SOUTH CAROLINA PIPELINE CORP — Notice of Amendment

party submissionOfficial PDF220071009M_operator response_09172007.pdf#

220071009M_notice sent_05222007.pdf, page 1Official PDF,l \t7 U.5. Deporfment of Tronsporfotion Plpellno ond Hozonlour ilsDadolr Adminl$rsrlon 239 Peecnfee Streel Sle- 600 Atanta,GA 30303 3df.ty : NOTICE OF AMENDMENT CERTIF'IED MArL - RETLIRN RECETPT_BSOITESTEn May 22,2007 Mr. Sarruel L. Dozier Vice President and Commercial Field Operations Carolina Gas Transmission (CGT) 105 New Way Road Columbia Souttr Carolina 29224-2407 cP['2-2007-1009M Dear Mr. Dozier: On October 2-5 and October 23-26,2006, representatives of the Pipeline and Hazardous Materials Safety Admifislplion (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Carolina Gas Transmission (CGT) procedures for gas integrity management program in Columbia" South Carolina. On the basis of the inspection, PHMSA has identified the apparent inadequacies for:nd within CGT plans or procedures, as described below: 1. $le2.erl(a) $ 192.91f (a) An identifrcation of all high consequence orets' in accordance with s 192.90s. $ 192.905 IIow does an operator identify a high consequence area? . (a) General To determine which seguents of an operator'g transmission pipeline system ere covered by this subpart, an operator must identify the high corsequence areas. An operator must use method (1) or (2) from the definition#

220071009M_notice sent_05222007.pdf, page 2in $192.903 to identify a high consequence area. An operator may apply one method to its entire pipetine system, or an operrtor may apply one method to individual pofrions ofine pipetine system. An operator must describe in its integrity -uoug"*"ot program which method it is applyingto each portion of the Jpeiator's fipeline system- The description must include the potentirl impact radius when utilized to establish a high consequence area. (bxl) Identifrcd sites. An operator must identify an identifred site' for purposeg itthi. subpart, from information the operator has obtained from routine operation and maintenance ectivities and from public olficials with safety or cmergency response or planning responsibilities who indicate to the operator that they i*ow of locations that meet the identified site criteria. These pubHc offrcialscould include officials on e local emergency planning commission or relevant Native American tribal officials. (2) If e public official with safety or emergency response or planning ."rpoorlbilities informs an operator that it does not have the information to iOentify an identilied site, the operator must use one of the following sources' 8s to identify these sites. (i) Visible marking (e-gua sign); or (ii) The "pptoi"i"te, site is licensed or registered by a Federal, State, or local goYernment agency; or (iii) The site is on a list (including a list on an intetnet web site) or map maintained by or available from a Federalo State, or local goYenrment agency and avaihble to the general public. (c) Newly identifted areas. When an operator has information that the area around a pipeline segment not previously identified as a high consequence arel could satisfy any of the delinitions in $ 192.903, the operator must complete the evaluation using method (1) or (2). If the segment is determined to meet the definition as a high consequetrce lre& it must be incorporated into the operator,$ baseline assessment plrn as a high consequence area within one year from the date the area is idenffied. $ f92.903 \ilhat definitions apply to this subpart? High consequcilce area meuns ln lrea established by one of the methods described in paragraphs (f) or (2) as follows: (f) An area defmed as{i) A Class 3 location under $ 192.5; or (ii) A Class 4 lbcation under $ 192.5; or (iii) Any area in a Class 1 or Class 2 location where the potential imprct radius is greater than 660 feet (200 meters), and the area witnin a potential impact circle contains 20 or moIle buildings intended for human o"copancy; or (iv) Any area in a Class I or Class 2location where the potential impact circle contrins rn identilied site. (2) The areawithin a potential impaet circle containing{i) 20 or more buildings intended for human occupancy, unless the exception in paragraph (4) applies; or (ii) An identified site.#

