WILLIAMS GAS CO — Corrective Action Order

case documentOfficial PDF520031003H.pdf#

case documentOfficial PDF520031003HA.pdf#

case documentOfficial PDF520031003H_CAO_05022003.pdf#

case documentOfficial PDF520031003h_cao_05022003_text.pdf#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 1Official PDF?} U.SDeoortment of Tronsoortolion Reseorch ond Spe€iol Prognoms Admanistrolion 40o Seventh St S.W Washrngton. O C 20590 Ai,1 ," '.^,.\ A .. .' ],+ Mr. Randy Bamard Vice President of Operations Williams Gas Pipeline - Northwest 2800 Post Oak Boulevard MD-21 Houston, TX 77056 Re: CPFNo. 5-2003-1003-H Dear Mr. Bamard: Enclosed is the Post Hearing Decision to the Amendment to the Corrective Action Order in this case. The Post Hearing Decision includes a Second Amendment to the Corrective Action Order and proposes an additional amendment, The Second Amendment clarifies and modifies some of the provisionsoftheDecemberl8,2003AmendmenttotheCorrectiveActionOrder. ThisPostHearing Decision also notifies you of a proposed amendment that would require you to take additional corrective action involving your communication and liaison procedures with public officials and provide progress reports on the work done under the order. Service is being made by certified mail and facsimile. Your receipt constitutes service under 49 C.F.R. $ 190.5. The terms and conditions of this Second Amendment to the Corrective Action Order are effective upon receipt. You have the right to a hearing with respect to the proposed additional amendment. Sincerely, nf\ v \ 4(A^S^ /\a u H", Revnolds 6tl Pipeline iompliance Registry \ Office of Pipeline Safety Enclosure VIA CERTIF'IED MAIL RETURN RECEIPT REOIJ]ESTED) AND TELECOPY#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 2DEPARTMENT OF TRANSPORTATION RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION WASHINGTON. DC 20590 In the Matter of Williams Gas Pipeline. Northwest, Respondent. CPF No.5-2003-1003-H POST.HEARING DECISION -- SECOND AMENDMENT TO TI{E CORRECTIVE ACTION ORDER AND PROPOSED FURTHER AMENDMENT Purpose and Background On May 2, 2003, the Associate Administrator for Pipeline Safety issued a Corrective Action Order (May 2 Order) in this case, under authority of 49 U.S.C. $ 60112, finding that continued operation by Williams Gas Pipeline - Northwest (Respondent) of its 26-inch natural gas pipeline in westem Washington State would be hazardous to the public, property, and the environment without corrective measures. The May 2 Order was issued as a result of the May |,2OO3 rupture of the line at mile post 1352.7 near Lake Tapps in Pierce County, Washington. On December 13,2003, the line ruptured again. This time the failure occurred near Toledo, kwis County, Washington. On December 18, 2003, the Associate Administrator issued an Amendment to the Corrective Action Order (Amendment) to require additional corrective measures. By letter ofDecember29,2003,Respondentrequesteda"hearingandclarification"andenumeratedsix items of the Amendment it intended to address. A hearing was conducted on lanuary 26, 2004 in the OPS offices in Lakewood, Colorado. Representatives of the Washington Utilities and Transportation Commission (WUTC), which participated in the investigation ofthe accidents as an interstate agent, participated in the hearing. In addition to the six items enumerated in the response, Respondent raised issues and sought clarification with respect to other items of the Amendment. On February 9, Respondent filed its post-hearing submission. Discussion of Items Raised by Respondent Pressure restriction on Sumas to Mt Venton segrnent. Respondent noted that it had been unable to comply with Item 1 of the Amendment on the Sumas to Snohomish portion of the line. Item 1 required reduction of the line pressure to 100 psi by mid-January. By letter of January 12,2004, Respondent had requested additional time to achieve that pressure. Respondent contends that#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 3achieving the reduced pressure can only be done by venting a considerable amount of gas to the atmosphere in the more populated area of the line. Respondent has been unable to reduce the pressure on this segment below 100 psi and still operate the line. Respondent confirmed that this pressure is less than 207o of the specified minimum yield strength of the pipe, a pressure at which it is highly unlikely to rupture. The line was subsequently depressurized for integrity testing. However, if retum to full service is delayed, there is a need to prescribe an acceptable interim pressure. The Regional Director concurs that operation of this segment at pressures up to 200 psi would not likely result in failure. Accordingly, paragraph a. below modifies Item 1 to grant relief. Metallurgical Analysis. Item 2 of the Amendment required Respondent to submit the original of the metallurgical report to the Regional Director within one week of receipt. The Regional Director noted that the goal was to ensure