TAMPA AIRPORT PIPELINE CORPORATION — Notice of Amendment

220126018M_notice of amendment_10022012_text.pdf, page 1Official PDFNOTICE OF AMENDMENT CERTIFIED MAIL - RETURN RECEIPT REQUESTED October 2, 2012 Mr. Robert L. Rose President Tampa Airport Pipeline Corporation P.O. Box 35236 Sarasota, FL 34242 CPF 2-2012-6018M Dear Mr. Rose: From November 8-10, 2011, and March 22, 2012, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Southern Region, inspected the Tampa Airport Pipeline Corporation (TAPC) Pipeline Integrity Management Plan (IMP) in Tampa, Florida, pursuant to Chapter 601 of 49 United States Code. On the basis of the inspection, PHMSA identified apparent inadequacies within TAPC’s written IMP procedures as follows: 1. §195.50 Reporting accidents. An accident report is required for each failure in a pipeline system subject to this part in which there is a release of the hazardous liquid or carbon dioxide transported resulting in any of the following: (a) Explosion or fire not intentionally set by the operator. (b) Release of 5 gallons (19 liters) or more of hazardous liquid or carbon dioxide, except that no report is required for a release of less than 5 barrels (0.8 cubic meters) resulting from a pipeline maintenance activity if the release is: (1) Not otherwise reportable under this section; (2) Not one described in §195.52(a)(4); (3) Confined to company property or pipeline right-of-way; and (4) Cleaned up promptly; (c) Death of any person; (d) Personal injury necessitating hospitalization; (e) Estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000.#

220126018M_notice of amendment_10022012_text.pdf, page 2TAPC’s IMP incorrectly addressed reporting accidents in Section 2.18 Communications Plan, subsection Reporting Accidents or Safety Related Conditions. − TAPC’s procedures required TAPC to submit a leak report and to make a telephonic notice if leak conditions met the criteria in §191.5. However, §191.5 pertains to gas pipelines, not to hazardous liquid pipelines. Moreover, the procedure incorrectly listed the reporting criteria based on the gas pipeline regulations in 49 CFR Part 191, not on hazardous liquid pipeline regulations in 49 CFR Part 195. − Similarly, TAPC’s IMP Section 1.01 Glossary defined the term “incident.” But an “incident” is an event on a gas pipeline. The correct term for a hazardous liquid pipeline is an “accident” and the reporting criteria for accidents are listed in §195.50. 2. §195.452 Pipeline integrity management in high consequence areas. …. (c) What must be in the baseline assessment plan? (1) An operator must include each of the following elements in its written baseline assessment plan: (i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies. (A) Internal inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges and grooves; … TAPC’s IMP did not properly address the methods TAPC selected to complete the baseline assessment of the integrity of its line pipe. Moreover, while the IMP provided for assessment tools capable of detecting corrosion, it did not provide for inspection tools capable of detecting deformation anomalies including dents, gouges and grooves. In 2008, TAPC ran an Enduro caliper in-line inspection (ILI) tool capable of detecting deformation anomalies; yet, TAPC’s IMP did not address the use of this tool or any other ILI tool capable of detecting such anomalies. The IMP merely addressed ILI tools capable of detecting corrosion as follows: − Section 3.01 Introduction - addressed “corrosion activity, metal loss, crack formations and third party damage” but it did not address deformation anomalies. − Section 3.02 In-Line Inspection Procedures - covered ILI tools and the threats the tools addressed. This section stated, “Generally, the goal and objective of the inspection should be to analyze and match significant factors known about the pipeline and expected anomalies with the capabilities and performances of the tool. Choice of the tool will depend on the specifics of the pipeline section and the goal set for the inspection.” This generic statement did not address either corrosion or deformation anomalies. − Section 3.03 ILI Tool Selection - limited the selection of the primary ILI tool to a High-Resolution Magnetic Flux Leakage (Hi-Res MFL) tool capable of detecting corrosion. It further restricted tool selection by stating, “Other secondary tools recommended by the provider will be considered for evaluation methods.” That is, 2#

