MAGELLAN PIPELINE COMPANY, LP — Notice of Probable Violation

party submissionOfficial PDF420125010_Operator_Response_and_Request_for_Hearing_04272012.pdf#

420125010_NOPV PCP PCO_03232012_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED March 23, 2012 Mr. Larry Davied Vice President, Technical Services Magellan Pipeline Company One Williams Center Tulsa, OK 74172 CPF 4-2012-5010 Dear Mr. Davied: Between March 22, 2010 and April 22, 2011, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code were on site and inspected your operations and maintenance procedures and ten pipeline inspection units in Oklahoma and Texas. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violation(s) are: 1. 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? (a) You must electrically isolate each buried or submerged pipeline from other metallic structures, unless you electrically interconnect and cathodically protect the pipeline and the other structures as a single unit. (b) You must install one or more insulating devices where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. (c) You must inspect and electrically#

420125010_NOPV PCP PCO_03232012_text.pdf, page 2test each electrical isolation to assure the isolation is adequate. (d) If you install an insulating device in an area where a combustible atmosphere is reasonable to foresee, you must take precautions to prevent arcing. (e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices. Magellan (the Operator) failed to isolate each buried pipeline from other metallic structures as required by §195.575 and confirmed in the written procedures required under §195.402. As discussed below, the Operator has both metallically and electrolytically shorted casings in the units inspected (including Longhorn, Duncan to Ft. Smith, Cimarron Pipeline, Orion West, Oklahoma City, and Tulsa) and has not consistently taken measures to achieve electrical isolation between the casings and carrier pipes. Metallically shorted casings are addressed by Magellan Corrosion Control Program procedures, 7.04-ADM-001, Section 2.9.4, which states that metallically shorted casings require actions when the casing potential is within 100 millivolts of the carrier pipe. Magellan’s annual surveys of pipe-to-soil and casing-to-soil readings show some casing-to-soil readings taken at the same test station or a nearby test station to be within 100 mV of the pipe-to-soil readings. According to Magellan records, testing performed by the Operator has confirmed that some of these casings are metallically shorted but actions have not been taken to achieve the electrical isolation required to comply with the requirements of 195.575. In addition, the Operator has not followed its procedures to clear the short or fill the casing annulus with dielectric material for each metallically shorted casing. A sample of the Magellan annual cathodic protection survey records, included as evidence, show the inspection date, the name of the pipeline segment, the milepost, a description of the location, the pipe-to-soil and casing-to-soil readings in volts and the casing status. Some examples in the Magellan records with casing-to-soil reading within 100 mV of the pipe-to-soil reading, indicating the potential for the casing to be metallically shorted, include the following: Segment Name MP/Station Year(s) Comments Ponca City to Barnsdall 22+24 2005, 2006, 2007, 2008, 2009 (2009) P/S -2.175V, C/S -2.181V Enid to Oklahoma City 74+06 2005, 2006, 2007, 2008, 2009 (2009) P/S -1.612V, C/S -1.602V Allen to Drumright 16+27 20072, 20082, 20091 (2009) P/S -0.926V, C/S -0.844V Tulsa Jct. to Kansas St. Line 119.223 20053,20064,20074,20084,20094 (2009) P/S -1.620V, C/S -1.617V Barnsdall to Kansas City #3-8 1+06 20052, 20072, 20084, 20092 (2008) P/S -1.205V, C/S -1.109V West Tulsa to Glenpool 4.38 20054,20064,20074,20084,20091 (2009) P/S -0.901V, C/S -0.900V West Tulsa to Glenpool 4.58 20054,20064,20074,20084,20091 (2009) P/S -0.943V, C/S -0.930V Clyde to DeLeon 156.302 2010 P/S -1.127V, C/S -1.124V 1 Casing-to-soil within 100 mV of pipe-to-soil but shown in Magellan records to be clear. 2 >100 mV difference and shown in Magellan records as electrolytically shorted. 3 Casing-to-soil within 100 mV of pipe-to-soil and shown in Magellan records to be metallically shorted. 4 Casing-to-soil within 100 mV of pipe-to-soil and shown in Magellan records to be electrolytically shorted. The Magellan records show casing status test designations using “C” for clear (not shorted), “E” for electrolytically shorted, “S” for metallically shorted, and “I” for inhibited (the annulus of the casing has been filled with a dielectric material). These designations have sometimes changed2#

420125010_NOPV PCP PCO_03232012_text.pdf, page 3from year to year between metallically shorted, electrolytically shorted, and clear. For example, the shorted casing at station 22+24 on the Ponca City to Barnsdall segment was designated to be metallically shorted (S) as early as 2005, was changed to electrolytically shorted (E) in 2006, then back to metallically shorted (S) in 2007, 2008, and 2009. The operator does not explain these inconsistencies. Research on corrosion of cased pipes supports the need to achieve electrical isolation between the carrier pipe and casing and a discussion is provided in the associated Violation Report. Magellan does not have a procedure specifically addressing the issue of electrolytically shorted casings, but the records indicate that the Operator has recognized the issue given the many casings in their records designated to be electrolytically shorted. The records, however, do not indicate the operator has taken consistent actions to address these electrolytic shorts and achieve electrical isolation as required by 195.575. Out of the many shorted casings (electrolytically) on the Magellan system where the casing-to-soil readings are not within 100 mV of the pipe-to-soil readings some specific examples are as follows: Segment Name MP/Station Year(s) Comments Ponca City to Barnsdall 0+04,44+22,52+08 20051,20061,2007,2008,2009 (00+04,2009) P/S -1.395V,C/S -1.102V Enid to Oklahoma City 69+14,80+26 20062,20072,2008,2009 (69+14,2009) P/S -1.271V,C/S -1.062V Allen to Drumright 68+25,69+16,75+15 2007,2008,2009 (68+25,2009) P/S-1.692V, C/S -1.466V Tulsa Jct. to Kansas St. Line 110.878,151.557 20053,2006,2007,2008,20091 (110.87,2009) P/S-1.519V,C/S -0.992V Barnsdall to Kansas City (#3-8) 29+44 2006,2007,2008,2009 (2009) P/S -1.791V, C/S -0.953V Cushing to Drumright 8+15 2006,2007,2008,2009,2010 (2010) P/S -1.457V, C/S -1.177V Drumright to Tulsa 0+24, 28+40, 32+29 20055,20061,20074,20084,2009 (2009,0+24) P/S -1.349V, C/S -0.896V Concord to East Houston 170.6 2006,2007,2008,2009,2010 (2010) P/S -1.171V, C/S -1171V Clyde to DeLeon 187.200 2010 P/S -1.201V, C/S -0.972V 1 Casing(s) designated as clear even though casing-to-soil reading is significantly more electronegative than native steel in soil. 2 Casing at 80+26 designated as clear. 3 Casing at 110.878 designated as metallically shorted. 4 Casing at 32+29 designated as clear. 5 Casings at 0+24 designated as clear even though casing-to-soil reading is significantly more electronegative than native steel in soil. None of the casings were intentionally bonded to the carrier pipe or connected to the cathodic protection system to cathodically protect the casings. Therefore, it was not the intent of the Operator to protect the pipe and casing as a unit. In addition, no records were presented documenting the installation of galvanic anodes to cathodically protect the casings which could result in elevated casing-to-soil readings. 2. 195.410 Line Markers. (1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known. (c) Each operator shall provide line marking at locations where the line is above ground in areas that are accessible to the public. The Operator did not meet the requirements of §195.410 by placing a sufficient number of markers along the buried pipeline so that its location is accurately known. Magellan also did not follow its “Pipeline Marking Procedure, 7.05-ADM-002, pages 1-5 of 5” dated January 1, 2010 3#