220071009M_notice sent_05222007.pdf, page 3(3) rwhere a potential impact circle is calculafed under either method (1) or (2) to establish a high consequence area' the length of the high consequence area extends axially atong thelength of the pipeline from the outermost edge of the first potential impact circle that contains either an identified site or 20 or more buildlngs intended for human occupancy to the outermost edge of the last - contiguius potentiat impact circle that contains either an identified site or 20 or morelbuildings intended for human occupancy. {See Figure E.I.A. in appendix E.) {4) If in identifying a hrgh consequence arer under paragraph (lxiiD of this definition or panagnrph (2Xi) of this definition, the radius of the potential impact circle is gr-atir than 660 feet (200 meters), the operetor mry identify a high conseqoence area based on a prortted number of buildings intended_for humrn o."op"o"y within a distancl 660 feet (200 meters) from the centerline of the pipeline until-December 17r2OO6.If an operator chooses this approachn the opeia-o" must prorate the number of buildingr intended for human occupancy based on the ratio of an trea with a radius of 660 feet (200 meterc) to the area of the potcntial impact circle (ie., the prorated number of buildingc intended for human occupancy is equal to [20 x (560 feet [or 200 meters l/ potential impact radius in feet for metersl) 2 l). Identifud tite means each of the following areas: (a) An outside aret or open structure that is occupied by twenty (20) or mono persorr$ on at least 50 days in any twelre (l2)-month period. (Ihe days need not be consecutive.) Examples include but are nsl limited to, beaches, playgrounds, recreational facilities' camping grounds, outdoor theaters, stadiums, recreational ereas near a body otwatei o" outside a rural building such as a religious facility; or (b) A "t""s building that is occupied by twenty (20) or more persons on at least live (5) days a week for ten (10) weeks in any twelve (|2)-month period. (Ihe days and weeks need not be consecutive.) Examples include, but are not limited tor religious facilities, office buildings, community centers, generll storesr'4-H facilities, or roller skating rinks; or (c) A facility occupied by persons who are confined, are of impaired mobilitV, or would be difficutt to evacuate. Examples include but are not limited to hospitals, prisons, schools, day-carc facilities' retircment facilities or assisted-living facilities. Potential impact circle is a circle of radius equal to the potential impact radius (PrR). Potentidl impact radi.us (PIR) metns the radius of a circle within which the potential failure of e pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69* (square root of (p*d 2))t where'r' is the radius of a circular anea 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 ndt is the nominal diameter of#

220071009M_notice sent_05222007.pdf, page 4the pipeline in inches. Note: 0.69 is the factor for natural gas. This numberwill vary for other geses depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI 831.8-5-2001 (Supplement to ASME 831.8; ibr, see $ 192.7) to calculate the impact radius formula. Remcdifiion 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 1A: $ 192.905(a) and $ 192.903(2), (3), and (a) There are no detailed procedures describing a repeatable process by which HCA maps are produced. Flow charts are being used that do not adequatety address the process us"i to produce the maps. For example, the flow charts do not describe who is to perfornr-specific tasks and how they are to docume,lrt fhe output of those tasks. In addition, ihere is inadequate guidance for application of PIRs as they relate to identified sites. For example, no direction is provided that describes where a PIR is to be located in relation to a school with a playground. Item LB: $ 192.905(b) and $ 192.903(4) There is no documentation of the basis for inclusion or exclusion of identified sites. Additionally, no instruetions are provided regarding how to provide this documentation' Item LC: $ 192.9050) There is a lack of instruction provided to emergency responders to ensure that they provide consistent and quality feedback during events designed to obtain this information. There wasno documentation available to substantiate HCA identification updates. $rez.er1G) $192.911(b) A baseline assessment plan meeting the requirements of $192.919 and sl92.921. $ f92.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (el Aetions to address particular thrests.If an operetor identifies flny of the following threats, the operator must take the following actions to address the threat (3) Manufacturing and construction defects. If an operator identifies the threat of manufacturing and construction defects (including seam defects) in the covered segment, an operator must an*lyze the covered segment to determine the risk of fnilure from these defects. The analysis must consider the results of prior#