220126018M_notice of amendment_10022012_text.pdf, page 3other tools that could possibly detect deformation anomalies would be considered but not necessarily selected for use, as required by the regulation. − Section 3.10 Data Analysis - stated, “The PM/PE shall select tools based on their ability to reliably detect corrosion activity both internal and external.” As previously noted, nothing in this section addressed the required selection of ILI tools capable of detecting deformation anomalies such as dents, gouges and grooves. Subsequent to the PHMSA inspection, TAPC made minor wording changes to its IMP to require that an MFL tool be able to detect third party damage, but TAPC’s IMP continued to restrict ILI tool selection to MFL tools with other tools being considered only if recommended by the vendor. This wording change was inadequate. 3. §195.452 Pipeline integrity management in high consequence areas. …. (c) What must be in the baseline assessment plan? (1) An operator must include each of the following elements in its written baseline assessment plan: (i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies. … (B) Pressure test conducted in accordance with subpart E of this part; … TAPC’s IMP did not properly address all the assessment methods it selected to complete the baseline assessment of the integrity of its line pipe. That is, TAPC used pressure testing as an assessment method on its pipeline in March 2010, but its IMP only addressed ILI tools. − Section 2.07 Baseline Assessment Method - stated, • “TPC is using the pressure test performed in December of 2004 as a prior assessment. TPC elects not to use this pressure test as its baseline assessment, because it does not give any indication of future integrity of the pipeline. • “The integrity assessment method to be employed by TPC in the development and continued assessment of pipeline integrity is Inline Inspection (ILI).” − Section 3.0 Assessment Procedure - stated, “The TPC pipeline will rely on In-Line Inspection (ILI) Assessment technique.” Subsequent to the inspection, TAPC made minor wording changes to its IMP to explain that pressure testing could be used as an assessment method. In making the change, however, TAPC did not develop procedures in the IMP for pressure testing nor did it change the Section 3.0 Assessment Procedure to address the use of pressure testing as an assessment method beyond the wording change in the lead paragraph. This wording change was inadequate. 3#

220126018M_notice of amendment_10022012_text.pdf, page 44. §195.452 Pipeline integrity management in high consequence areas. .... (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: (1) A process for identifying which pipeline segments could affect a high consequence area; (2) A baseline assessment plan meeting the requirements of paragraph (c) of this section; (3) An analysis that integrates all available information about the integrity of the entire pipeline and the consequences of a failure (see paragraph (g) of this section); (4) Criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis (see paragraph (h) of this section); (5) A continual process of assessment and evaluation to maintain a pipeline's integrity (see paragraph (j) of this section); (6) Identification of preventive and mitigative measures to protect the high consequence area (see paragraph (i) of this section); (7) Methods to measure the program's effectiveness (see paragraph (k) of this section); (8) A process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information (see paragraph (h)(2) of this section). Many portions of TAPC’s IMP contained written procedures, references, and requirements appropriate for Direct Assessment (DA) and External Control Direct Assessment (ECDA), but the IMP does not include DA or ECDA as assessment methods nor has TAPC used DA or ECDA as assessment methods. In fact, TAPC’s IMP specifically required the use of ILI for pipeline integrity assessments. Specific examples where TAPC’s IMP discussed DA and ECDA include, but are not limited to, − Section 1.01 Glossary − Section 2.10 Direct Assessment Plan − Section 2.11 Remediating Conditions Found During Direct Assessment − Section 4.0 Direct Examination − Section 5.0 Post Assessment 5. §195.452 Pipeline integrity management in high consequence areas. …. (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high 4#