420125010_NOPV PCP PCO_03232012_text.pdf, page 4regarding its criteria to “Effectively delineate the pipeline corridor.” This procedure also states that “Markers must be placed and maintained over each buried pipeline at the following locations: 3.3.4 in sufficient numbers along the remainder of each buried line so that its location is accurately known.” During the field inspection there were locations on the Magellan pipeline system where there were an inadequate number of pipeline markers in order to accurately know the location of the pipeline, even when turning 360 degrees. At each of the sites listed below and by walking in various directions from each of the specific known pipeline locations identified by the operator, it was impossible to ascertain with any certainty the ongoing pipeline path through the further observation of pipeline markers that would accurately show the location of the pipeline. Locations where there were inadequate pipeline markers include segments in the Barnsdall, Tulsa, Oklahoma City, Odessa to El Paso, and Cimarron inspection units. Some examples are included in the following table: Date Unit Pipeline Segment Approximate Location Comments 08/10/2010 Tulsa Tulsa to State Line Oologah, OK near Road E0390 Pipeline near house, apt. bldg. 09/24/2010 Oklahoma City Allen to Drumright County Road 3261 near 81+05 Pipeline near corral, residence 09/28/2010 Oklahoma City Wynnewood to OKC County road crossing near MP 11 Pipeline near residence 09/21/2010 Oklahoma City Tulsa to Drumright 56th Street near 26+48 08/10/2010 Tulsa Tulsa to State Line ROW near MP 138 Near Oologah Lake block valve 08/10/2010 Tulsa Tulsa to State Line ROW near MP 148 08/10/2010 Tulsa Tulsa to State Line ROW near MP 144 Near old Alluwe Station site 05/11/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near 94+07 Near east end of Sander Road 05/11/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near 128+96 Near county road crossing 05/11/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near 142+31 Near Massey Point gate valve 05/11/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near 199+32 Near Havener gate valve 05/11/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near MP 201 Near Spiro rectifier 05/14/2010 Duncan-Ft. Smith Duncan to Ft. Smith ROW near 213+21 Near RR x-ing 06/09/2010 Orion West Frost to Odessa ROW near MP 310 Near Frost Station 06/09/2010 Orion West Frost to Odessa ROW near MP 202 Near Highway 8 crossing 06/09/2010 Orion West Frost to Odessa ROW near MP 174 06/09/2010 Orion West Frost to Odessa ROW near MP 163 Near county road 483 06/09/2010 Orion West Frost to Odessa ROW near MP 162 Near state highway 283 06/09/2010 Orion West Frost to Odessa ROW near MP 73 Near Colorado River crossing 06/10/2010 Orion West Frost to Odessa ROW near MP 72 Near Colorado River crossing 07/27/2010 Odessa-El Paso Odessa to El Paso ROW near MP 44 07/27/2010 Odessa-El Paso Odessa to El Paso ROW near MP 46 Damaged marker 07/27/2010 Odessa-El Paso Odessa to El Paso ROW near MP 61 Damaged marker 07/27/2010 Odessa-El Paso Odessa to El Paso ROW near rectifier E-8 Near 355+00 07/29/2010 Odessa-El Paso Odessa to El Paso ROW near rectifier E-40 Near 11208+95 08/10/2010 Tulsa Tulsa to State Line ROW near MP 168 Near Highway 10 crossing 08/10/2010 Tulsa Tulsa to State Line ROW near MP 158 Near county road crossing 08/10/2010 Tulsa Tulsa to State Line ROW near MP 147 08/10/2010 Tulsa Tulsa to State Line ROW near MP 139 08/10/2010 Tulsa Tulsa to State Line ROW near MP 130 08/10/2010 Tulsa Tulsa to State Line ROW near MP 118 Pipeline near residence 08/10/2010 Tulsa Tulsa to State Line ROW near 49th Street North 08/10/2010 Tulsa Tulsa to State Line ROW near MP 105 Near Million Dollar Casino 08/10/2010 Tulsa Glenpool to W. Tulsa ROW near MP 10 08/11/2010 Tulsa Glenpool to W. Tulsa ROW near MP 2 Old Koch tie-in 09/21/2010 Tulsa Tulsa to Drumright 56th Street area 09/21/2010 Tulsa Tulsa to Drumright MP 19 area 09/23/2010 Oklahoma City OKC to Wynnewood MP 34 area 09/23/2010 Oklahoma City OKC to Wynnewood Wynnewood tank farm area 09/23/2010 Oklahoma City Allen to Drumright ROW near 1+42 09/24/2010 Oklahoma City Allen to Drumright MP 74 area 4#

420125010_NOPV PCP PCO_03232012_text.pdf, page 509/24/2010 Oklahoma City Allen to Drumright MP 40 area County road 108 09/24/2010 Oklahoma City Allen to Drumright MP 29 area 10/05/2010 Cimarron Crude Glenpool to Tulsa MP 3 area 10/05/2010 Cimarron Crude Glenpool to Tulsa South I-44 and railroad tracks 3. 195.567 Which pipelines must have test leads and what must I do to install and maintain the leads? (b) Installation. You must install test leads as follows: (1) Locate the leads at intervals frequent enough to obtain electrical measurements indicating the adequacy of cathodic protection. (c) Maintenance. You must maintain the test lead wires in a condition that enables you to obtain electrical measurements to determine whether cathodic protection complies with §195.571. Magellan failed to maintain its test lead wires in a condition that enabled Magellan to obtain electrical measurements to determine whether cathodic protection complies with §195.571. During the field inspection, Magellan was observed to have cathodic protection test stations listed in their records as annual test points that were damaged but had not yet been repaired so that electrical measurements to determine the adequacy of cathodic protection could be made. For example: • The test station on the Wynnewood to Allen segment of the Duncan to Ft. Smith 12-inch and 10-inch pipeline located on Racetrack Road north of County Road 357 was destroyed and had not been repaired at the time of the inspection. • The test station at 7705+00 on the Black river to Hueco segment of the Odessa to El Paso pipeline had been destroyed and not repaired at the time of the inspection. • The test station on the Cimarron pipeline near County Road 4804 read -707mV at the time of the inspection and the analysis performed by the corrosion technician indicated that the test leads may not have been solidly connected to the pipe. These actions also show that the Operator failed to follow its procedure for installing and maintaining test leads as required in their procedure titled “Corrosion Control Program, 7.04- ADM-001, pages 1-21 of 21, dated January 1, 2010, section 2.10 Test Leads 195.567, 192.460, and 192.471.” 4. 195.406 Maximum operating pressure. (a) Except for surge pressures and other variations from normal operations, no operator may operate a pipeline at a pressure that exceeds any of the following: (1) The internal design pressure of the pipe determined in accordance with §195.106. However, for steel pipe in pipelines being converted under §195.5, if one or more factors of the design formula (§195.106) are unknown, one of the following pressures 5#