220071009M_notice sent_05222007.pdf, page 5assessments on the cov€red segment An operator may consider manufacturing and construction related defects to be stable defects ilthe operating pressure on the covered segment has nOt increased over the maximum operating prcssune experienced during the live years preceding identffication of the high coneequence area. If eny of the following changes occur in the covered segment' an operltor must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reassessment. (i) Operating pressure increases above the maximo- op*""tiog pressure experienced during the preceding five years; (ii) MAOP increasesl or (iii) The stresses teading to cyclic fatigue increase' (4) ERW pipe. If a covered pipeline segment contains low frequency electric welded pipe @Rw), lap welded pipe or other pipe that satislies the ".*i*t"oru conditions specifredin ASME/ANSI mf.$ S, 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 operatingpnessure experienced during the preceding five years, an operator must select an assessment technologr or technologies with a p"oo*o applicrtion capable of assessing sesm integrity and seam corrosion anomaUei. The operaior must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reasseesmenl S f92.919 What must be in the baseline assessment plan? An operetor must include each of the following elements in its written baseline assessment plan: (a) tdentification of the potential threats to each covered pipeline segment rnd the information supporting the threat identilication. (See $f92.914 (c) A schedule for completing the integrity assessment of all covered segments' including risk factors considered in establishing the assessment schedule; $ 192.921 How is the baseline assesgmeut to be conducted? {d) Thnc period" Al operator must prioritize alt the covered segments for ssse$sment in accordance with $ 192.917(c) and peragraph (b) of this section' An operator must assess at least 507o of the covered segments beginning with the highest risk segments, by December 1712007. An operator must complete the baseline assessment of all covered segments by Deeember 1712012. $ 192.933 What actions must be taken to address integrity issues? (bl Discovery of condition. Iliscovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. A condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (dxl) through (dX3) of this#

220071009M_notice sent_05222007.pdf, page 6section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity? (a) General. After completing the baseline integrity assessment of a covered segment, an operator must continue to assess the line pipe of that segment at the intervals specified in § 192.939 and periodically evaluate the integrity of each covered pipeline segment as provided in paragraph (b) of this section. An operator must reassess a covered segment on which a prior assessment is credited as a baseline under § 192.921(e) by no later than December 17, 2009. An operator must reassess a covered segment on which a baseline assessment is conducted during the baseline period specified in § 192.921(d) by no later than seven years after the baseline assessment of that covered segment unless the evaluation under paragraph (b) of this section indicates earlier reassessment. • Item 2A: § 192.917 (e)(3) and (4) CGT program and procedure requirements are inadequate to track MOP and MAOP changes to ensure that stable long seam threats do not become unstable for both covered and non-covered segments. • Item 2B: § 192.919(c), § 192.921(l), § 192.933(b), and § 192.937(a) CGT does not have program requirements to ensure that the date for completion of field activities for an assessment is recorded so that the timeframe for evaluating anomalies and reassessment date(s) can be accurately determined. 3. §192.911(c) §192.911 (c) An identification of threats to each covered pipeline segment, which must include data integration and a risk assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for assessment (§ 192.917) and to evaluate the merits of additional preventive and mitigative measures (§ 192.935) for each covered segment. § 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 ASME/ANSI B31.8S (ibr, see § 192.7), section 2, which are grouped under the following four categories: 6#

220071009M_notice sent_05222007.pdf, page 7(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) iime independent threats such as third party damage and outside force damage; and (4) Human error. (b) Data gilhering and integrati.on.To identify and evaluate the potential threats to ".o"*rd pipeline segmeni; an operetor 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 aUd integration, an operator must fo[ow the requirements in ASME/AI\[SI B3l.8S, section 4. At a minimum' an operator must gather and evaluate the set of data specified in Appendix A to .tSUf,laXSI B3l.8S, and consider both on the covered segment and similar non- eovered segments, past incident history, corrosion control records, conlinuing sutTeillancu "e"o"dr, patrolling records, maintenance history, internal inspection records and all other conditions specific to each pipeline' (c),Rrst assessmentAn operator must conduct a risk assessment that follows ^q,SUnnnSI831.85, r*"iioo 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for tle baseline snd continual reassessments ($$ l92'919t lg1.g1l,tgZ,gST),and to determine what additional preventive and mitigative measures are needed ($ f92.935) for the covered cegment. (e) Acttons to address pafiicular thrcats, If an operator identifies any of the ioitowing threats, the operator must take the following actions to address the threat (ll Third pafi danuge,An operator must utilize the data integration required in i"t"g*pi O) of this section and ASME/ANSI B3l.8S, Appendix A7 to determine ine suscep6bility of each covered segment to the threat of third party damage.If an operator identifies the threat of third prrty damage, the operator must imptement comprehensive additional preventive measure$ in accordance with $1i2.935 and monitor the effectiveness of the preventiv€ measurss.Ift in conducting a baseline lssessment under $192.921, or a reassessment under $192.93?, au operator uses an intemal inspection tool or external cotrosion direct assessment, the operator must integrate data from these rssessments with data related to eny eniroachment or foreign line crossing on the covered segment' to define where potential indications of third party damage may exist in the covered segment. An operator must also have procedures in its integrity management program eddressing actions it will take to respond to findings frcm this data integration. o ltem 3A: $ 192.917(a)#