that OPS saw the original version of the metallurgical analysis and that having thd laboratory mail the copy simultaneously with forwarding the report to Respondent would achieve this. Respondent has now submitted a copy of the original report to the Regional Director. IntegriQ management program. Respondent requested clarification with respect to Item 3 of the Amendment: 3. Integrity management. Finalize an integrity management program that conforms to the requirements for integrity management programs published on December 15, 2003 (new subpart O to 49 C.F.R. Part 192) on an expedited basis. The program must address the factors involved in the failures on the line that have occurred since 1990, including stress corrosion cracking and land movement, as risks. Submit this program within 90 days of issuance of this Amendment for approval by the Director, Westem Region. Specifically, Respondent noted the difficulty of developing a plan that will satisfy all of the detailed requirements of the December 15 final rule prior to the development of the protocols and guidance that OPS has indicated will be forthcoming. The Regional Director agreed that some of the details may need to be filled in later, but noted that, based on a December 10,2003 meeting, Respondent had already done a considerable amount of work in analyzing the risks on the lines subject to this order. It is not unreasonable to require Respondent to produce a first version of an integrity management plan for the lines covered by this order on an expedited basis. At the hearing, the Regional Director agreed to review an eady draft and provide feedback on the adequacy of the plan to meet the requirements of the Amendment and the areas which Respondent may need to address in the future as it implements the integrity management program for its entire system. Respondent informally submitted its draft on February 2,2004 andhas engaged in discussions with regional staff about the scope. To allow these discussions to continue, the Regional Director extended time for submitting the program until April 18, 2004. Accordingly, paragraph b. below modifies item 3 of the Amendment to again allow for a slight extension of time and to allow for future development of a complete integrity management program.#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 4Pipe replacement. Item 4 of the Amendment requires Respondent to develop a prioritized plan to remove pipe that is subject to stress corrosion cracking from the 26-inch line if it intends to request removal of the current pressure restrictions. The plan may allow for implementation to extend over aten-year period. Although the term "replacement" is used, nothing in the Amendment requires Respondent to continue operating or to replace the line pipe with pipe of equivalent size. Respondent would satisfy the replacement requirement by constructing a new pipeline that meets future capacity needs and abandoning (in accordance with 49 C.F.R. $ 192.605) all or sections of the cuffent 26-inch line requiring replacement. As an initial argument, Respondent challenges the need to replace pipe in the 26-inch line. Respondent argues that OPS lacks authority to order replacement with the information available to it. Respondent urges OPS to consider an approach that allows the line to continue in service indefinitely so long as it is managed through an integrity management program. Section 60112 of Title 49, United States Code, expressly allows OPS to order "suspended or restricted use of the facility, . . ., replacement, or other appropriate action" ifthe agency determines that the pipeline facility at issue is or would be hazardous but for the corrective actions. As already noted, replacement in this context does not require Respondent to replace with equivalent pipe, but does require that the hazardous pipe be removed from service. In this case, OPS has presented evidence of numerous SCC failures that have occurred on the line. There is evidence that the pipe is subject to several of the factors in SCC - nature of the coating, environmental conditions, and metallurgical toughness of the pipe. The same toughness factors make the pipe prone to failure during land movement, which is also a well-recognized risk in the area. Respondent has not challenged this evidence or the conclusion of OPS that corrective action is needed. The question comes down to the reasonableness of a requirement to remove pipe rather than to manage the risk of SCC and earth movement through some other means, Evidence of pipeline failure due to land movement was detailed in the May 2 Order in this case. The followine indicates that SCC is a serious and pervasive problem on this line: The metallurgical report on the 1992 SCC failure south of Snohomish indicated that there was a family of deep cracks on the pipe examined. The report recommended periodic hydrostatic testing to identify and remove the SCC in the line. Hydrostatic testing of a 4.8 mile segment of a l6-inch lateral in 1994 resulted in 22 SCC failures. The report on the 1999 Mt. Pleasant failure noted 21 othercracks in addition to the crackthat caused the failure. The report on the May L, 2003 SCC failure noted numerous other cracks due to SCC in the pipe examined. The report on the December 73,2003 SCC failure that underlies the Amendment also indicates that there are several other cracks due to SCC that had not failed in the pipe tested.