420125010_NOPV PCP PCO_03232012_text.pdf, page 6is to be used as design pressure: (i) Eighty percent of the first test pressure that produces yield under section N5.0 of Appendix N of ASME B31.8, reduced by the appropriate factors in §§195.106(a) and (e); or (ii) If the pipe is 323.8 mm (12¾ in) or less outside diameter and is not tested to yield under this paragraph, 1379 kPa (200 psig). (2) The design pressure of any other component of the pipeline. (3) Eighty percent of the test pressure for any part of the pipeline which has been pressure tested under Subpart E of this part. (4) Eighty percent of the factory test pressure or of the prototype test pressure for any individually installed component which is excepted from testing under §195.305. (5) For pipelines under §§195.302(b)(1) and (b)(2)(i), that have not been pressure tested under Subpart E of this part, 80 percent of the test pressure or highest operating pressure to which the pipeline was subjected for 4 or more continuous hours that can be demonstrated by recording charts or logs made at the time the test or operations were conducted. (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. Magellan has allowed pipeline pressures to exceed the maximum operating pressure in violation of the requirements in §195.406. Specifically, according to records submitted by the Operator in response to the PHMSA March 3, 2011, Request for Specific Information, Magellan has allowed their pipeline system to exceed the Maximum Operating Pressure (MOP) for ten (10) minutes, or longer, seventeen (17) times since 2007. Magellan states that it is standard practice per their System Integrity Plan procedure 13.01-ADM-008, Abnormal Operating Conditions List, to alarm as an abnormal operating condition when exceeding MOP on a ten minute basis. However, allowing the pressure to remain over the MOP for ten minutes is not consistent with a reasonable definition of surge pressure. Another issue involving an overpressure situation occurred when the Magellan control center received an alarm indicating that the MOP +110% had been exceeded at the Ponca City facility. The Operator determined that a pressure relief valve had been incorrectly set at 1,440 psig for a pipeline with a MOP of 480 psig. A Magellan technician also found during an inspection at the Sooner Road facility that the numbered tags identifying the pressure relief devices did not match the numbers on the Pipeline and Instrumentation Drawing (P&ID). In addition to showing the configuration of the piping, valves, and relief devices, the P&ID ties the MOP of the pipeline segment to the relief valve so that the correct settings can be established. Incorrect tagging may result in incorrect setpoints for the pressure relief devices. Magellan records also show that at the Drumright facility the overpressure devices were set to activate at pressures higher than the designated pressure on the inspection form (07-FORM- 0741). For example, the inspection form indicates that device MLMF-0033 on the East Pig Bypass should be set to activate at a pressure of 1,050 psig. However, on September 24, 2009, the pressure was set at 1,448 psig. Another example is device UNT2-0012 was set to activate at 6#

420125010_NOPV PCP PCO_03232012_text.pdf, page 7809 psig but the maximum pressure indicated on the form is 800 psig. The inspection form for the Oklahoma City Reno facility shows that device PSV-1221 was found to be set to relieve at 500 psig but the maximum pressure is 305 psig. Improperly setting the relief device pressures may allow an overpressure condition and could result in a failure of the pipeline facilities. 5. 195.402(a) Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Magellan failed to follow its Inspection of Right-of-way Procedure, 7.05-ADM-006, which requires the Operator to identify activity along the right-of-way that could, if not corrected, pose a hazard or compromise the safety, integrity or operation of pipelines and right-of-way. Specifically, several encroachments were observed during the field inspection with large quantities of junk on the right-of-way (abandoned trucks and cars, and oil storage tanks) in West Tulsa and near Drumright, OK. While barn construction predates the Magellan acquisition of the pipeline, there are other indications of encroachment and overgrowth indicating Magellan is not following its Inspection of Right-of-way Procedure for identifying conditions on the pipeline right-of-way that could pose a hazard or compromise safety. Specific locations where problems were found related to encroachment activities found on or adjacent to the pipeline ROW include: 1. Sandler Road, tank on the ROW 2. Race Track Road, encroachment of equipment on the ROW 3. County Road 145, barn on the ROW 4. Commercial business wareyard on the ROW 5. Cushing 8”, truck and storage facilities encroaching on the ROW 6. Cushing 8”, oil field debris on the ROW 7. Wynnewood 12”, metal debris on the ROW 8. Cushing to Glenpool, abandoned vehicles on the ROW 9. West Tulsa Area, miscellaneous materials in yard over ROW 10. Tulsa to Drumright 8”, facility encroachment on the ROW Major overgrowth which obscured the ROW was found at the following locations identified as follows: 1. 39th street 2. Caney River 3. 49th street 4. Glenpool to PSO 5. Glenpool to West Tulsa 7#

420125010_NOPV PCP PCO_03232012_text.pdf, page 86. South Ok City 7. Allen to Drumright 8”, MP68 6. 195.402(a) Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Magellan did not install pipeline markers where the pipe is to remain exposed as specified by its procedures, Corrosion Control Program, 7.04-ADM-001, 2.11.4. The Magellan procedures state that if the pipe is to remain exposed, proper pipeline markers shall be installed. During the field inspection exposures were observed without pipeline markers and without stated plans for reburial. The Operator was found to have unmarked exposures on the Glenpool to West Tulsa, Tulsa to Drumright, Drumright to Cushing, Cushing to Glenpool, Barnsdall to El Dorado, and Odessa to El Paso pipelines. 7. 195.571 What criteria must I use to determine the adequacy of cathodic protection? Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP 0169 (incorporated by reference, see §195.3). Magellan did not meet one of the applicable cathodic protection criteria required by §195.571 for portions of its pipeline system. With regard to §195.571, the Operator was unable to adequately show how IR drop is considered in the pipe-to-soil readings as required by the referenced standard (NACE RP 0169). Magellan also did not follow its Corrosion Control Program procedure, 7.04-ADM-001, Sections 2.3 and 2.4. During the field portion of the inspection, some pipe-to-soil readings were not meeting the criterion chosen by the Operator for determining the adequacy of the cathodic protection. Examples of inadequate readings were found on the Cimarron 8-inch pipeline at MP 53 (-683mV), MP 54 (-768mV), MP 61 (-696mV), MP 71 (- 707mv), the Odessa to El Paso pipeline at 9899+72 (-700mV), 9700+19 (-771mV), 9747+19 (- 500mV), 10123+95 (-500mV), 10264+00 (-654mV), the Cushing to Oklahoma City pipeline at MP 30.5 (-781mV), MP 0.7 (-817mV), the Glenpool to PSO pipeline at MP 16.7 (-822mV), the Tulsa to State Line pipeline at MP 110.5 (-500mV), MP 128.4 (-746mV). 8. 195.573 What must I do to monitor external corrosion control? 8#

420125010_NOPV PCP PCO_03232012_text.pdf, page 9(d) Breakout tanks. You must inspect each cathodic protection system used to control corrosion on the bottom of an aboveground breakout tank to ensure that operation and maintenance of the system are in accordance with API Recommended Practice 651. However, this inspection is not required if you note in the corrosion control procedures established under §195.402(c)(3) why compliance with all or certain operation and maintenance provisions of API Recommended Practice 651 is not necessary for the safety of the tank. Magellan did not meet one of the applicable cathodic protection criteria required by §195.573 for some breakout tanks. For the breakout tanks not meeting the cathodic protection requirements, the operator has not demonstrated why compliance with API 651 is unnecessary as required by §195.573. Magellan also did not follow its Corrosion Control Program procedure, 7.04-ADM- 001, Sections 2.3 and 2.4. During the field portion of the inspection, some tank-to-soil readings were not meeting the criterion chosen by the Operator for determining the adequacy of the cathodic protection. With regard to §195.573, structure-to-soil readings for breakout tanks 533, 535, and 868 in Oklahoma City were found to not meet the criterion chosen by the operator. 9. 195.573 What must I do to monitor atmospheric corrosion control? (c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by Sec. 195.581. Magellan failed to provide protection against atmospheric corrosion as required by §195.581. The operator also did not follow its Corrosion Control Program procedure, 7.04-ADM-001, Section 3.0. There were areas of oxidation observed on the chime area of some breakout tanks, above ground valves and piping, flange bolts, pipe/soil interfaces, and spans at various locations on the Magellan Pipeline System. Evidence includes photographs taken during the field inspection. These photographs indicate ongoing atmospheric corrosion at the following locations: 1. Allen Station Breakout Tank (BOT) 880 2. Barnsdale BOT 1214 3. Barnsdale BOT 416 4. Barnsdale BOT 729 5. Barnsdale BOT 730 6. Enid BOT 1231 7. Enid BOT 1232 8. Enid BOT 1238 9. Odessa BOT 574 10. Odessa piping 11. Odessa BOT 586 12. Odessa BOT 225 13. Odessa BOT 228 14. Odessa BOT 229 15. Line #1, 8” MP 21 16. P/S Interface on Old Tulsa line 9#