220126018M_notice of amendment_10022012_text.pdf, page 5consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: …. (3) An analysis that integrates all available information about the integrity of the entire pipeline and the consequences of a failure (see paragraph (g) of this section); TAPC’s IMP did not include a process for performing an analysis that integrates all the available information about the integrity of its entire pipeline and the consequences of a failure anywhere along its pipeline system. TAPC’s IMP did not contain a process for a risk analysis of its pipeline facilities. Section 2.05 Risk Analysis stated, “Risk assessments will be conducted for the transmission pipeline and related facilities.” But, an adequate process for performing the risk assessment of the pipeline facilities was not included in the IMP. 6. §195.452 Pipeline integrity management in high consequence areas. …. (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: …. (8) A process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information (see paragraph (h)(2) of this section). TAPC’s IMP did not include a detailed process for the review of ILI and other integrity assessment results. For ILI assessments, TAPC’s IMP − did not address or include the consideration of tool tolerances in the evaluation of ILI data or procedures for determining that an ILI run was acceptable. − did not adequately address procedures for integrating the results of different types of ILI tools used to assess the pipeline. • Sections 3.03 ILI Tool Selection, 3.10 Data Analysis, and 4.14 Prioritization of Indications addressed integrating ILI information in general terms but did not include detailed procedures to address how TAPC would actually integrate the data. • Section 4.14 was written to address prioritization for ECDA, an assessment method, but TAPC does not allow the use ECDA as an assessment method. − did not adequately address procedures for comparing the ILI information with the results of the evaluations of anomalies on the pipeline or the acceptability standards for the comparison. − did not adequately address procedures for the re-evaluation of the ILI information when the results comparing the ILI information to the evaluations of the anomalies on the pipeline did not meet the acceptability standards. 5#

220126018M_notice of amendment_10022012_text.pdf, page 6• Sections 4.24 In Process Evaluation, 4.25 Reclassification And Reprioritization of Indications, 4.26 Reprioritization Criteria, and 4.28 Reprioritization Requirements addressed reprioritization but the procedures were written for ECDA, which is not an assessment method in TAPC’s IMP. • The procedures addressed the evaluation of corrosion activity, established reprioritization criteria for corrosion activity in Table 3.3.8.1 Reprioritization Criteria, and addressed indications based on indirect inspection - ECDA. But the procedures did not address the evaluation of anomalies other than corrosion, despite the fact that TAPC’s ILI assessment tool identified other anomalies such as deformations and dents. Also, TAPC’s IMP addressed the evaluation of the actual pipe in Section 4.0 Direct Examination, but this section was written for ECDA. Moreover, Section 4.01 Objectives stated that the section was to prioritize pipeline sections which do not have IM repair conditions. Lastly, the direct examination process in Section 4.0 is the process TAPC used to confirm IM repair conditions identified during its integrity assessments and information analysis, but the procedure was not written for the assessment methods TAPC used or for the integrity issues that have been identified on TAPC’s pipeline. 7. §195.452 Pipeline integrity management in high consequence areas. …. (h) What actions must an operator take to address integrity issues? (1) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline’s integrity. An operator must be able to demonstrate that the remediation of the condition will ensure the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An operator must comply with § 195.422 when making a repair. (i) Temporary pressure reduction. An operator must notify PHMSA, in accordance with paragraph (m) of this section, if the operator cannot meet the schedule for evaluation and remediation required under paragraph (h)(3) of this section and cannot provide safety through a temporary reduction in operating pressure. (ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA in accordance with paragraph (m) of this section and explain the reasons for the delay. An operator must also take further remedial action to ensure the safety of the pipeline. While TAPC’s IMP addressed taking action for anomalous conditions discovered during the ILI processes, the IMP did not provide clear, consistent, sufficient, and correct guidance for taking prompt action to address all anomalous conditions discovered through the integrity assessment or through information analysis. For example, − Section 2.11 - incorrectly limited the “prompt action” to those “anomalies and defects discovered during the In-Line Inspection process.” 6#