#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 5The Ulffascan crack detection done in 2003 revealed 38 SCC colonies in the three miles from Sumner to White River. There have been 8 digs in this three-mile segment in which over a hundred anomalies have been noted. At least one of these was a crack with 100Vo penetration of the pipe and at least 10 had a depth of more than25Eo. At the hearing, Respondent claimed that the transverse field inspection tool (TFI) can accurately detect, and thus be used to manage, SCC in the26-inch line. Noel Duckworth, an expert in internal inspection technology, discussed the limitations of the TFI in locating SCC. In his opinion, the tool does not at this time reliably detect SCC sufficiently in advance of failure for it to be used for long- term management. The limitations stem from the manner in which the tool measures anomalies, rather than from the quality of the analysis done of the inspection data. Although Respondent pointed out that Mr. Duckworth's assessment was opinion, not fact, Respondent did not present evidence that supported a contrary view. OPS is left with the information before it. There is a history of SCC with two failures in the past year, the existence of several known parameters for SCC, an expert opinion that TFI will not detect SCC in time to prevent failure, and no countervailing evidence, Respondent indicates that a complete understanding of the SCC parameters at issue could allow an integrity management program to eliminate the threat of SCC failures and that it should not be ordered to replace the line until it can gain that complete understanding. It is not clear, however, when Respondent will have enough information to present such a case or whether technology will indeed provide sufficient certainty to manage the SCC on this line for an indefinite time. Respondent indicates that hydrotesting being done may provide data that would be helpful and that I-Jltrascan crack detection has been accurate. However, discussions at the hearing indicate that Ultrascan cannot be used on the entire system because of the hilly terrain. In the meantime, OPS is faced with the real risk of a future failure. The Amendment does not require Respondent to replace line pipe if replacement is not necessary for safety and is otherwise reasonable with respect to the replacement program. The terms of the Amendment expressly provide Respondent with the opportunity to present the case that a particular segment is not subject to SCC and that replacement is not necessary (Items 4.v. and 6). As examples, this showing could be evidence that, because of different construction, manufacturing techniques, or pipe materials, a particular segment is not subject to SCC. To the extent that extenuating circumstances mean that, despite all efforts, Respondent cannot make a decision about replacement of the capacity within the 120 days cunently required for a replacement plan, the order allows for extensions of time for good cause. In addition, if the hydrotesting and trials of the Ultrascan crack detection provide new unexpected and convincing data indicating that SCC can be managed on this line, Respondent may request OPS to amend the order with respect to the replacement program. Accordingly, this Second Amendment does not change the requirements of Item 4 of the Amendment which addresses the current risks accordins to the current realitv.#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 6to seek removal from pressure restrictions for pipe in the replacement program. The basis is an oManaging SCC until replacement. Item 5 of the Amendment provides a provision for Respondent adequate demonstration that SCC can be managed as a temporary measure through periodic hydrostatic testing or intemal inspection. Respondent has requested some modification of these procedures. First, Respondent has asked that it be allowed to retum a segment to service after successful completion of a hydrostatic test but prior to the establishment of the interval for retesting. Respondent asks that it be allowed 90-120 days to establish this interval. This additional time will allow for better analysis of the test data, including analysis of any failures that occur. There is literature available that provides guidance on appropriate retest intervals and it is appropriate that Respondent use this guidance to establish an interim interval prior to requesting permission to return to service. If this is done, allowing Respondent to adjust the retest interval within 90 days after