 6. 4 and NACE RP 0502-2002, section 4, the plan's procedures for indirect
examination of the ECDA regions must include-
(i) Provisions for applying more restrictive criteria when conducting KCDA for
the first time on a covered segment;
(ii) Criteria for identifying and documenting those indications that must be
considered for excavation and direct examination. Minimum identification
criteria include the known sensitivities of assessment tools, the procedures for
using each tool, and the approach to be used for decreasing the physical spacing of
indirect assessment tool readings when the presence of a defect is suspected;
(iii) Criteria for defining the urgency of excavation and direct examination of
each indication identified during the indirect examination. These criteria must
specify how an operator will define the urgency of excavating the indication as
immediate, scheduled or monitored; and
{iv) Criteria for scheduling excavation of indications for each urgency level.
(3) Direct examination. In addition to the requirements in ASME/ANSI B31. 8S section
6. 4 and NACE RP 0502-2002, section 5, the plan's procedures for direct examination of
indications from the indirect examination must include-
(i) Provisions for applying more restrictive criteria when conducting ECDA for
the first time on a covered segment;
(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allowable limits (Section
5. 5. 2. 2 of NACE RP0502-2002), or
(B) Root cause analysis reveals conditions for which ECDA is not suitable
(Section 5. 6. 2 of NACK RP0502-2002);
(iii) Criteria and notification procedures for any changes in the ECDA Plan,
including changes that affect the severity classification, the priority of direct
examination, and the time frame for direct examination of indications; and
12



(iv) Criteria that describe how and on what basis an operator will reclassify and
reprioritize any of the provisions that are specified in section 5. 9 of NACE
RP0502-2002.
(4) Post assessment and continuing evaluation. In addition to the requirements in
ASME/ANSI B31. SS section 6. 4 and NACE RP 0502-2002, section 6, the plan's
procedures for post assessment of the effectiveness of the ECDA process must
include-
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing
external corrosion in covered segments; and
(ii) Criteria for evaluating whether conditions discovered by direct examination
of indications in each ECDA region indicate a need for reassessment of the
covered segment at an interval less than that specified in g 192. 939. (See Appendix
D of NACE RP0502-2002. )
~ Item SA: $192. 925(b)
Although WGP's ECDA procedure 20 19. 01. 02 requires that the operator follow the data
requirements in ASME B31. 8S Section 4. 2 and NACE RP 0502 section 3 2, the ECDA
documents reviewed on several completed ECDA's did not contain all of the information
required by WGP's procedure. In addition there was no documentation on what
assumptions were made and what information was required to assure the feasibility of
each ECDA project. [D 02. a]
Evidence: WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch
Lateral, and Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756 6128
ECDA Glenn's Ferry 1401 Buhl to Mt Home MP 756, 6155
~ Item SB: $192. 925(b)(1)
Per WGP's ECDA procedure 20. 19 01. 02 sections 3 1. 1 and 3. 1. 2, WGP was to perform a
feasibility assessment for each ECDA performed. Of the ECDA's reviewed there were no
documents showing that any feasibility assessments were performed. [D. 02. b]
Evidence: WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch
Lateral, and Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756. 6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756. 6155
Item SC: $192. 925(b)(1)
Per the requirements in NACE RP 0502 Section 3 4, there was no documentation on the
indirect inspection tool selection criteria. In addition, it appeared tool selection followed
13