220071009M_notice sent_05222007.pdf, page 8CGT's IMP includes a statement (in Section 4.4) that threat interaction will be considered, but includes no process for implementation. The Kiefner model currently used by CGT, does not address threat interaction. • Item 3B: § 192.917(a) CGT has concluded, without an adequate documented basis, that three threats - stress corrosion cracking, internal corrosion, and human error - are not threats of concern throughout their system. • Item 3C: § 192.917(e)(1) There is no procedure to assure that data on encroachments and foreign line crossings are integrated with ILI or ECDA results. This data integration process is required by 192.917(e)(1) for addressing the threat of third-party damage. • Item 3D: § 192.917(c) CGT has insufficient description in its program to demonstrate that risk assessment is being used to address the objectives listed in ASME/ANSI B31.8S, other than risk ranking of HCA segments. • Item 3E: § 192.917(c) There are bai or tian he is a oris process to assure that riskhar prevalated on • Item 3F: § 192.917(c) There is no detailed process to assure validation of risk results against company/industry experience. 4. §192.911 (d) §192.911(d) A direct assessment plan, if applicable, meeting the requirements of §§ 192.923, and depending on the threat assessed, of 192.925, 192.927, or 192.929. §192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? (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, see § 192.7), section 6.4, and in NACE RP 0502-2002 (ibr, see § 192.7). An operator must develop and implement a direct assessment plan that has procedures addressing pre-assessment, indirect examination, direct examination, and post-assessment. If the ECDA detects pipeline coating damage, 8#

220071009M_notice sent_05222007.pdf, page 9the operator must also integrate the data from the ECDA with other information from the data integration ($ f92.9f?ft0 to evaluate the covered segment for the threet of third psrty damage, and to address the threst as required by $ re2.e17(e)(1). (l) pre-als essn ent,In addition to the requirements in ASME/AI\SI 831.85 section G.l and NACE Rp 0502-2(X12, section 3, the plen's procedures for pre-assessment must includ* (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a cover.ed segment' Q\ Indbect Examinatiott ln addition to the requirements in ASMEIAN$ 831.8S iection 6.4 and NACE RP 0502-2002, section 4, the plan's procedures for indirect examination of the ECIIA 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 excava*on anO direct examination. Minimum identification criteri| include the known sensitivities of assessment tools, the procedurw for using each tool, and the approach to be used for deereasing 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 exrmination of erch indication identilied durtng ttre indiiect examination. These criterie must specify how an operator wilt define the urgency of excavating the indication as immediate' scheduled or monitored; and 1iv; Criteria for scheduling excavation of indications for each urgency level. p) Direct wamination In addition to the requirements in ASME/ANSI B31.ES r".tioo 6.4 and NACE RP 0502-2002, section 5, the plan's procedures for direct exemination of indications from the indirect examination must include (i) Provisions for apptying more restrictive criteria when conducting ECDA for the first time on a covered sesmsnll (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 @) Root cause analysis reveals conditions forwhich ECDA is not suitable (Section 5.6J of NACE RP0502-20v2). $ 192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity?#

220071009M_notice sent_05222007.pdf, page 10(a) General. After completing the baseline integrity assessment of a covered segment, an operator must continue to assess the line pipe of that segment at the intervals specified in § 192.939 and periodically evaluate the integrity of each covered pipeline segment as provided in paragraph (b) of this section. (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 § 192.917... For all other transmission pipelines, the evaluation must consider the past and present integrity assessment results, data integration and risk assessment information (§ 192.917), and decisions about remediation (§ 192.933) and additional preventive and mitigative actions (§ 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 4A: § 192.925(b)(3)(ii)(B) There is no documented process for performing root cause analysis when the operator uncovers problems for which ECDA is not well suited. • Item 4B: § 192.925(b), § 192.917(a) and (c), and § 192.937(a) and (b) CGT has no documented process to continuously assess for SCC during the direct examination step of the ECDA process. Further, there is no evidence that SCC assessments have been completed for examinations performed to date. • Item 4C: § 192.925(b)(3)(i) CGT could not identify provisions in its ECDA Plan or more restrictive criteria it applied when conducting the ECDA direct examination step for the first time on a covered segment. §192.911(e) §192.911(e) Provisions meeting the requirements of § 192.933 for remediating conditions found during an integrity assessment. § 192.933 What actions must be taken to address integrity issues? (a) General requirements... An operator must be able to demonstrate that the emediation of the condition will ensure that the condition is unlikely to pose ‹ hreat to the integrity of the pipeline until the next reassessment of the coverer segment... 10#