220126018M_notice of amendment_10022012_text.pdf, page 7− Section 5.05 - incorrectly stated, “ … any condition that is likely to pose a threat will be evaluated and any anomalous conditions resulting from integrity assessment will be scheduled for repair within 180 days of its discovery.” The regulations are much more prescriptive as to when anomalies must be repaired - they do not simply default to180 days. − Section 5.05 - stated “A schedule that prioritizes evaluation and remediation of anomalous conditions in accordance with table 3.2.6. Anomalous conditions will be classified as IMMEDIATE (Severe), ONE YEAR (Moderate) or MONITORED (Minor) conditions, or Other conditions as specified in ASME/ANSI B31.4, Section 7.” But • TAPC’s IMP did not contain a table 3.2.6, • The anomalous conditions noted are not per §195.452(h)(4); and, • The ASME/ANSI B31.4 reference to Section 7 is not valid. 8. §195.452 Pipeline integrity management in high consequence areas. …. (h) What actions must an operator take to address integrity issues? …. (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. TAPC’s IMP did not properly address the discovery of a condition in that it did not adequately define when the discovery of a condition occurs, or the requirement to promptly obtain sufficient information about a condition to make the determination that it presents (or does not present) a potential threat to the integrity of the pipeline. − TAPC’s IMP incorrectly established discovery of a condition in its Section 1.01 definition where it stated that discovery occurs at the end of the direct examination phase, and in Section 4.15 where discovery is determined to be when proposed excavations for direct examination are determined. − The dates established by TAPC’s IMP are not when TAPC has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline as required by the regulation. Depending on circumstances, an operator may have adequate information when the operator receives a preliminary internal inspection report, gathers and integrates information from other inspections, or when an operator receives a final internal inspection report. − TAPC’s IMP did not adequately address obtaining sufficient information about a condition promptly, but no later than 180 days, after an integrity assessment. Neither TAPC’s IMP definition of “Discovery of a Condition” in Section 1.01, Section 2.11, its requirement for the Program Manager to meet time requirements in Section 3.09 Qualifications, or its “Repair and Mitigation” requirements in Section 5.05 Exception Process established the requirement to promptly obtain sufficient information about a condition. 7#

220126018M_notice of amendment_10022012_text.pdf, page 89. §195.452 Pipeline integrity management in high consequence areas. …. (h) What actions must an operator take to address integrity issues? …. (3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety or environmental protection. TAPC’s IMP did not establish detailed and adequate procedures requiring conditions to be evaluated and remediated within the required timelines subsequent to discovery or to ensure the scheduling of the evaluation and remediation of the conditions was within the required time frames specified in §195.452(h)(4). TAPC’s IMP was not clear where it addressed conditions on a timeline. Various sections the IMP defined repair conditions, stated they will be prioritized to a timeline, covered scheduling as it referred to the condition by name (i.e. Immediate, 60 day, 180 day), covered repairing within 180 days of “discovery,” and had requirements for a pressure reduction for an “immediate” condition. However, the IMP incorrectly defined “discovery” and it did not tie the start of the clock to “discovery” for “60 day” conditions. 10. §195.452 Pipeline integrity management in high consequence areas. …. (h) What actions must an operator take to address integrity issues? …. (4) Special requirements for scheduling remediation. …. (iv) Other conditions. In addition to the conditions listed in paragraphs (h)(4)(i) - (iii) of this section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could impair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. Appendix C contains guidance concerning other conditions that an operator should evaluate. TAPC’s IMP did not identify “other conditions” that could impair the integrity of the pipeline or address how TAPC would evaluate and remediate the conditions. 11. §195.452 Pipeline integrity management in high consequence areas. …. (i) What preventive and mitigative measures must an operator take to protect the high consequence area? (1) General requirements. An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. These measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protection. Such actions may include, but are not limited to, implementing damage prevention best practices, better monitoring of cathodic protection where corrosion is a concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment, modifying the systems that monitor pressure and detect leaks, providing additional training to personnel on response procedures, conducting drills with local emergency responders and adopting other management controls. 8#