ECDA region determination rather than preceding it Also, WGP is using guided wave in
casings without required notification. [D 02.c]
Evidence: Procedure 20.19.01.02, Performing External Corrosion Direct Assessment
(ECDA)
WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch Lateral, and
Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756.6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756 6155
• Item 8D: §192.925(b) (1)(ii)
Panhandle B is not a NACE recognized assessment tool for ECDA indirect inspections.
[D.02.c]
Evidence: NACE RP 0502, Table 2
Use of Panhandle B identified by WGP during the inspection.
• Item 8E: §192.925(b)(1)(ii)
Although the ECDA procedures specify that casings and other areas are separate regions,
in one of the ECDA's reviewed (1400 line, Glenn's Ferry) a cased crossing was part of the
single ECDA region along with road crossings and other areas. [D 02.d]
Evidence: ECDA Glenn's Ferry HCA 1400 Buhl to Mt. Home MP 756.6128.
• Item 8F: §192.925(b)(1)(i)
The ECDA procedure 20.19 01.02 does not include the 192.925 requirement that initial
ECDA assessments include more restrictive criteria for the pre-assessment and that this be
documented. [D.02.e]
Evidence: Procedure 20.19.01.02, Performing External Corrosion Direct Assessment
(ECDA)
• Item 8G: §192.925(b)(2)
There is no documentation that the start and finish of each ECDA region in the completed
documented. [D.03.a]
assessments were not physically marked nor is the amount of overlap for each tool
Evidence: WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch
Lateral, and Harrison 10 Inch Lateral
14



ECDA Glenn's Ferry 1400 Buhl to Mt Home MP 756. 6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756. 6155
~ Item SH: $192. 925(b)(2)
WGP's ECDA procedure 20. 19. 01. 02 section 5 1 4 requires that the indirect inspection
results be integrated with other data obtamed m the pre-assessment such as encroachments
and foreign line crossings, this is not evident in the ECDA assessments reviewed (1400
line Glenn's Ferry and Oreland, Mercer and Harrison projects) [D. 03. b]
Evidence: Procedure 20. 19 01. 02, Performing External Direct Assessment (ECDA),
Section 5. 1. 4.
WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch Lateral, and
Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756. 6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756. 6155
~ Item SI: $192. 925(b)(3)
The ECDA procedure does not follow the NACE RP for all required excavations. A
review of several ECDA projects showed that in one case only half the number of required
excavations was made based on the NACE RP and the ECDA procedure [D. 04. a]
Evidence: Procedure 20. 19. 01, Performing External Corrosion Direct Assessment
(ECDA)
WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch Lateral, and
Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756. 6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756. 6155
~ Item 8 J: $192. 925(b)(3)(iii)
There is no documentation that any internal notifications were made based on the results
of what was learned in the ECDA prospects completed to date. [D. 04. g]
Evidence: WGP Transco, ECDA Project, Oreland 12 Inch Extension, Mercer 16 Inch
Lateral, and Harrison 10 Inch Lateral
ECDA Glenn's Ferry 1400 Buhl to Mt. Home MP 756. 6128
ECDA Glenn's Ferry 1401 Buhl to Mt. Home MP 756. 6155
Item SK: $192. 925(b)(4)
The WGP ECDA procedure does not have the corrected NACE RP 0502 formula for
determining the remaining life nor does it include the NACE default corrosion rate where
15



corrosion rates are not documented. One of the evaluated ECDA projects used these
incorrect formulas and default values. [D. 05. a]
Evidence: Procedure 20. 19. 01. 02, Performing External Corrosion Direct Assessment
{ECDA)
9. $192. 927 What are the requirements for using Internal Corrosion Direct Assessment
(ICDA)?
(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a process an operator uses
to identify areas along the pipeline where fluid or other electrolyte introduced during
normal operation or by an upset condition may reside, and then focuses direct examination
on the locations in covered segments where internal corrosion is most likely to exist. The
process identifies the potential for internal corrosion caused by microorganisms, or fiuid
with CO2, 02, hydrogen sulfide or other contaminants present in the gas. . .
~ Item 9A: $192. 927(a)
WGP does not have a technical justification for eliminating the internal corrosion threat in
areas where ECDA is being utilized. Therefore, an ICDA procedure is required or another
assessment method must be utilized. [D. 06. a]
Evidence: There is no ICDA procedure.
WGP IM Overview Chapter 8, Section 8. 2. 2
Internal Corrosion Threat Checklist, HCA 2436, MP 27. 1 to 27. 28
Internal Corrosion Threat Checklist, HCA 2436, MP 27. 29 to 27 72
Internal Corrosion Threat Checklist, HCA 2479, MP27 1 to 27. 28
Internal Corrosion Threat Checklist, HCA 2479, MP 27. 29 to 27. 72
Internal Corrosion Threat Checklist, HCA 0030 Harrison, MP 1. 59 to 1. 9
Teleconference with Transco Gas Control who established that process equipment was
taken out of service due to damage from Katrina and unprocessed gas was being
introduced into the system that may exceed the water quantity limits
10. $192. 937 What is a continual process of evaluation and assessment to maintain a
pipeline's integrity? COMMENT since the probable violation stated below is only for
937(b), it is not necessary to restate the regulatory text (in yellow) for 937(a) and 937(c).
This same comment applies to other sections in the letter in which there appears to be more
regulatory text than needed.
(a) GeneraL
(b) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to
assure the integrity of each covered segment. The periodic evaluation must be based on a
data integration and risk assessment of the entire pipeline as specified in g 192. 917. For
16