complete analysis is reasonable. This provides assurance that there will always be an interval in place for retesting. Paragraph c. below provides for this modification. Second, Respondent has asked that the "spike test" be conducted for no more than 30 minutes rather than for the t hour provided in Item 5. iii. and thatthe pressure of ll0%o of the specified minimum yield strength (SMYS) not be required for the entire segment. The Regional Director has agreed that this is acceptable provided the entire segment be tested to a minimum of lOUVo SMYS with the weakest pipe, typically 0.28l-inch pipe, testing to LLOVo SMYS at some point in the test section. Respondent's post-hearingcomments assert that the Regional Directorhas indicated that only0.281- inch pipe need be tested. That assertion is incorrect and all pre-1970 pipe must be tested. Paragraph c. below provides for modification with respect to the terms of the "spike test". Third, Respondent has asked that, if intemal inspection using a combination of TFI and magnetic flux tools is used, it be allowed up to one year to address the anomalies after a retum to service. Some anomalies may require expedited repair, but a repair schedule that addresses the most critical first (prior to return to service) and allows additional time for noncritical repairs is acceptable. Paragraph d. below provides for this modification. Finally, discussion at the hearing indicated public concern about safety when work is done on a pipeline and Respondent's willingness to include provisions for a public safety procedure in the protocol for hydrostatic testing. Based on continuing concern from local officials, OPS proposes, below, to further amend this corrective action order to provide for a public safety procedure for all activities conducted under the order that could create the need for public safety decision-making by federal, state, or local officials. Evaluation of other lines. Item 8 requires Respondent to evaluate certain other lines for susceptibility to SCC and to report the findings and response to the Regional Director. Respondent has sought clarification as to the requirement. Item 8 does not require Respondent to evaluate the other lines using hydrostatic testing or internal inspection, or indeed to select either in selecting the o#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 7response to the evaluation. If, at some time in the future, OPS determines that either is needed, it may further amend the order. No change to the Amendment is needed. Modifications of the Required Corrective Action of the Amendment Pursuant to 49 U.S.C. $ 60112, I hereby amend the corrective action of the December 18, 2003 Amendment to the Corrective Action Order (Amendment) as follows: Item I of the Amendment (addressing pressure restrictions on the 26-inch line) is amended by adding the following language: ff a reduced pressure of 100 psi cannot be maintained on the Sumas to Snohomish segment, Respondent may reduce the pressure and operate the line at a maximum pressure of 200 psi as needed to maintain a minimal line pack on the segment. b. Item 3 of the Amendment is modified to read as follows: 3. Integrity management. Develop an integrity management program covering the lines subject to this orderthat substantiallyconforms to the requirements forintegritymanagement programs published on December 15,2003 (new subpart O to 49 C.F.R. Pafi 192) on an expedited basis. The program must address the factors involved in the failures on the line that have occurred since 1990, including stress corrosion cracking and land movement, as risks. The program must include at least the following elements of an integrity management program: 49 C.F.R. $$ 192.911(a), (b), (c), (e), (f), (h), (i), 0), (l) and (m). Submit this program to the Director, Western Region by April 30,2004 for his approval. c. Item 5 iii. of the Amendment is modified to read: iii. Successful completion of hydrostatic testing must include a "spike test"; that is, a test with someportionofthesegmentexperiencingll0percentofthespecifiedminimumleld strength of the weakest pipe in the test section for a period of 30 minutes and no segment experiencing less than 100 percent, The spike test must be followed by a test at a minimum of 90 percent of the specified minimum yield strength for eight hours. Each failure must be metallurgically tested to identify cause and failed pipe must be replaced with pretested pipe. In supporting the request for removal of the pressure restriction, Respondent may submit for approval an interim interval for reassessment of a pipe section based upon general guidance. Respondent must then provide a final interval for reassessment based upon additional analysis within 90 days of removal of the pressure restriction.