220126018M_notice of amendment_10022012_text.pdf, page 9TAPC’s IMP did not include a systematic decision making process with prioritization and follow-through for evaluating and implementing preventative and mitigative measures (PMM). Moreover, TAPC’s IMP did not have fully-developed written procedures for evaluating, prioritizing, and implementing PMM. While Section 2.13 Preventative and Mitigative Measures addressed PMM evaluation in general terms and covered the PMM that TAPC would use, it did not establish a detailed process nor did it include the one PMM process TAPC did use. 12. §195.452 Pipeline integrity management in high consequence areas. …. (i) What preventive and mitigative measures must an operator take to protect the high consequence area? …. (3) Leak detection. An operator must have a means to detect leaks on its pipeline system. An operator must evaluate the capability of its leak detection means and modify, as necessary, to protect the high consequence area. An operator's evaluation must, at least, consider, the following factors--length and size of the pipeline, type of product carried, the pipeline's proximity to the high consequence area, the swiftness of leak detection, location of nearest response personnel, leak history, and risk assessment results. TAPC’s IMP did not include a process to evaluate the capability of its leak detection means or to modify its leak detection to protect high consequence areas. 13. §195.452 Pipeline integrity management in high consequence areas. …. (i) What preventive and mitigative measures must an operator take to protect the high consequence area? …. (4) Emergency Flow Restricting Devices (EFRD). If an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, consider the following factors- -the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain between the pipeline segment and the high consequence area, and benefits expected by reducing the spill size. TAPC’s IMP did not include a process to determine if an emergency flow restricting device (EFRD) is needed on a pipeline segment to protect a high consequence area in the event of a release, and to install an EFRD if a need for one is determined. 14. §195.452 Pipeline integrity management in high consequence areas. …. (j) What is a continual process of evaluation and assessment to maintain a pipeline's integrity? …. (3) Assessment intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the line pipe’s integrity. An operator must base the assessment intervals on the risk the line pipe poses to the high consequence area to determine the priority for assessing the pipeline segments. An operator must establish the assessment intervals based on the factors specified in 9#

220126018M_notice of amendment_10022012_text.pdf, page 10paragraph (e) of this section, the analysis of the results from the last integrity assessment, and the information analysis required by paragraph (g) of this section. − TAPC’s IMP established conflicting requirements for the maximum interval for continually assessing the line pipe’s integrity. Section 2.12 established the maximum reassessment interval as a minimum of 5 years while Section 5.03 required the reassessment interval be no longer than 5 years. − TAPC’s IMP did not establish the interval for assessing the line pipe’s integrity based on the factors in §195.452(e), the information analysis required by §19.452(g), and the analysis of the results of the last integrity assessment. − TAPC’s IMP only considered the corrosion rate for corrosion defects found during direct examinations when determining the reassessment interval. Section 2.12 Reassessment and Evaluation stated, “After completing the baseline integrity assessment, the TPC will continue to assess the pipeline as frequently as needed to assure its integrity. The reassessment will be performed by February 17, 2009. A maximum reassessment interval will be established at a minimum of 5 years. Section 3.0 identifies the continual integrity assessment plan and procedures to be followed by TPC.” But TAPC’s IMP did not address determination of the reassessment interval in Section 3.0. − TAPC’s IMP addressed the determination of the reassessment interval in Section 5.0 Post Assessment but this section was written for corrosion anomalies and ECDA. Moreover, only the corrosion rate established during direct examination of the pipe was considered. It should also be noted that while the procedure covered establishing reassessment intervals based on external corrosion, the section was primarily written for an assessment method that TAPC did not use; and, it did not address integrity issues that had been identified on TAPC’s pipeline. 15. §195.452 Pipeline integrity management in high consequence areas. …. (j) What is a continual process of evaluation and assessment to maintain a pipeline's integrity? …. (5) Assessment methods. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies. (i) Internal inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges and grooves; TAPC’s IMP did not properly address the methods TAPC selected to complete the continual process of assessing the integrity of its line pipe. Also, while the IMP provided for assessment tools capable of detecting corrosion, it did not provide for inspection tools capable of detecting deformation anomalies including dents, gouges and grooves.1 1 This finding is for the process of continual assessments and is similar to the finding in Item 1 for the baseline assessment. For brevity, the write-up for this item was shortened. However, the operator must amend its IMP to address proper methods and tool selection for both the baseline assessment and for the continual assessments. 10#