420125010_NOPV PCP PCO_03232012_text.pdf, page 1017. Orion West Unit 18. Orion West MP 312 19. Pipeline span near Black River Station 20. Glenpool to West Tulsa 21. MLV @ MP 21 22. Pipeline Span @ MP 46 10. 195.430 Firefighting equipment. Each operator shall maintain adequate firefighting equipment at each pump station and breakout tank area. The equipment must be- (a) In proper operating condition at all times; (b) Plainly marked so that its identity as firefighting equipment is clear; and, (c) Located so that it is easily accessible during a fire. Magellan does not maintain adequate firefighting equipment at each pump station and breakout tank area. The Operator has only fire extinguishers at most pump stations and breakout tank areas as required under its Portable Fire Extinguishers Administrative Procedure, 5.05-ADM- 076, which states that “equipment shall be adequate to extinguish fires that are in the early stages of development and in no case shall be expected to fight a fully engulfed fire.” The Operator relies on public firefighting agencies or firefighting cooperatives to respond to fires at their breakout facilities. However, liaison documentation is not adequate to show that Magellan has confirmed that these agencies have adequate training, equipment, and supplies to respond to fires at their pump stations and breakout tank areas. 11. 195.432 Inspection of in-service breakout tanks. (a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each in-service breakout tank. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). The Magellan breakout tank inspection program and methodology to establish in-service and out-of-service inspections does not meet the requirements for a risk-based inspection process defined by API 653, incorporated into Part 195 by reference. Specifically, the Magellan Tank Integrity Risk Based Inspection Procedure, 7.10-ADM-013, does not adequately incorporate some of the factors in the referenced version of API 653, including the materials of construction, the as-built standard, the accuracy and completeness of determining bottom plate thickness, the methods used to determine the product side and soil side corrosion rates and accuracy of the 10#

420125010_NOPV PCP PCO_03232012_text.pdf, page 11methods, the availability, accuracy and need for leak detection, the effectiveness of corrosion mitigation measures, and the quality of maintenance including previous repairs. Magellan personnel administering the risk-based program do not have formal training in risk-based inspection methodology and no records showing initial and subsequent assessments of the program by an authorized inspector and tank engineer were presented. Also, the Magellan routine breakout tank inspections failed to identify issues that should be addressed by the Operator’s breakout tank maintenance program such as plugged telltale holes, corrosion near the floor to shell weld, corrosion of the extension, soil or gravel covering the extension, corrosion around the perimeter of the reinforcing plates, cracked foundations supporting equipment and piping connected to the tanks, incomplete records of construction and repairs, and documentation that API 653 inspection recommended repairs were evaluated and completed or determined by the operator to not be needed. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1,000,000 for any related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $149,800 as follows: Item number PENALTY 2 $ 61,500 4 $ 55,400 5 $ 32,900 Warning Items With respect to item(s) 3, and 6 through 11 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 promptly correct these item(s). Be advised that failure to do so may result in Magellan Pipeline Company being subject to additional enforcement action. Proposed Compliance Order With respect to item(s) 1, 2, 4, and 5, pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Magellan Pipeline Company. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. 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 you11#

420125010_NOPV PCP PCO_03232012_text.pdf, page 12must 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). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2012-5010 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 12#

420125010_NOPV PCP PCO_03232012_text.pdf, page 13PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Magellan Pipeline Company a Compliance Order incorporating the following remedial requirements to ensure the compliance of Magellan Pipeline Company with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice pertaining to electrical isolation where Magellan failed to address metallically and electrolytically shorted casings, the Operator must perform tests to determine if each casing is metallically or electrolytically shorted. If a casing is determined to be metallically or electrolytically shorted, the Operator must evaluate any existing ILI data to determine if there are metal loss indications and make any required repairs to the carrier pipe. If no ILI data is available from studies made within the past five years, Magellan must perform studies using ILI or an alternative technology to determine for each casing if there is metal loss requiring repairs. The Operator must also clear the shorts, purge the casings of electrolyte, and replace the end seals as described in NACE SP0200. The Operator must also develop a procedure that specifically addresses the issue of electrolytically shorted casings. 2. In regard to Item Number 2 of the Notice pertaining to line markers where Magellan failed to adequately mark its pipeline, the Operator must install additional line markers in the Barnsdall, Tulsa, Oklahoma City, Odessa to El Paso, and Cimarron inspection units so that the location of the pipeline is accurately known as required by 195.410. 3. In regard to Item Number 4 of the Notice pertaining to maximum operating pressure where Magellan allowed the pipeline pressure to exceed the MOP for durations longer than indicated by a surge event, the Operator must review the design of its overpressure protection and make changes necessary to prevent recurrence. Magellan must also perform a review of the MOP’s for each pipeline segment, check the setpoints of each overpressure device, ensure each overpressure device is correctly tagged, and check each inspection form to ensure the tag numbers, maximum pressures, and setpoints are all correct. 4. In regard to Item Number 5 of the Notice pertaining to patrolling the rights-of-way where Magellan failed to identify activity along the right-of-way that could, if not corrected, pose a hazard or compromise the safety, integrity or operation of pipelines and right-of-way specified by its inspection of right-of-way procedure. The Operator also failed to remedy overgrowth that prevents the inspection of the surface condition on or adjacent to the pipeline right-of-way, also as specified by its right-of-way procedure. Magellan must make modifications to its patrolling practices to ensure that its procedures are followed. The Operator must also remedy existing encroachments that impair observation of the right-of-way and safety of the pipeline system. The operator must also perform maintenance on areas of the right-of-way that are obscured by vegetation. 5. Magellan must complete all items within 180 days following receipt of the Final Order. 13#

420125010_NOPV PCP PCO_03232012_text.pdf, page 146. It is requested (not mandated) that Magellan Pipeline Company maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 14#

420125010_Final Order_09022014_text.pdf, page 1Official PDFSEPTEMBER 2, 2014 Mr. Michael N. Mears President and Chief Executive Officer Magellan Midstream Partners, LP Magellan Pipeline Company, LP One Williams Center Tulsa, OK 74172 Re: CPF No. 4-2012-5010 Dear Mr. Mears: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a civil penalty of $149,800, and specifies corrective action that must be completed. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Final Order is made pursuant to 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. R.M. Seeley, Director, Southwest Region, OPS Ms. Bizunesh Scott, Steptoe & Johnson LLP 1330 Connecticut Ave. NW, Washington, D.C. 20036 CERTIFIED MAIL – RETURN RECEIPT REQUESTED#

420125010_Final Order_09022014_text.pdf, page 2U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ___________________________________ In the Matter of ) Magellan Pipeline Company, LP, ) CPF No. 4-2012-5010 ) ) ) Respondent. ) ___________________________________ ) FINAL ORDER Between March 22, 2010, and April 22, 2011, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an inspection of the pipeline facilities and records of Magellan Pipeline Company, LP (Magellan or Respondent) in Oklahoma and Texas. 1 As a result of the inspection, the Director, Southwest Region, OPS, issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order on March 23, 2012 (Notice). In accordance with 49 C.F.R. § 190.207, the Notice alleged Magellan committed four violations of the hazardous liquid pipeline safety regulations, proposed a civil penalty of $149,800, and proposed corrective action to be taken. The Notice also included seven warning items. Magellan responded by requesting a hearing on April 27, 2012, and then submitted a supplemental response dated August 17, 2012 (Supp. Response). In accordance with 49 C.F.R. § 190.211, a hearing was held on August 28, 2012, in Houston, Texas, before the Presiding Official from the Office of Chief Counsel, PHMSA. After the hearing, Magellan submitted a post-hearing brief dated October 29, 2012 (Brief). FINDINGS OF VIOLATION The Notice alleged that Respondent committed four violations of the pipeline safety standards in 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.575(a), which states: 1 Magellan is a subsidiary of Magellan Midstream Partners, LP, and operates approximately 10,000 miles of pipeline primarily transporting refined petroleum products in Kansas, Texas, Oklahoma, and other west-central states, as reported for the 2013 calendar year pursuant to § 195.49.#