#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 8d. The last bullet of Item 5. iv. of the Amendment is modified to read as follows: . Following written procedures approved by the Director, Western Region, that include fitness for service criteria for identifying, pri oitizing, and correcting defects within one year after removal of the pressure restriction. The terms and conditions of this Amendment are effective upon receipt. Failure to comply with this Order may result in the administrative assessment of civil penalties of not more than $i00,000 per day and in referral to the Attomey General for appropriate relief in United States District Court. Pronosed Further Amendment - Public Safety Procedures: Progress Reports Since I issued the Amendment to the Corrective Action Order, public safety officials have expressed concern that an ineffective and uncoordinated flow of information from the Respondent about the pipelines is hindering their ability to execute their public safety responsibilities and to protect persons in the vicinity of the pipeline. This proposed additional amendment proposes additional corrective measures based on the following: . In meetings with the Associate Administrator for Pipeline Safety, public officials from Skagit, Puyallup and Bellevue, WA, and representatives of the WUTC expressed concern that more information from Respondent about the condition and ongoing operations ofthe subject pipeline was necessary to avoid confusion, enhance coordination and better protect the citizens for whom the officials are resoonsible. In a meeting with the Associate Administrator for Pipeline Safety, the Fire Chief of Puyallup, WA expressed concern that more information from Respondent concerning its planned operating activities was necessary for the Fire Chief to effectively carry out his responsibilities. In addition, corrective action orders with extensive measures require significant monitoring effort on the part of OPS. Based on the experience thus far, OPS believes that periodic progress reports are necessary for effective monitoring. Accordingly, I propose to further amend this coffective action order by adding the following items: 10. Identify actions or series of actions taken under this order that may require rapid decision- making by responsible authorities at the community level to protect the public safety such as through evacuations, road closings, or notifications of police, fire, or other emergency responders (such actions would include, but are not limited to, line restarts, pressure testing, purging, and other significant excavation activities). Develop procedures for communicating timely notice of such actions to federal, state, and local officials and for maintaining liaison to coordinate pre-planned and actual response activities with the appropriate officials that provide for appropriate notice to the public officials. Provide a copy of these procedures to the Director, Westem Region, within 30 days (of issuance of an amendment including this term).#

520031003H_post-hearing decision on CAO amendment_04092004.pdf, page 91L Provide Progress Reports on actions taken under this order on a monthly basis to the Director, Western Region, that include at least the following information: Number of miles of pipe hydrostatically tested, number of failures, and suspected causes with updates based on results of the metallurgical testing. ll. (For each type of nondestructive test performed) The number of miles tested, the number and nature of anomalies found, and the number and nature of repairs made. Within 10 days of receipt of this proposed amendment, Respondent may request a hearing, to be held as soon as practicable, by notitlng the Associate Administrator for Pipeline Safety in writing, delivered personally, by mail or by telecopy at (202) 366-4566. The hearing will be held in Lakewood, Colorado or Washington, DC on a date that is mutually convenient to OPS and Respondent. Failwe to respond authorizes the Associate Administrator to issue an amendment consistent with this notice. APR - g 2m4 Date Issued for Pioeline Safetv#

520031003h_amendment to cao_12182003_text.pdf, page 1Official PDFU5 Department or Tronsporiarion taeaearch and SpeckN Aogrwna AglmlirlattcNon c0o ~enih si s w waahegl0n D C 20590 DEC 18 21lc3 Mr Randy Barnard Vice President of Operations Williams Gas Pipeline - Northwest 2800 Post Oak Boulevard MD-21 Houston, TX 77056 Re CPF No. 5-2003-1003-H Dear Mr. Barnard Enclosed is an Amendment to the Corrective Action Order issued by the Associate Admmistrator for Pipeline Safety m the above-referenced case. It requires you to take additional corrective actions with respect to your 26-inch line in Western Washington and to evaluate your 30- inch parallel line, the 26-inch line from the Washougal Compressor Station east to the Goldendale Compressor station, and all transmission lines from the Washougal Compressor Station south to Grants Pass, Oregon, for similar safety concerns. Service is being made by certified mail and facsimile. Your receipt of this Amendment constitutes service of that document under 49 C F R g 190 5. The terms and conditions of this Amendment to the Corrective Action Order are effective upon receipt Smcerely, James Reynolds Pipehne Compliance Registry Once of Pipeline Safety Enclosure Vl. a C ED MAIL RETURN El RE STE ND ECOPY,#