plastic transmission pipelines, the periodic evaluation is based on the threat analysis
specified in g 192. 917(d) For all other transmission pipelines, the evaluation must consider
the past and present integrity assessment results, data integration and risk assessment
information (g 192. 917), and decisions about remediation (g 192. 933) and additional
preventive and mitigative actions (g 192. 935). An operator must use the results from this
evaluation to identify the threats specific to each covered segment and the risk represented
by these threats.
~ Item 10A: $192. 937(b)
WGP's IMP section 9. 1. 1. 5 of procedure 10. 25. 01. 02, SME's determme reassessment
intervals during the annual risk assessment results review. No annual review has been
completed to date to determine the reassessment mterval of completed baseline
assessments. [F. O l. a, b]
Evidence: Procedure 10. 25, 01. 02, Performing WGP Risk Assessment and Threats
Analysis, Section 9. 1. 1. 5
11. $192. 935 What additional preventive and mitigative measures must an operator
take?
(a) General requirements. An operator must take additional measures beyond those
already required by Part 192 to prevent a pipeline failure and to mitigate the consequences
of a pipeline failure in a high consequence area. An operator must base the additional
measures on the threats the operator has identified to each pipeline segment. (See g 192. 917)
An operator must conduct, in accordance with one of the risk assessment approaches in
ASME/ANSI B31. 8S (ibr, see g 192. 7), section 5, a risk analysis of its pipeline to identify
additional measures to protect the high consequence area and enhance public safety. Such
additional measures include, but are not limited to, installing Automatic Shut-off Valves or
Remote Control Valves, installing computerized monitoring and leak detection systems,
replacing pipe segments with pipe of heavier wall thickness, providing additional training to
personnel on response procedures, conducting drills with local emergency responders and
implementing additional inspection and maintenance programs.
(b) Third party . . .
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator
determines, based on a risk analysis, that an ASV or RCV would be an efficient means of
adding protection to a high consequence area in the event of a gas release, an operator must
install the ASV or RCV. In making that determination, an operator must, at least, consider
the following factors-swiftness of leak detection and pipe shutdown capabilities, the type of
gas being transported, operating pressure, the rate of potential release, pipeline profile, the
potential for ignition, and location of nearest response personnel.
~ Item 11A: )192. 935(a)
WGP has not identified or implemented any preventive and mitigative measures as
required in procedure their IMP procedure 10. 25. 01 02, Section 9. [H. O I. bj
17