420125010_Final Order_09022014_text.pdf, page 32 § 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? (a) You must electrically isolate each buried or submerged pipeline from other metallic structures, unless you electrically interconnect and cathodically protect the pipeline and the other structures as a single unit. The Notice alleged that Respondent violated § 195.575(a) by failing to electrically isolate buried pipelines from metallic casings. Specifically, the Notice alleged that Respondent failed to remedy “shorted casings” at various units over a number of years, including units at Longhorn, Duncan to Ft. Smith, Cimarron Pipeline, Orion West, Oklahoma City, and Tulsa. In addition, the Notice alleged that Respondent did not follow its written procedures to address metallically shorted casings, and did not have procedures to address electrolytically shorted casings. In its written submissions and at the hearing, Magellan responded that the alleged violation should be withdrawn because § 195.575(a) does not require operators to remedy or “clear” shorted casings. Respondent also argued that the evidence does not support the allegation that Magellan failed to follow its procedures, or that there is even a requirement to have procedures for clearing shorted casings. PHMSA first considers Respondent’s argument that § 195.575(a) does not require operators to electrically isolate their pipelines from metallic casings. If the standard does require electrical isolation from casings, as alleged in the Notice, then PHMSA must determine whether Respondent complied with that standard. A. Safety Standards In matters of regulatory application, PHMSA begins by examining the plain language of the rule. The text of a regulation is controlling, but the Agency may consider other administrative material to ensure consistent application of its rules. Administrative material may include prior enforcement cases, guidance documents, regulatory history, and other material, if relevant. (1) Regulatory language Section 195.575(a) requires operators with cathodic protection systems to electrically isolate each buried pipeline from other metallic structures, unless the operator interconnects and cathodically protects the pipeline and other structure as a single unit. Cathodic protection systems are used by pipeline operators to protect steel pipelines from external corrosion.2 A cathodic protection system with an impressed current prevents external corrosion by applying a direct electric current to the metal of the pipeline in an amount sufficient to prevent metal loss to the surrounding environment.3 Operators must maintain a minimum 2 § 195.563. 3 Kinder Morgan Energy Partners, L.P., CPF 4-2006-5023, Item 4, 2010 WL 6531634 (Aug. 31, 2010). Final orders can be viewed on PHMSA’s website at http://www.phmsa.dot.gov/pipeline/enforcement (follow link for enforcement since 2002 and then for final orders issued by year).#

420125010_Final Order_09022014_text.pdf, page 43 level of cathodic protection to protect their pipelines. 4 Any deficiency identified in the corrosion control must be corrected.5 Deficiencies in corrosion control may arise when cathodically protected pipelines are adjacent to other metallic structures. The deficiency results when current from the cathodic protection system gets diverted from the pipeline to the foreign structure. A pipeline casing is typically a larger diameter steel pipe that surrounds the pipeline transporting hazardous liquid. A casing can be used to protect a pipeline from stresses imposed on the pipe, such as when the line is buried beneath a highway or railroad. The inside of the casing is generally lined with spacing material so the pipeline does not touch the casing, and the ends of the casing are sealed to prevent water from entering. A steel casing that surrounds a pipeline with cathodic protection may become “shorted,” which means the casing is no longer electrically isolated from the pipeline and current is leaving the pipe for the casing.6 There are generally two types of shorted casings. A metallically shorted casing is caused by physical contact between the casing and the carrier pipe, which may be caused by movement of the pipe inside the casing or failure of spacing material. An electrolytically shorted casing is caused by ionic contact between the casing and carrier pipe via some electrolyte, such as water that has entered the casing. By definition, a steel casing is a metallic structure. Section 195.575(a) requires operators to ensure their buried pipelines are electrically isolated from “other metallic structures.” The regulation does not explicitly exclude casings or any other type of metallic structure from this requirement. Accordingly, PHMSA finds that a plain reading of the regulation requires operators to electrically isolate buried pipelines from other metallic structures, including metallic casings, unless the pipeline and casing are electrically interconnected and cathodically protected as a single unit. PHMSA also reviews the applicable administrative material, including material cited by Respondent, to ensure this plain reading is consistent with other applications of the rule. (2) Enforcement history In prior enforcement cases that involved shorted casings under § 195.575, PHMSA determined that shorted casings are not in compliance with the regulation. In July 2012, PHMSA issued a final order finding a violation of § 195.575 where cathodic protection tests demonstrated the operator had a metallic short.7 In that case, PHMSA found the shorted casing proved the operator had failed to electrically isolate its pipeline, among other violations of § 195.575. Likewise, in May 2005, PHMSA issued a final order finding a violation of § 195.575(a) based on evidence from cathodic protection tests demonstrating a shorted casing was present.8 Both the 4 § 195.571. 5 § 195.573(e). See also § 195.401(b) (requiring operators to correct any discovered condition that could adversely affect the safe operation of a pipeline system). 6 Alyeska Pipeline Serv. Co., CPF 5-2005-5023, Items 10(a) and 10(b), 2009 WL 7810542 (July 28, 2009) (“Electrically shorted casings may interfere with cathodic protection and result in inadequate protection.”). 7 Buckeye Partners, L.P., CPF 1-2011-5013, Item 2, 2012 WL 4025918 (Jul. 27, 2012). 8 Alyeska Pipeline Serv. Co., CPF 5-2003-5002, Item 5(b), 2005 WL 5010121 (May 19, 2005).#

420125010_Final Order_09022014_text.pdf, page 54 casing vent and settlement rod readings indicated a pipe-to-soil potential of -1.25 volts, suggesting the casing or casing test lead was in electrical contact with the carrier pipe. PHMSA determined the operator had violated § 195.575(a) by failing to electrically isolate the buried pipeline from other metallic structures. Magellan cited an enforcement case that it believed supported the contrary view that § 195.575 does not require operators to remedy shorted casings.9 In the case cited by Magellan, PHMSA issued a warning to an operator for failing to inspect shorted casing vents every six months as required by the company’s written procedures. In that case, PHMSA warned that a failure to follow written procedures was a probable violation of § 195.402(a). Magellan argued this demonstrates PHMSA has allowed an alternative to clearing shorted casings. PHMSA finds the case cited by Respondent has limited applicability because the case concerned compliance with a different regulation than is at issue in the present matter. The issue in that case was whether the operator followed its own written procedures as required by § 195.402(a). The case did not address compliance with § 195.575; nor did it find any conduct to be permissible or prohibited under § 195.575. In prior cases that explicitly addressed shorted casings under § 195.575, PHMSA determined that shorted casings do not comply with the regulation. Accordingly, having reviewed prior applications of § 195.575, PHMSA finds a plain reading of the regulation is consistent with the prior enforcement history. (3) Administrative guidance Magellan argued further that administrative “guidance developed at the time this regulation became effective and in effect during the inspections in this case” demonstrates that § 195.575 does not require operators to remedy shorted casings.10 Respondent contended that under that guidance, PHMSA considers pipelines to be protected if an electrolytic short is present. Respondent also contended that the guidance established various methods to comply with the regulation besides merely clearing the short. PHMSA has developed inspection and enforcement guidance for § 195.575 that discusses, among other things, the cathodic protection of pipelines inside metallic casings. 11 It is not clear if Respondent was referring to this guidance or some other document, because Respondent did not cite the guidance by name, publication date, or location where it could be accessed, and did not submit a copy as evidence. 12 9 Supp. Response at 14, citing Texas Eastern Products Pipeline Co., CPF 4-2009-5010, Item 2, 2010 WL 5761110 (Dec. 30, 2010). 10 Supp. Response at 10. 11 Part 195 Corrosion Enforcement Guidance. PHMSA staff manuals and instructions are available on its website at http://www.phmsa.dot.gov/foia/e-reading-room. 12 See, e.g., Supp. Response at 10.#