520031003h_amendment to cao_12182003_text.pdf, page 2DEPARTMENT OF TRANSPORTATION RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION WASHINGTON, DC 20590 In the Matter of Williams Gas Pipeline - Northwest, Respondent. ) CPF No. 5-2003-1003-H A ENDM TT CO ACTION ORDER Pur ose and Back round On May 2, 2003, the Associate Administrator for Pipeline Safety issued a Corrective Action Order (May 2 Order) in this case, under authority of 49 U S. C g 60112, finding that continued operation by Williams Gas Pipeline - Northwest (Respondent) of its 26-inch natural gas pipeline in v estern Washington State would be hazardous to the public, property, and the environment v ithout corrective measures The May 2 Order was issued as a result of the May 1, 2003 rupture of the linc at mile post 1352. 7 near Lake Tapps in Pierce County, Washington. The May 2 Order restricted operating pressure on the linc and required Respondent to conduct a metallurgical analysis of the May 1, 2003 failure, to re-evaluate in-lme inspection surveys, to do a geotechnical evaluation of the area, and to take appropriate remedial action On December 13, 2003, the hne ruptured again This time the failure occurred near Toledo, Lee is County, Washington Pursuant to 49 U. S. C. ) 60117, thc Western Region, Office of Pipeline Safety (OPS) initiated an investigation of the incident, The Washington Utilities and Transportation Commission (WUTC), which, as an interstate agent, inspects the line for compliance with pipeline safety regulations, is participating in the investigation. Additi nal Prelimina 'nd s ~ On the morning of December 13, 2003, a rupture occurred on Respondent's 26-inch gas transmission pipeline at Mile Post 128LS, approximately 7 miles south of the Chchalis compressor station in Lewis County, Washington. AAer confirming that the pressure drop that had been detected was indeed a failure, Respondent reported the failure to th«National Response Center at approximately 11. 15 A. M. 1, "ST.#

520031003h_amendment to cao_12182003_text.pdf, page 3The failure resulted in the release of gas for at least three hours. There was no ignition and no fatalities or tnJunes. The residents of 4 of the 12 homes in the vicinity evacuated voluntarily The linc is located in primarily rural locations. Howcvcr, thc line is in close proximity to population where the line passes through the Seattle area, Whatcom County, as well as other communities. There were houses within 250 yards of the failure site as well as a road crossing approximately 30 feet away. The maximum allowable operating pressure (MAOP) had been reduced by 20 percent by the May 2 Order. Visual examination of the failed section revealed a dark stain at the edge of the rupture area which is indicative of corrosion. Field examination revealed signs of moisture beta een the 1957 vintage tar coating and the pipe wall and indications of surface corrosion and pitting Visual examination also revealed significant longitudinal cracking of the pipe body that appears to be stress corrosion cracking (SCC) The May 2 Order required a metallurgical analysis of the May I, 2003 failure The analysis, performed by an independent laboratory, found that the cause was stress corrosion «racking (SCC). The May 2 Order also required a geotechnical evaluation This evaluation, performed by an independent consultant, indicated that land movement. originally thought to be a factor, was not the cause. According to a November 1992 metallurgical report by an independent third party, the failure that occurred on the line approximately 7 miles south of Snohomish during hydrotesting was causedl by stress ~convsion . :. «. . ' in, An Apnl 23, 1999 metallurgical report by an independent third party consultant indicated that stress corrosion cracking was involved in a leak that occurred near M. P. 1255 5 in March 1999 In addition to the failures on the line within the State of Washington, there were 22 fail wes duc to SCC expenenced dunng hydrostatic testing of a 16-inch lateral between June and August 1994 between Mile Posts 21 and 26 near Oregon City, Oregon. On October I, 2003, OPS issued an advisory bulletin to owners and operators of gas and hazardous liquid pipelines advising them to assess their pipelines for susceptibility to SCC Th« bulletin contains detailed instructions on identifying and addressing the SCC threat The 0 play a role in SCC include the operating pressures, imposed loads placed on pipeline due to stress, the acidity of the soil, and coal tarcoating. These are factors found on this 26-inch line#