220071009M_notice sent_05222007.pdf, page 11...A reduction in operating pressure cannot exceed 365 days without an operltor pnoviding r techniial justification that thc continued pressure restriction will not ieopardize the integrity of the pipeline. (b) Discovery of condition. Discovery of a condition occutll when an operator has adeqoate in-formation about a condition to determine that the condition presents a poteoti"l threat to the integrity of the pipeline. A condition that presents a potential thrcat includes, nut is not limited to, those conditions that require remediation or monitoring tisted under paragraphs (rilf) through (dX3) of this section. An operator -orip.omPtlY, bui no later than 180 days after conducting an integrity assessment, obtain suflicient information about a condition to make that determination, unless the operator demonstrates that the 180'day period is impracticable. (c) Schedulefor evaluation and remcdiotion. An operator must complete remediation of a condition according to a schedule that prioritizes the conditions for evaluation and remediation. Unless a special requirement for remediating certain conditions applies, as provided in paragraph (d) of this section, an operator must follow the scheiurc in ASME/AIrISI831.85 (ibr, see $192.7)' section 7' F'igure 4. If an operator cannot meet the schedule for any condition, the operrtor must justrfy th. "."sons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety. (il) Speciat requbements for scheduling temediutian.- e) Monitored conditiow, An operator does not have to schedule the following conditions for remediation, but must record and monitor the conditions during subsequent risk assessments and integrity assessments for any change that may require remediation: (i) A dent with a depth gre*ter then6Vo of the pipeline diameter (greater than 0.50 ilches in depth for a pi[e[ne dismeter less than NPS 12) located between the 4 o'clock position and the 8 otclock position ftottom l/3 of the pipe). (ii) A dent located between the 8 o'clock and 4 o'clock positions (upper 2 /3 of the pibe) witfr a depth greater than 67o of the pipeline diameter (greater than 0'50 ioin*t in depth fori pipeline diameterlessthan Nominal Pipe Size (NPS) 12)' and engineering analyses oftUu dent demonstrrte critical strnin levels rre not exceeded. (iir) A dent with a depth greater thrrn2o/a of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curuature at a girth weld or a longitudinal seam weld, and engineering tnalyges of the dent and gi*tt o" seam weld demonetrate critical strain levels are not exceeded. These analyse must consider weld propertiee. r Item 5A: $ 192.933(c) 11#

220071009M_notice sent_05222007.pdf, page 12The CGT IMP does not have a requirement to develop a schedule that prioritizes evaluation and remediation of anomalous conditions. Item 58: $ 192.933(dX3) There are no detailed procedures to describe the process for recording anomalies that are classified as "monitored conditionso'and monitoring them during subsequent risk assessments and reassessments. Item 5C: $ f92.933(c) There are no detailed procedures describing a repeatable process by which technical justifications are produced when anomaly evaluation timeframes cannot be met- Item 5D: $ 192.933(c) The CGT remediation schedule does not provide the criteria in Section 192.93J of the Rule or in ASME B3l.8S which is the basis for remediation of the respective anomalies. o Item 5F: $ f92.933(a) There is inzufficient evidence in the CGT remediation records to demonstrate that an anomaly is unlikety to tlreaten the integrity of the pipeline before the next scheduled reassessment. The operator relies upon contractor's reports to provide this evidence, however the contractor's reports do not provide sufficient details for these conclusions. For example, safe pressure calculations need to be documented to demonstrate thc basis of safety urtil reassessments are performed. 6. $1e2.er1(h) $192.9110) Provisions meeting the requirements of $ 192.935 for adding preventive and mitigative measures to protect the high consequence area. $ 192.935 Whnt additionrl preventive and mitigative measures must an operator take? (n) General requiremenls. An operator must take additional mettures beyond those already rcquired by Pert 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 opsrator has identilied to each pipeline segment. (^fee $ L92,917) An operator must conduct, in aecordance with one of the risk assessment approaches in ASME/AIISI831.85 (ibr, see $ 192.7)' section 5, a risk analysis of its pipeline to identify additional metsuros to protect the high consequence area and enhance public safety. Such additional measures t2#