Evidence: Procedure 10. 25. 01. 02, Performing WGP Risk Assessment and Threat
Analysis, Section 9. 0
~ Item 11B: )192. 935(c)
WGP globally evaluated the effectiveness of ASV's and RCV's for their pipelines. WGP
did not delineate a process that evaluates the impact on risk on individual covered
segments of installing ASV's and RCV's [H. 07. a]
Evidence: Procedure 10. 25. 01. 02, Performing W'GP Risk Assessment and Threat
Analysis, Section 9. 1. 1
Policy 20. 15. 00, Remedial Measures. Transmission Lines
12. $192. 909 How can an operator change its integrity management program?
(a) General. An operator must document any change to its program and the reasons for
the change before implementing the change.
~ Item 12A: $192. 909(a)
The WGP Integrity Management Program change log does not provide a detailed
description of changes that were made to the Integrity Management Plan or Procedures.
[K. Ol. a]
Evidence: WGP Protocol Cross Reference lists this protocol as NA
13. $192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
192. 907) and evolves into a more detailed and comprehensive integrity management
program, as information is gained and incorporated into the program. An operator must
make continual improvements to its program. The initial program framework and
subsequent program must, at minimum, contain the following elements. (When indicated,
refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed information on the listed
element. )
(a) An . . .
(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.
(I) A quality assurance process as outlined in ASME/ANSI B31. 8S, section 12.
(m) A communication plan that includes the elements of ASME/ANSI B31. 8S,
section 10, and that includes procedures for addressing safety concerns raised by—
(1) OPS; and
(2) A State or local pipeline safety authority when a covered segment is
located in a State where OPS has an interstate agent agreement.
18



~ Item 13A: $192. 911(k) ASME B31. SS-2001, section 11 (b)
Some important system changes were not reported to the IMP team that could have
affected pipeline integrity. [K. 02. d]
Evidence: Teleconference with WGP Transco Gas Control where the introduction of
unprocessed gas into Transco due to equipment outages from Katrina was unknown to the
Integrity management group. The IM group was assummg that all gas in the WGP system
met tariff requirements for water content and they were usmg that as a basis for not
performing ICDA on segments where ECDA was being used as the sole assessment
method.
Item 13B: $192. 911(k) ASME B31. SS-2001, section 11 (d)
The Management of Change form had an approval process that was described in
Procedure 10. 29. 01. 02. The forms reviewed by the Inspection Team indicated that
approval for startup/change was at times the first dated signature on the form when the
procedure would indicate that it should be the final signature. MOC examples reviewed
(MOCR-BOD-2005-14 and MOCR-BOD-2005-15) reflect the occurrence of required
management approvals for modification prior to completion of the specified pre-
modification reviews. Final approvals for the completed startup/change occurred prior to
the pre-modification reviews and modification approvals. MOCR-110-2005-01 and -02,
Palmetto-2006-2, MOCR-180-2005-02 do not reflect some approval signatures or
approval dates. MOCR-110-2006-001 involves replacement of a rupture device and it
would be expected that Engineering (Pipeline Design) or IMP review would be required.
[K. 02. e]
Evidence: MOCR-110-2005-01
MOCR-110-2005-02
MOCR-110-2006-01
MOCR-BOD-2005-14
MOCR-BOD-2005-15
MOCR-Palmetto-2006-2
MOCR-180-2005-02
Item 13C: $192. 911(k) ASME B31. SS-2001, section 10. 3
There is no internal communication procedure as required per the rule [M. 01 b]
Evidence: Per the WGP Protocol Cross Reference list this protocol is NA
~ Item 13D: $192. 911(m)
No procedure exists to handle safety concerns that PHMSA and/or local regulatory
authorities raise. [M 02. a]
Evidence: Per WGP Protocol Cross Reference list this protocol is NA
19



Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000
lated series of violations. The Compliance Officer has reviewed the circumstances an
r each violation for each day the violation persists up to a maximum of $1,000,000 for ar
supporting documentation involved in the above probable violation(s) and has recommended that
you be preliminarily assessed a civil penalty of $351,000 as follows:
Item number
PENALTY
[1A]
$26,000
[2A]
$26,000
(2B]
[3A]
$43,000
$26,000
[4A]
$43,000
(4B]
$43,000
[4C]
$26,000
[4D]
$43,000
[5A]
$15,000
[5B]
$15,000
[SD]
$15,000
[6Bj
$6,000
(7A]
$6,000
[8A]
$3,000
[8B]
$3,000
[81)
$3,000
[11A]
$3,000
[13C]
$3,000
[13D]
$351,000
$3,000
Warning Items
With respect to items 5C, 6A, 8C, 8D, 8E, 8F, 8G, 8H, 8J, 10A, 11B, 12A, 13A and 13B we have
viewed the circumstances and supporting documents involved in this case and have decided n
conduct additional enforcement action or penalty assessment proceedings at this time. W
advise you to promptly correct these items). Be advised that failure to do so may result in
Williams Gas Pipeline being subject to additional enforcement action.
Proposed Compliance Order
With respect to items 5A, 5B, 5D, 6B, 7A, 81, 8K, 9A, 13C and 13D pursuant to 49 United States
Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a
Compliance Order to Williams Gas Pipeline. Please refer to the Proposed Compliance Order,
which is enclosed and made a part of this Notice.
20