420125010_Final Order_09022014_text.pdf, page 65 The inspection and enforcement guidance issued by PHMSA for § 195.575 notes that casings are electrically isolated because otherwise they can drain current away from the carrier pipe. The guidance also states that once a shorted casing is identified, “the operator should determine a course of action to correct or negate the adverse effects . . . within six months.” It also states that shorts “should be removed since they could reduce the effectiveness of [cathodic protection] to not only the carrier pipe in the casing but to the line pipe on either side of the casing.”13 Although this guidance is informational and may not constitute the basis for a violation by itself, the guidance is consistent with the conclusion that § 195.575(a) requires operators to correct shorted casings or negate the adverse effects by cathodically protecting the pipeline and structure as a single unit. In fact, the guidance states that a violation of § 195.575(a) likely occurs if an operator fails to timely initiate corrective action upon discovery of a shorted casing.14 Having reviewed the relevant administrative guidance material, PHMSA finds it is consistent with the reading of § 195.575(a).15 (4) Regulatory history Magellan cited the regulatory history of § 195.575 in support of its position that shorted casings are not required to be remediated. Respondent argued that rulemaking documents show PHMSA intentionally omitted any “measures to remedy shorted casings.”16 In December 2000, PHMSA issued a notice of proposed rulemaking to revise the corrosion control standards for hazardous liquid pipelines. In the notice, PHMSA explained that the proposed standards were “identical to present corrosion control requirements in Part 195 [for hazardous liquid pipelines] and standards that are substantially like present requirements in Part 192 [for gas pipelines].”17 The version of § 195.575(a) proposed by PHMSA was based on a comparable provision in § 192.467(a), which requires gas pipeline operators to electrically isolate their pipelines from other metallic structures.18 Section 192.467(c) of the gas regulations, which PHMSA did not propose to include in § 195.575, requires that “each pipeline be electrically isolated from metallic casings.” PHMSA stated that it was not including a provision like § 192.467(c) in the proposal because the safety need to clear shorted casings was not apparent. Magellan argued “it 13 Corrosion Enforcement Guidance at 52. 14 Corrosion Enforcement Guidance at 53. 15 OPS also included as evidence another guidance document, Guidelines for Integrity Assessment of Cased Pipe for Gas Transmission Pipelines in HCAs. Violation Report, Exhibit 1-15, available at http://primis.phmsa.dot.gov/ gasimp/techreports.htm. This guidance concerns different requirements for gas pipelines, but does refer to shorted casings as “immediate” and “scheduled” priorities. 16 Supp. Response at 12, quoting Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 65 Fed. Reg. 76968, 76977 (proposed Dec. 8, 2000). Reference to “PHMSA” includes predecessor agencies. 17 Controlling Corrosion, 65 Fed. Reg. at 76975. 18 Controlling Corrosion, 65 Fed. Reg. at 76977.#

420125010_Final Order_09022014_text.pdf, page 76 is reasonable to infer that the absence of a similar provision in § 195.575 means that there is not a regulatory requirement to isolate casing[s] under § 195.575.”19 PHMSA has considered the preamble to the notice of proposed rulemaking and agrees the proposed rule did not indicate an intent to include a provision identical to § 192.467(c). The final rule, however, adopted regulatory language for hazardous liquid pipelines that covers all metallic structures without exception. The final rule did not differentiate between casings and any other type of metallic structure that must be electrically isolated from pipelines.20 In the event of any perceived inconsistency between the text of the final rule and a statement in the preamble of the proposed rule, the text of the final rule must control. Moreover, after adoption of the final rule, PHMSA has issued at least two enforcement cases that concluded § 195.575(a) requires operators to electrically isolate hazardous liquid pipelines from metallic casings. Therefore, PHMSA rejects Respondent’s argument that the regulatory history requires a different application of the regulation. (5) Other research materials Finally, the Notice alleged that “[r]esearch on corrosion of cased pipes supports the need to achieve electrical isolation between the carrier pipe and casing.”21 As support for this assertion, OPS produced two research documents prepared by third-parties. Magellan responded that it was not taking a position on the research, but noted that none of the reference materials suggested operators must take specific actions to address shorted casings. 22 The first report, Statistical Analysis of External Corrosion Anomaly Data of Cased Pipe Segments, studied the significance of corrosion damage on cased pipelines.23 One of the conclusions after evaluating thousands of casings was that “shorted casings are significantly more susceptible to corrosion than non-shorted casings.”24 Particularly with metallically shorted casings, the study noted that “a metallic short does increase the chances of external pipe corrosion and thus, shorted casings should be considered to receive prioritization for integrity assessment.”25 19 Supp. Response at 12. 20 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 FR 66994, 67000 (Dec. 27, 2001). 21 Notice at 3. 22 Supp. Response at 13-14. 23 Violation Report, Exhibit 1-14. The report was prepared for INGAA Foundation, Inc. by Southwest Research Institute (Dec. 2007). 24 Statistical Analysis at 33. 25 Statistical Analysis at 16.#

420125010_Final Order_09022014_text.pdf, page 87 The second document, Research Efforts for Addressing Cased Pipeline Integrity Management, echoed the findings of the Statistical Analysis study.26 It also referred to metallic shorts as “severe” and electrolytic shorts as “moderate” issues requiring action.27 While these reference materials do not control the application of § 195.575, they are informative about the risks to pipeline safety posed by shorted casings and the need to address them to prevent pipeline failures caused by corrosion. In conclusion, on the issue of whether shorted casings must be addressed under § 195.575(a), PHMSA finds the plain reading of the regulation requires operators to electrically isolate each buried pipeline from other metallic structures, including metallic casings, unless the pipeline and casing are electrically interconnected and cathodically protected as a single unit. The relevant enforcement history and administrative guidance material that have been issued since the final regulation was adopted are consistent with this reading. B. Analysis and Findings The Notice alleged that Respondent violated § 195.575(a) by failing to electrically isolate buried pipelines from metallic casings, and they were not electrically interconnected and cathodically protected as a single unit. It was not disputed at the hearing or in the written submissions that Respondent’s pipeline system had multiple metallically and electrolytically shorted casings over a number of years.28 By definition, shorted casings are not electrically isolated from the pipeline because the short involves current being diverted or shielded from the pipeline. Therefore, the pipelines in question were not electrically isolated. As to whether the pipelines and casings were electrically interconnected and cathodically protected as a single unit, the Notice alleged that none of the casings were intentionally bonded to a carrier pipe or connected to the cathodic protection system in a manner that cathodically protected the pipe and casing as a single unit. The Notice further alleged Respondent never intended to protect the pipes and casings together as a unit. In its written submissions and at the hearing, Respondent argued that an electrolytically shorted casing is essentially electrically interconnected and cathodically protected.29 Respondent explained that Magellan does not intentionally short casings, but an electrolytically shorted casing can be considered the same as being electrically interconnected.30 (Respondent did not 26 Violation Report, Exhibit 1-17. The document was prepared by Pipeline Research Council International, Inc. for a PHMSA workshop (Jul. 14, 2008). 27 Research Efforts at 7. 28 See Violation Report, Exhibits 1-4 through 1-13 (containing annual cathodic protection survey data for Respondent’s pipeline facilities primarily for years 2005 through 2009). 29 Supp. Response at 10. 30 Respondent did not contend that it intentionally bonded pipe and casings as a single unit.#