220071009M_notice sent_05222007.pdf, page 13include, but are not limited to, installing Automatic Shut-off Valves or Remote Control Valves, installing computerized monitoring and leak detection systems, placing pipe segments with pipe of heavier wall thickness, providing addition: "aining to personnel on response procedures, conducting drills with loca emergency responders and implementing additional inspection and maintenance programs. § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (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. (5) Corrosion. If an operator identifies corrosion on a covered pipeline segment that could adversely affect the integrity of the line (conditions specified in § 192.933, the operator must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics. An operator must establish a schedule for evaluating and remediating, as necessary, the similar segments that is consistent with the operator's established operating and maintenance procedures under part 192 for testing and repair. • Item 6A: § 192.935(a) The CGT IMP does not include an evaluation of threats, a spectrum of preventive and mitigative (P&M) alternatives, and the potential impact on the identified risks for HCA segments. • Item 6B: § 192.917(e) (5) There is a lack of program requirements to ensure that identified corrosion issues that meet the "immediate" classification are evaluated for pipeline segments outside of HCAs. 7. §192.911(k) Section 11) A management of change process as outined in ASME/ANSI B31.8S, §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 13#

220071009M_notice sent_05222007.pdf, page 14initial program framework and subsequent program must, at minimum, contain the following elements. When indicated, refer to ASME/ANSI B31.85 (ibr, see § 192.7) for more detailed information on the listed element.) • Item 7A: § 192.911(k) The criteria used to determine when an MOC form is used to track physical changes to the pipeline are inadequate. Physical changes are being made to the pipelines that are not being tracked using the MOC process. • Item 7B: § 192.911(k) The MOC process does not provide sufficient procedures to describe how a change identifies affected documentation and how the change is communicated to affected parties. • Item 7C: § 192.911(k) The MOC process does not have provisions to ensure that integrity management system - changes are properly reflected in the pipeline system and that pipeline system changes are properly reflected in the integrity management program. 8. §192.911(1) §192.911(1) A quality assurance process as outlined in ASME/ANSI B31.8S, Section 12. §192.911 What are the elements of an integrity management program? An operator's initial integrity management program begins with a framework (see 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 § 192.7) for more detailed information on the listed element.) (I) A quality assurance process as outlined in ASME/ANSI B31.8S, section 12. § 192.915 What knowledge and training must personnel have to carry out an integrity management program? (a) Supervisory personnel. The integrity management program must provide that cach supervisor whose responsibilities relate to the integrity management program possesses and maintains a thorough knowledge of the integrity management program and of the elements for which the supervisor is responsible. The program 14#

220071009M_notice sent_05222007.pdf, page 15must provide that any person who quelilies Ns a superrisor for the integrity matragemcnt program has appropriate training or experience in the area for which the person is resPonsible. (b) Persozs who earry out assessments and anluate assessment resalts. The integrity managemcnt program must provide criteria for the qualification of any person- (f) Who conducts an integrity assessment allowed under this subpart; or (2) Who reviews and analyzes the results from an integrity assessment and evaluationl or (3) Who makes decisions on actions to be takeu based on these assessments. (c) Persons responsiblefor preventive and mitigetive mccsures. The integrity managemenr program must provide criteria for the qualification of any person- (f) Wio inpliments pr*enti"u and mitigative measures to carry out this subpart' inctuding tfe marking and locating of buried structures; or (2) Who directly supen'ises excavation work carried out in conjunction with an integrity assessment $ f92.7 Incorporation by reference. (a) Any documents or portions thereof iucorporated by refercnce in this part are incluOea in this part as though set out in full'When only a portion of a document is referenced, the remainder is not incorporated in this part. r Item 8A: $ f92.91f0) CGT extensively uses contracted services to accomplish important aspects of its IMP. In many areasi, th" torp""tion Team noted that CGT relies on its contactors to perfornr IMP related work without suffrcient guidance and quality as$rance procedures and processes. r ltem 8B: g f92.9f5(a), (b), and (c) CGT has not established qualification requirements for personnel participating in IMP activities, including in-house personnel responsible for evaluating assessment results. 15#