Res onse to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in
Compliance Proceedings Please refer to this document and note the response options. If you do
not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to
contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline
Safety to find facts as alleged in this Notice without further notice to you and to issue a Final
Order
In your correspondence on this matter, please refer to CPF 5-2007-1001 and for each document
you submit, please provide a copy in electronic format whenever possible.
Chris Hoidal
Director, Western Region
Pipehne and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
21



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code ) 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Williams Gas Pipeline a Comphance Order
incorporating the following remedial requirements to ensure the comphance of Wilhams Gas
Pipeline with the pipeline safety regulations:
In regard to Item Number 5A of the Notice pertaining to evaluation of a covered
pipeline segment containmg low frequency electric resistance welded pipe (ERW),
lap welded pipe, or other pipe that satisfies the conditions specified in ASME
B31. 8S-2001, Appendix A4. 3 and ASME B31. 8S-2001, Appendix A4. 4. WGP
must conduct a study of all pipeline segments located withm an HCA to determine
if it contains any pipe meeting the definition as described above. Furthermore, this
study must evaluate any covered or non-covered segment m the pipeline system
with such pipe that has experienced seam failure, or operating pressure on the
covered segment has increased over the maximum operating pressure experienced
during the preceding five years.
In regard to Item Number 5B of the Notice pertaining to the lack of data
integration. WGP must perform a complete data integration of all known
information about the entire Northwest and Transco Pipeline systems in
conjunction with each HCA area.
In regard to Item Number 5D of the Notice pertaining to missmg data and
conservative assumptions that can be used in their risk analysis, WGP must define
and justify any conservative assumptions made during their risk analysis process.
Furthermore, WGP must develop a program and process to obtain missmg data for
future risk analysis determination.
In regard to Item Number 6B of the Notice pertaming to numerous errors in the
initial HCA identification process, WGP must completely conduct their initial
HCA identification process over with the new revised procedures produced from
this inspection.
In regard to Item Number 7A of the Notice pertaining to the risk analysis
conducted by WGP, the operator must conduct a complete new risk analysis with a
new risk model that considers all risk factors applicable to each HCA segment.
In regard to Item Number 8I of the Notice pertaining to the incorrect number of
excavations required for the direct examination piece of the ECDA procedures,
WGP must re-examine all of their ECDA projects and conduct all of the
excavations required by Part 192
In regard to Item Number 8K of the Notice pertaining to the incorrect NACE RP
0502 formula for determimng the remaining life and the incorrect default corrosion
rate, WGP must re-evaluate and recalculate the remaining life for each corrosion
anomaly based on the correct values. WGP must then determine if any additional
excavations are required and report the number of increased excavations to
PHMSA.
In regard to Item Number 9A of the Notice pertaining to Internal Corrosion Direct
Assessment (ICDA), WGP must develop an ICDA plan and process to evaluate the
threat of internal corrosion. Furthermore, WGP must conduct an assessment for
22



ICDA on all areas where ECDA has been used or is planned to be used or develop
a sound technical justification for each HCA area why internal corrosion is not a
threat.
9. In regard to Item Ninnber 13C of the Notice pertaining to internal communications
procedures, W'GP must develop an internal communications plan.
10, In regard to Item Ninnber 13D of the Notice pertaining to procedures to handle
safety concerns communicated from regulatory authorities, WGP must develop a
process in which to handle such requests and concerns.
11. The operator will have 60 days from the issuance of the Final Order in which to
complete the above compliance order items.
12. WGP shall maintain documentation of the safety improvement costs associated
with fulfilling this Comphance Order and submit the total to Chris Hoidal,
Director, Western Region, Pipeline and Hazardous Materials Safety
Administration. Costs shall be reported in two categories: 1) total cost associated
with preparation/revision of plans, procedures, studies and analyses, and 2) total
cost associated with replacements, additions and other changes to pipelme
infrastructure.
23