520031003h_amendment to cao_12182003_text.pdf, page 4~ Respondent operates a 30-inch pipeline parallel to the 26-inch line that is the subject of the May 2 Order This line is of newer construction and does not have the failure history of the 26-inch line However, it is subject to the same land movements and soil conditions, and has coal tar coating Determination of Necessity for Corrective Action Order and Right to Hearing Section 60112 of Title 49, United States Code, provides for the issuance of a Corrective Action Order, aAer reasonable notice and the opportunity for a hearing, requiring corrective action, which may include the suspended or restricted use of a pipeline facihty, physical inspection, testing, repair, replacement, or other action as appropnate The basis for making the determmation that a pipeline facility is hazardous, requinng correct& ve action, is set forth both in the above referenced statute and 49 C. F. R. )190. 233, a copy of which is enclosed. Section 60112, and the regulations promulgated thereunder, provide for the issuance of a Corrective Action Order without prior opportunity for notice and hearing upon a finding that failure to issue the Order expeditiously will result in likely senous harm to life, property or the environment. In such cases, an opportunity for a hearing will be provided as soon as practicable aAer the issuance of the Order AAcr evaluating the preliminary findings of fact, I continue to find that the operation of Respondent's 26-inch line between the Sumas station near the Canadian border and the Washougal station near the Columbia River (Sumas-Washougal 26-inch line), without corrective measures would be hazardous to life, property and the environment and that additional measures arc required Additionally, aAer considering the age of the pipe, the population near the pipeline in western Washington state, the excessive land movements in the area, the prior history of the pipeline, the May 1, 2003 accident attributed to stress corrosion cracking, the possibility that the December 13, 2003 accident was also caused by stress corrosion cracking, and the fact that a second accident occurred under the reduced operating pressure, I find that a failure to expeditiously issue this Amendment, requiring immediate corrective action, would likely result in serious harm to life, property, and the environment. Accordingly, this Amendment mandating needed immediate correcti ve action is issued without prior notice and opportunity for a heanng. The terms and conditions of this Amendment are efYectivc upon receipt. Within 10 days of receipt of this Amendment, Respondent may request a hearing, to be held as soon as practicable, by notifying the Associate Administrator for Pipeline Safety in wnting, delivcrcd personally, by mail or by telecopy at (202) 366-4566. The hearing will be held in Lakcwood, Colorado or Washington, DC on a date that is mutually convenient to OPS and Respondent#

520031003h_amendment to cao_12182003_text.pdf, page 5After receiving and analyzing additional data in the course of tlus investigation, OPS may identify other corrective measures that need to be taken. In that event, Respondent will be notifie of any additional measures required and further amendment of the May 2 Order will be considered. To the, extent consistent with safety, Respondent will be afforded notice and an opportunity for a hearing prior to the imposition of any additional corrective measures. R ird Pursuant to 49 U. S. C. $ 60112, I hereby order Respondent to immedtately take thc following additional corrective actions With respect to the Sumas-Washougal 26-iach Iiae: Arlrhttonal pressure restnctton, Immediately reduce operating pressure on the line and alloi~ depletion of the product to achieve a reduced pressure of 100 psi withia 30 days of issuance of this Amendment. Once the reduced pressure of 100 psi has been achieved, the line may be operated at a maximum pressure of 110 psi as needed to maintain a minimal line pack on thc system. 2. Metallurgical analysts. Conduct a detailed metallurgical analysis of the pipeline that failed nn December 13, 2003 to determine the cause of failure and contributing factors Submit an origmal copy of the report of this analysis to the Director, Western Region, OPS, within one week of your receipt of the report, 3. Integnti management. Finalize an integrity management program that conforms to the requirements for integrity management programs published on December 15, 2003 (new subpart 0 to 49 C. F. R. Part 192) on an expedited basis The program must address the factors involved in the failures on the line that have occurred since 1990, including stress corrosion cracking and land movement, as risks. Submit this program withia 90 days of issuance of this Amendment for approval by the Director, Western Region 4. Replacement program. Withia 120 days of issuance of tlus Amendment, develop a plan for replacement of pipe in those segments for which Respondent intends io seek removal of pressure restrictions as provided for in item 5 below, The plan must provide that A segment in a high consequence area, as defined in the natural gas integrity management rule published on December 15, 2003, which is to be replaced, must be replaced on a priority basis within three years of issuance of this Amendment. A segment in a class 2 area must be replaced within five years of the issuance of this Amendment.#