220071009M_notice sent_05222007.pdf, page 16' Response to this Notice This Notice is provided pursuant to 49 U.S.C. $ 6010S(a) and 49 C.F.R. $ 190.237. Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Cimptiance Proceedings. Please rcfer to this document and note the response options. Be advised that all material you submit in response !o this enforcement action is subject to being made publicly available. Hyou believe that any portion of your responsive mlerial qualifies for confidential treatunent rurder 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document wirh the portions you believe qualify for confidential treatnent redact,ed and an explanation of why you believe the redacted inforrration qualifies for confidential treafinent under 5 U.S.C. 552(b). 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 Adminisha0or for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order' Il after opportunity for a hearing, you plans or procedures are found inadequate as alleged in this Notice, yo,r *uy be ordered iounrrnd your plans or procedures to correct the inadequacies (49 C.F.R. S 190.237). If you are not contesting this Notice, we propose that 1ou submit your amended procedwes to my office within 30 days of receipt of this Notice. This period may be extended by written request for good cause. Once the inadequacies identified herein have been addressed in your amEsd"6 procedures, this enforcement action will be closed. ln correspondence concerning this matter, please refer to CPF 2-2007-1009M and, for each document you submit, please provide a copy in electronic fonnat whenever possible. Sincerely, r |a\ 0-r ,Kj^-€lq\W Linda Daugherty U \J Director, Southern Pipetine and Hazardous Materials Safety Administration Enclosure: Response Optiorufor Pipeline Operators in Compliance Proceedings 16#

220071009m_notice of amendment_06182007_text.pdf, page 1Official PDFF Is 0M tMON1, 1UN 18 2007 15 00/8T 14 59/N 68024Ii8986 F 2 Seawl L Ooxior Yise Pressdenr tonenersxsl p, Fiekl Operations ssiaiier@ssoaa, sara CAHOLlkA GAS 75bSICfhflSSlON A SCAHA COMPANY 3iuie 18, 2007 VIA OVERNIGHT Dr. l IVKRY AND FACSIMILE Ms Linda Daugherty Director, Southern Region Pipeline and Hazardous Material Safety Administration U, S Department of Transportation 233 Peachtree Street, Suite 600 Atlanta, GA 30303 Re' Carolina Gas Transmission Corporation, CPF 2-2007-1009M Request For Extension of Time. or, in the Alternative, Request for Hearing and Statement of Issues Dear Ms, Daugherty: On May 22, 2007, Carolina Gas Transmission Corporation ("CGT") received a Nouce of Amendment ("NOA") dated May 22, 2007, issued by the Southern Region of the Department of I ransportation's Office of Pipeline and Hazardous Materials Safety Administration ("PHMSA"), ln the NOA, based on its review nf CGT's Integrity Management Program ("IMP") conducted in Columbia, South Carolina, during the weeks of October 2-5 and 23-26, 2006, PHMSA states that it has idenu lied apparent inadequacies within CGT's IMP plans or procedures CGT respectfully requests a ninety (90) day extension of time within which to respond to thc NOA, such that CGT's response to the Notice would be due September 19, 2007. CGl requests this extension in order to (1) more fully review the items listed in the 'NOA; (2) secure necessary assistance and staffing to revise the elcmcnts of CGT's IMP plan addressed in the NOA in a comprehensive aud consistent manner; and (3) address in more detail the items Iisted in d separate Notice of Proposed Violation, dated May 22, 2007, in Docket CPF-2-2007-1010, which arises out of the same audit that lead to the NOA To ihe extent this request for an extension of time is denied, CGT hereby requests a hearing pursuant to 49 C. F. R. ( 190. 211 in order to present to PHMSA a proposal for developing amended compliance procedures that appropriately comply with each of the regulations referenced in the NOA, Pursuant to 49 C. F, R. ) 190. 211(e), CGT requests that the materials; in the agency's case files be provided to CGT at least 30 days before any hearing date During the hearing process, CGT will be represented by counsel. (aroenss teas Transmission I P 0. lax 102I07 iblotnbia, South Carolina ~ 292242407 I 1803) 217b457 ~ F (803) 933 71d0#

220071009m_notice of amendment_06182007_text.pdf, page 2Ms. I. inda Daugherty June 18, 2007 Page 2 CGT respectfully requests that any correspondence and communications regarding this request for a hearing be directed to the following; Laura A, Comstock Supewisor, Safety and Compliance Carolina Gas Transmission Corporation 105 New Way Road Columbia, South Carolina 29224-2407 Sincerely, Samuel L. D iiex Vice President, Commercial and Field Operations cc, B, Craig Collins T. Wayne Vermullen#