GEORGIA-PACIFIC CONSUMER — Warning Letter

420141008W_Warning_08262014_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED August 26, 2014 Mr. Gary Kaiser Sr. Vice President Georgia Pacific, LLC P.O. Box 3333 Crossett, AR 71635 CPF 4-2014-1008W Dear Mr. Kaiser: On multiple occasions between December 2013 and May 7, 2014, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code were onsite and inspected your records and procedures in the field office located in Crossett, AR. Records and procedures for your Integrity Management Plan were inspected in Pasadena, TX. As a result of the inspection, it appears that you have committed a probable violation of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are: 1. §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.) Georgia Pacific, LLC (GP) failed to properly identify a high consequence area as defined in §192.905(a) and appendix E.I. Specifically, the operator failed to apply the axial extension of#

420141008W_Warning_08262014_text.pdf, page 2the 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. On April 14, 2014, GP provided this office the results of the review and a properly identified Map of their HCA on the 14-inch pipeline system which include changes in the total length of the HCA. 2. § 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. (b) Documents supporting the threat identification and risk assessment in accordance with § 192.917; § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31.8S, section 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for the baseline and continual reassessments (§§ 192.919, 192.921, 192.937), and to determine what additional preventive and mitigative measures are needed (§ 192.935) for the covered segment. GP failed to maintain documentation of a risk assessment process that should include the evaluation of data collected during the HCA and threat identification process. Additionally the risk assessment should include the identification of conditions and location specific events that could lead to a pipeline failure along with the probability and consequences of each event. GP only provided a meeting agenda which does not show a structured set of weighting factors to indicate the relative level of influence of each risk assessment component. 3. §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 (incorporated by reference, see § 192.7), section 6.4, and in NACE SP0502-2008 (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#

420141008W_Warning_08262014_text.pdf, page 3information 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 SP0502-2008, 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 RP0502-2002, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method. GP failed to correctly select ECDA regions. After reviewing the assessment data it was clear that Georgia Pacific identified and assessed only one region in the HCA area. The HCA area has a section with cased piping. This cased piping area should be treated as another region to be assessed properly. According to section 3.5.1.1.2 of NACE SP0502-2008, the pipeline operator should consider all conditions that could significantly affect external corrosion when defining criteria for ECDA regions. Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per violation per day the violation persists up to a maximum of $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed $100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series of violations. We have reviewed the circumstances and supporting documents involved in this case, and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the item(s) identified in this letter. Failure to do so will result in Enterprise Crude Pipeline, LLC being subject to additional enforcement action.#

420141008W_Warning_08262014_text.pdf, page 4No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 4-2014-1008W. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#