520031003h_amendment to cao_12182003_text.pdf, page 6iii. All other segments to be replaced must be replaced within ten years of issuance of this Amendment. iv. To the extent that pressure restrictions have been liAed on a segment in accordance v ith item 5, retesting prescribed in item 5 must contmue until replacement. v, Provided that there are no mdicationsof SCC, segments that contam pipe with well-bonded coating and matenal toughness that meet standards for pipelines constructed aAer 1970 need not be replaced. 5 Removal of pressure restrictions. The Director, Western Region, may authonze removal of the pressure restnctions m this corrective action order, as amended, upon request by Respondent Support a request for removal of the pressure restrictions on a segment by demonstrating the fol lowmg. The successful completion of either hydrostatic test or fraternal inspection of the segment in accordance with requirements provided below and the establishment of an approved retest interval for the segment that does not exceed 3 years; or n. There is evidence that the pipe in the segment is not prone to SCC, This mcludes evidence, that the pipe has been replaced smce original construction with pipe meeting standards for toughness and coating acceptable for pipeline constructed since 1970 and has not shown indications of SCC iii. Successful completion of hydrostatic testing must include a "spike test", that is, a test conducted at 110 percent of the specified minimum yield strength of the weakest pipe in the test section fora penod of 1 hour The spike test must be followed by a test at a minimum of 90 percent of the specified mimmum yield strength for eight hours. Each failure must be metallurgically tested to identify cause and failed pipe must be replaced wi th pretested pipe iv. Successful completion of internal inspection must include: ~ Use of a tool that is at least capable of reliably detecting SCC. Tool capability must be validated. Validation is done through hydrostatic testmg of one statistically representative section without failure during the test. This hydrostatic test is done aAcr the tool has been run and all identified SCC anomalies in the section have been addressed. ~ Direct evaluation and repair or replacement of any identified SCC that could fail before the middle of the next test cycle. ~ Follov mg wntten procedures approved by the Director, Western Region, that include fitness for service critena for identifying, pnontizing, and correcting defects#

520031003h_amendment to cao_12182003_text.pdf, page 76. Other exceptions from replacement. At any time, Respondent may present evidence that a segment of pipe that this Amendment requires to be replaced is not susceptible to SCC and request that the Deputy Associate Administrator, OPS, grant an exception to replacement For example, Respondent may present evidence that a segment has been both hydrostatically tested without failure due to SCC and internally inspected without identification of SCC' The decision of the Deputy Associate Administrator granting or denying the request must be in writing 7, Advance no(ifica(ion of activities. Provide the Regional Director, Western Region, at least 5 working days advance notice of the schedules for any testing, inspection, excavation. repair, or replacement done under the corrective action order, as amended. The purpose of this is to allov, the Regional Director the opportumty to arrange for a Federal or State representative to witness thc activity. With respect to the parallel 30-inch line within the State of Washington, the 26-inch line from the Washougal Compressor Station east to the Goldendale Compressor Station, and all the transmission lines from the Washongal Compressor Station south to Grants Pass, Oregon: 8 Evaluate the lines for susceptibility to SCC based on data available and risk factors. Provide a report to the Director, Western Region, within 180 days of issuance of this Amendment on the findings and any programs Respondent is undertaking to address the findings 9, Monthly Progress Reports on the status of the evaluations required in Item 8 must be submitted to the Director, Western Region. Except for a request for a replacement exception (Item 6), the Director, Western Region, may extend the time for the conduct of any item in this order, as amended Respondent may appeal any decision of the Director, Western Region, OPS, or of the Deputy Associate Administrator, OPS, to the Associate Admimstrator for Pipeline Safety. Decisions of the Associate Administrator are final Failure to comply with this Order may result in the administrative assessment of civil penalties of not more than $100, 000 per day and in referral to the Attorney General for appropnate relief m United States District Court. OEC 18 z". : for Pipeline Safety#