420125010_Final Order_09022014_text.pdf, page 98 contend that a metallically shorted casing was electrically interconnected and cathodically protected.) At the hearing, OPS argued that allowing a previously isolated casing to lapse into a shorted condition is not an electrical interconnection under the regulation. OPS explained that intentionally protecting the structures as a single unit would be accomplished using a wire for the electrical connection. OPS agreed with Respondent that if a short is caused by water entering the annulus of the casing, current will travel through the electrolyte. But if the electrolyte does not surround the entire pipe, some areas of the pipe may not get any protection. Also, OPS stated the presence of water constitutes a more corrosive environment, resulting in a higher risk of corrosion especially when there is reduced protection from the short. Having considered the information presented by both parties, PHMSA concludes that a shorted casing is not equivalent to a pipeline and casing being electrically interconnected and cathodically protected as a single unit under § 195.575(a). An electrolytically shorted casing caused by the presence of water in the annulus may result in limited areas of electrical connection, which is different than a system purposefully designed and controlled to ensure the pipe receives the intended level of protection over its entire surface. Therefore, PHMSA rejects Respondent’s argument that an electrolytically shorted casing complies with § 195.575(a). Respondent’s annual cathodic protection survey records demonstrate the shorted casings were not electrically isolated. The evidence also shows Respondent did not electrically interconnect and cathodically protect them as a single unit. Accordingly, PHMSA finds Respondent violated § 195.575(a) by failing to electrically isolate each buried pipeline from other metallic 31 structures. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.410, which states in part: § 195.410 Line markers. (a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following: (1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known. The Notice alleged that Respondent violated § 195.410 by failing to place line markers over each buried pipeline at public road crossings, railroad crossings, and in sufficient number along the remainder of the pipeline so that its location is accurately known. The Notice also alleged that Respondent did not follow its written procedures to effectively delineate the pipeline corridor. The Notice listed 45 locations, including road and railroad crossings and other areas where there were allegedly inadequate pipeline markers to ascertain the location of the pipeline. OPS alleged that at each of those locations, inspectors walked in various directions at the pipeline right-of- 31 The Notice also alleged that Respondent did not follow its procedures. It is not necessary to reach a conclusion on this issue because Respondent’s cathodic protection records prove a violation of § 195.575(a).#

420125010_Final Order_09022014_text.pdf, page 109 way but could not identify the path of the pipeline through observation of pipeline markers even when turning to look 360 degrees. OPS included photographs of the rights-of-way taken during the inspection. In its written submissions and at the hearing, Respondent argued that § 195.410 does not require pipeline markers to be placed in sufficient number so they can be viewed by looking 360 degrees. Respondent argued that such a “360-degree test” is not mandated by the regulation and is also indistinguishable from the “line of sight test” rejected by PHMSA in prior enforcement cases. Respondent also argued that evidence in this case was not presented to Magellan in a manner that allowed for meaningful rebuttal. A. Safety Standards Section 195.410 requires operators to have above-ground line markers in the area of their pipelines. The markers must include the words “Warning,” “Caution,” or “Danger” followed by “Petroleum (or the name of the hazardous liquid transported) Pipeline,” the name of the operator, and a telephone number where the operator can be reached at all times. With some exceptions, line markers must be placed and maintained at each public road crossing, at each railroad crossing, and “in sufficient number along the remainder of each buried line so that its location is accurately known.” This regulation contains both prescriptive and performance-based requirements. The prescriptive requirements tell operators exactly where certain line markers must be placed: at each public road crossing and at each railroad crossing. The performance-based requirement tells operators that markers must also be placed in “sufficient” number along the remainder of each buried line so that its location is “accurately known.”32 The regulation does not establish a minimum number of markers or maximum distance between markers along the pipeline. Rather than establish a uniform distance for markers, the rule provides flexibility for operators to mark their pipelines in a manner appropriate for their system as long as the location of the pipeline is “accurately known” from the markers. In previous enforcement cases involving § 195.410, PHMSA took a cautious approach to gauging compliance with the performance-based requirement. In 2008, PHMSA began reexamining the “line-of-sight” test used by some inspectors to check if markers were sufficient in number. The line-of-sight test had been used primarily at cultivated agricultural fields and valve sites. An inspector would stand at a valve site or at one end of a cultivated field and observe whether the operator’s next line marker could be seen when looking in both directions. Between 2008 and 2011, PHMSA withdrew a number of alleged violations of § 195.410 where line-of-sight was the basis for the alleged violation.33 32 See, e.g., Tennessee Gas Pipeline Co., CPF 4-2012-1020, Item 1, 2013 WL 8284480 (Dec. 26, 2013) (discussing performance-based regulations in the context of a requirement to have “sufficient” test stations to determine the adequacy of cathodic protection). 33 See, e.g., Citgo Pipeline Co., CPF 4-2007-5010, Item 3, 2011 WL 2040231 (Apr. 14, 2011); Kinder Morgan CO2 Co., CPF 4-2006-5003, Item 1, 2010 WL 6539184 (Oct. 12, 2010); Kinder Morgan Energy Partners, L.P., CPF 4- 2006-5023, Item 2, 2010 WL 6531634 (Aug. 31, 2010); BP Pipelines (North America), Inc., CPF 4-2007-5003, Item 1, 2010 WL 6518288 (Jul. 19, 2010); Enterprise Products Operating, LLC, CPF 4-2007-5015, Item 2, 2009 WL#

420125010_Final Order_09022014_text.pdf, page 1110 Magellan argued that PHMSA has explicitly rejected the line-of-sight test and therefore any “360-degree test” must also be rejected as they are indistinguishable.34 PHMSA disagrees that line-of-sight was explicitly rejected. PHMSA did withdraw a number of alleged violations that were based on line-of-sight, but PHMSA made clear the withdrawals were due to a reexamination of the test and that “no decision” had been made “whether or how [line- of-sight] should be applied.”35 PHMSA also clarified that the “withdrawal neither constitutes an interpretation of § 195.410(a)(1) nor prejudices future potential enforcement action.”36 During the same time period PHMSA continued to find violations of § 195.410 in other cases that did not explicitly implicate line-of-sight. 37 The manner in which line-of-sight was addressed in prior enforcement actions does not preclude enforcement of § 195.410 in this case, regardless of the manner in which OPS inspectors observed Magellan’s pipeline. Respondent also argued that § 195.410 does not require pipeline markers to be placed in sufficient number so that they can be viewed by looking 360 degrees and that a “360-degree test” is not mandated by the regulation. At the hearing, OPS contended that its inspectors did not employ a “360-degree test,” but rather used the terminology “even when turning 360 degrees” in the Notice to describe how the inspectors examined the right-of-way. In other words, the inspectors walked in different directions but did not see markers to decipher the location of the pipeline when looking in all directions. Having considered the positions of the parties, PHMSA concludes that the inspectors appropriately used normal senses of visual perception to observe whether markers were placed in the area of Respondent’s pipeline. Since § 195.410 requires markers to be placed “in sufficient number along the [pipeline] so that its location is accurately known,” inspectors must be able to use normal methods of observation to see if markers are present and to discern the location of the pipeline. In this case, inspectors were walking around and looking in all directions to see where pipeline markers were located. There is nothing inappropriate about this method of evaluating compliance with § 195.410. 5538652 (Dec. 2, 2009); and NuStar Logistics, L.P., CPF 4-2005-5048, Item 2, 2009 WL 1211363 (Mar. 11, 2009). PHMSA also held a public workshop on February 20-21, 2008, in Houston, Texas, to discuss, among other issues, placement of line markers. See also, Pipeline Safety: Workshop on Public Awareness Programs for Pipeline Operators and Location of Line Markers, 73 Fed. Reg 223 (Jan. 2, 2008). 34 Brief at 13. 35 E.g., Enterprise Products, CPF 4-2007-5015, Item 2. 36 E.g., Enterprise Products, CPF 4-2007-5015, Item 2. 37 See, e.g., Buckeye Partners, LP, CPF 1-2013-5003, Item 1, 2013 WL 4406977 (Jun. 10, 2013); ExxonMobil Pipeline Co., CPF 5-2011-500, Item 1, 2011 WL 7006608 (Nov. 2, 2011); Marathon Pipe Line LLC, CPF 5-2010- 5013, Item 2, 2011 WL 1303343 (Feb. 18, 2011); Sunoco Pipeline, L.P., CPF 4-2007-5040, Item 4, 2010 WL 5761108 (Dec. 16, 2010); Kinder Morgan Energy Partners, L.P., CPF 4-2006-5023, Item 2, 2010 WL 6531634 (Aug. 31, 2010); and Magellan Pipeline Co., CPF 4-2007-5050, Item 1, 2009 WL 5538658 (Dec. 28, 2009).#