220126018M_notice of amendment_10022012_text.pdf, page 1116. §195.452 Pipeline integrity management in high consequence areas. …. (j) What is a continual process of evaluation and assessment to maintain a pipeline's integrity? …. (5) Assessment methods. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies. ….. (ii) Pressure test conducted in accordance with subpart E of this part; TAPC’s IMP did not include all the assessment methods that TAPC has used to assess its pipeline. TAPC used pressure testing to assess its pipeline in March 2010, but TAPC’s IMP did not include the use of pressure testing as an assessment method for its pipeline. TAPC’s IMP states in: − Section 2.07 Baseline Assessment Method -“The integrity assessment method to be employed by TPC in the development and continued assessment of pipeline integrity is Inline Inspection (ILI).” − Section 3.0 Assessment Procedure - “The TPC pipeline will rely on In-Line Inspection (ILI) Assessment technique.” Subsequent to the inspection TAPC made minor wording changes to its IMP to cover pressure testing as an assessment method. In making the change, however, TAPC did not develop procedures in the IMP for pressure testing. That is, TAPC’s IMP Section 3.0 Assessment Procedure has not been modified to address using pressure testing as an assessment method beyond the minor wording change in the lead paragraph. This wording change was inadequate. 17. §195.452 Pipeline integrity management in high consequence areas. …. (k) What methods to measure program effectiveness must be used? An operator's program must include methods to measure whether the program is effective in assessing and evaluating the integrity of each pipeline segment and in protecting the high consequence areas. see Appendix C of this part for guidance on methods that can be used to evaluate a program's effectiveness. TAPC’s IMP did not establish a procedure for TAPC to use to measure the program effectiveness of its IMP beyond a framework. TAPC’s IMP in Section 2.14 Performance Plan states the overall requirements for its performance plan evaluation, but it does not establish a detailed procedure which can be used to perform the evaluation. Response to this Notice This Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.237. 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. 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 11#

220126018M_notice of amendment_10022012_text.pdf, page 12confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment 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 Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. If, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in this Notice, you may be ordered to amend your plans or procedures to correct the inadequacies (49 C.F.R. § 190.237). If you are not contesting this Notice, we propose that you submit your amended procedures to my office within 60 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 amended procedures, this enforcement action will be closed. It is requested (not mandated) that Tampa Airport Pipeline Corporation maintain documentation of the safety improvement costs associated with fulfilling this Notice of Amendment (preparation/ revision of plans, procedures) and submit the total to Wayne T. Lemoi, Director, Southern Region, Pipeline and Hazardous Materials Safety Administration. In correspondence concerning this matter, please refer to CPF 2-2012-6018M and, for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Wayne T. Lemoi Director, Office of Pipeline Safety PHMSA Southern Region Enclosure: Response Options for Pipeline Operators in Compliance Proceedings 12#

220126018M_Closure letter_10032013_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED October 3, 2013 Mr. Robert L. Rose President Tampa Airport Pipeline Corporation P.O. Box 35236 Sarasota, FL 34242 CPF 2-2012-6018M Dear Mr. Rose: On November 8-10, 2011, and March 22, 2012, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Southern Region, Office of Pipeline Safety inspected the Tampa Airport Pipeline Corporation (TAPC) Pipeline Integrity Management Plan (IMP) in Tampa, Florida, pursuant to Chapter 601 of 49 United States Code. As a result of the inspection, the Southern Region issued a Notice of Amendment (NOA) to TAPC on October 2, 2012. The Southern Region granted one 53-day extension on December 18, 2012, for TAPC to provide revised procedures. Subsequent to that grant of extension, we received and reviewed three responses to the NOA dated January 23, 2013, April 12, 2013, and August 9, 2013. In each case we identified additional deficiencies. We received and reviewed your latest response to the NOA dated September 23, 2013. This letter is to inform you that TAPC has complied with the terms of the NOA and that no further action is necessary with regards to the NOA. This case is now closed. Please be advised that this letter refers only to the NOA (CPF 2-2012-6018M) and not to any other PHMSA pending cases. Sincerely, Wayne T. Lemoi Director, Office of Pipeline Safety PHMSA Southern Region#