520071001_closure letter_07092012_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
July 9, 2012
Mr. Randy Barnard
President
Williams Gas Pipelines
2800 Post Oak Boulevard
Houston, TX 77056
CPF 5-2007-1001
Dear Mr. Barnard:
On May 2, 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Williams Gas Pipelines a Final Order in the above-referenced case. This Order
included a Compliance Order and Civil Penalty assessment. Based on our review of the
documentation you provided and confirmation of payment of the civil penalty, it has been
determined that you have complied with the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
Chris Hoidal
Director, Western Region
Pipeline and Hazardous Materials Safety Administration
cc: PHP-60 Compliance Registry
PHP-500 R. Reineke

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/520071001>
- Source ID: `phmsa-enforcement`
- SHA-256: `7c700a9653f9abb8ac0da56a80074d956c2a611e703478088d231ccdb1294b24`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-22T17:50:25.866Z
- Document slug: `phmsa-enforcement-520071001`

### Source metadata

```json
{
  "cpf": "520071001",
  "operator": "NORTHWEST PIPELINE LLC",
  "region": "Western",
  "pipelineType": "GAS INTERSTATE ONSHORE",
  "caseStatus": "CLOSED",
  "citedSections": [
    "192.905(a)",
    "192.905(b)",
    "192.907(a)",
    "192.907(b)",
    "192.909(a)",
    "192.911(k)",
    "192.911(m)",
    "192.917(b)",
    "192.917(e)(4)",
    "192.921(b)",
    "192.921(d)",
    "192.925(b)",
    "192.925(b)(1)",
    "192.925(b)(1)(ii)",
    "192.925(b)(2)",
    "192.925(b)(3)",
    "192.925(b)(3)(iii)",
    "192.925(b)(4)",
    "192.927(a)",
    "192.935(a)",
    "192.935(c)",
    "192.937(b)"
  ],
  "dataAsOf": "08/04/2026 12PM",
  "caseDataAsOf": "2026-08-04",
  "attachmentCount": 7,
  "attachments": [
    {
      "name": "520071001_ notice letter_01292007.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_%20notice%20letter_01292007.pdf",
      "bytes": 236908,
      "category": "agency_document"
    },
    {
      "name": "520071001_ notice letter_01292007_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_%20notice%20letter_01292007_text.pdf",
      "bytes": 1333003,
      "category": "agency_document"
    },
    {
      "name": "520071001_closure letter_07092012.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_closure%20letter_07092012.pdf",
      "bytes": 19857,
      "category": "agency_document"
    },
    {
      "name": "520071001_closure letter_07092012_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_closure%20letter_07092012_text.pdf",
      "bytes": 9388,
      "category": "agency_document"
    },
    {
      "name": "520071001_Final Order_05022011.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Final%20Order_05022011.pdf",
      "bytes": 2819358,
      "category": "agency_document"
    },
    {
      "name": "520071001_Final Order_05022011_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Final%20Order_05022011_text.pdf",
      "bytes": 224501,
      "category": "agency_document"
    },
    {
      "name": "520071001_Operator_Response_and_Requesting_Hearing_03012007.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/520071001/520071001_Operator_Response_and_Requesting_Hearing_03012007.pdf",
      "bytes": 56660,
      "category": "party_submission"
    }
  ],
  "extractedAgencyDocumentCount": 3,
  "attachmentPolicy": "Official attachment links are retained. Agency-issued documents may also include a verified local PDF and page-level text representation.",
  "jurisdiction": "US",
  "operatorName": "NORTHWEST PIPELINE LLC"
}
```