420125010_Final Order_09022014_text.pdf, page 1211 B. Analysis and Findings PHMSA evaluates whether Respondent complied with § 195.410 by reviewing the evidence to determine if Respondent had line markers over each buried pipeline at public road and railroad crossings and in sufficient number along the remainder of each buried line so that its location is accurately known. As with any performance standard, it is inherent that operators evaluate their own conduct under the rule to determine whether they have satisfied the minimum standard.38 It is also inherent that operators be able to demonstrate their conduct complies with the minimum standard. At the hearing, Respondent argued that it could not demonstrate compliance without knowing what standard PHMSA uses to evaluate compliance. PHMSA notes that the text of the regulation provides the minimum standard: operators must ensure the location of their pipeline can be accurately known from the markers placed along the line. If the location of the pipeline cannot be accurately known from the markers, the operator is not likely to be in compliance with the minimum standard. Evidence in the record demonstrates there were locations on Respondent’s pipeline system that did not have enough markers to accurately know the location of the pipeline. Approximately 60 photographs from the OPS inspection show areas where there are no visible line markers to indicate the path of the pipeline. The inspector explained at the hearing that he actively tried to locate markers by walking around and looking for them, but the location of the pipeline could not be determined by observing markers in these areas. Respondent argued that the photographic evidence taken at the time of the inspection was not presented to Magellan in a manner that allowed for meaningful rebuttal. Specifically, Respondent contended the photographs were taken in 2010, but were not provided to Magellan until June 1, 2012, preventing the Company from challenging whether the alleged conditions actually existed in 2010. In addition, Respondent argued that OPS never articulated the camera settings used to take the photographs. At the hearing, the inspector explained that several Magellan personnel accompanied him on the inspection when the pictures were taken. They also participated in pre-inspection and post- inspection review meetings during which line marker issues were discussed. Testimony at the hearing confirmed that the photographs were taken with standard camera settings. Having reviewed the record, PHMSA finds no basis for Respondent’s contention that it was not able to provide meaningful rebuttal to the allegations. The Notice identified each of the 45 locations where adequate markers were allegedly not present. Respondent was free to present evidence at the hearing that those locations had sufficient markers to accurately know the location of the pipeline. 38 Tennessee Gas Pipeline Co., CPF 4-2012-1020, Item 1.#

420125010_Final Order_09022014_text.pdf, page 1312 Accordingly, PHMSA finds Respondent violated § 195.410 by failing to place line markers over each buried pipeline at public road crossings, railroad crossings, and in sufficient number along the remainder of the pipeline so that its location is accurately known. 39 Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(a) and (b), which states in part: § 195.406 Maximum operating pressure. (a) Except for surge pressures and other variations from normal operations, no operator may operate a pipeline at a pressure that exceeds any of the following: (1) The internal design pressure of the pipe determined in accordance with § 195.106 . . . . (2) The design pressure of any other component of the pipeline. (3) Eighty percent of the test pressure for any part of the pipeline which has been pressure tested under subpart E of this part. (4) Eighty percent of the factory test pressure . . . for any individually installed component which is excepted from testing under § 195.305. (5) For pipelines under §§ 195.302(b)(1) and (b)(2)(i) that have not been pressure tested under subpart E of this part, 80 percent of the test pressure or highest operating pressure to which the pipeline was subjected for 4 or more continuous hours . . . . (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. The Notice alleged that Respondent violated § 195.406(a) by operating pipelines at a pressure exceeding their maximum operating pressure (MOP). Specifically, the Notice alleged that company records from 2007 through 2011 show Magellan allowed its pipeline system to operate above MOP for durations in excess of ten minutes on at least 17 occasions. In addition, the Notice alleged that Respondent violated § 195.406(b) at the Ponca City facility where pressure exceeded 110% of MOP due to an incorrect setting on a pressure relief valve. With regard to the alleged violation of § 195.406(b), Respondent did not contest that pressure exceeded 110% of MOP on that occasion. Respondent explained the event was a result of thermal pressure increasing on a shutdown pipeline. Pressure reached 135% of MOP because the relief pressure was incorrectly set at a value much higher than it should have been. Respondent contested the alleged violation of § 195.406(a), and argued that exceeding MOP was permitted under the regulation as “variations from normal operations.” Respondent explained that it does not allow pressure above MOP for any amount of time; rather, it takes immediate 39 The Notice also alleged Respondent did not follow procedures to delineate the pipeline corridor. It is not necessary to reach a conclusion on this issue because the photographs and testimony prove a violation of § 195.410.#

420125010_Final Order_09022014_text.pdf, page 1413 action to reduce pressure. Respondent stated a pressure excursion above MOP triggers an alarm and requires the controller to take immediate action to reduce pressure, which may include shutting down units. If the corrective measures do not result in pressure being brought under MOP after ten minutes, an additional alarm is triggered and Respondent logs the event as an abnormal operating condition for further analysis to prevent reoccurrence. The second alarm does not change the controller’s actions that are already underway to reduce pressure. The ten minute interval, Respondent explained, is based on how long it typically takes pressure to settle after start up. With regard to the 17 specific events in question, Respondent contended that thirteen were attributed to thermal pressure increase in idle lines, two were related to the malfunction of a component that failed to control pressure as designed, one event was attributed to personnel error where a block valve was misaligned, and the final event occurred during startup. Respondent argued that none of the events were caused by intentionally exceeding MOP. At the hearing, OPS contended that the durations of the excursions were not the type of temporary pressure spikes permitted by the regulation for surges and other variations from normal operations. OPS also contended that the multiple events of pressure exceeding MOP for more than 10 minutes demonstrate Respondent’s system is not designed with adequate pressure control and relief to ensure pressure can be kept within MOP. A. Safety Standards The pipeline safety regulations at 49 C.F.R. § 195.406 establish the maximum safe operating pressure for pipelines. Pursuant to § 195.406(a), an operator is prohibited from operating any pipeline at a pressure that exceeds the established MOP of the line, with limited exceptions. The exceptions to the maximum operating limit in § 195.406(a) are for “surge pressures and other variations from normal operations.” A “surge pressure” is defined in § 195.2 as the pressure produced by a change in velocity of the moving stream that results from shutting down a pump station or pumping unit, closure of a valve, or any other blockage of the moving stream. Due to the low compressibility of hazardous liquid and near instantaneous adjustment in pressure for the transient condition, surges should be brief in duration depending on the length of the affected segment. For example, PHMSA has found that a pressure excursion lasting less than one minute that occurred during a shutdown was a surge pressure under § 195.406.40 “[O]ther variations from normal operations” is not separately defined in the regulation. The regulatory history of the rule and subsequent publications do not suggest any distinguishing characteristics between surge pressures and other variations from normal operations, as those terms are used in § 195.406.41 Whereas a surge may be caused by a shutdown or blockage of the 40 BP Pipelines (North America), Inc., CPF 3-2009-5002, Item 1, 2012 WL 1901291 (Apr. 3, 2012). 41 See, e.g., Transportation of Hazardous Materials by Pipeline, 33 Fed. Reg. 10213 (proposed Jul. 17, 1968); and Testing Requirements and Operating Pressure Limitations, 35 Fed. Reg. 17183 (Nov. 7, 1970). Both rulemaking documents primarily refer to surges, but occasionally refer to “surges or other pressure variations from normal operation” without distinguishing the terminology.#

420125010_Final Order_09022014_text.pdf, page 1514 moving stream, a variation from normal operation could have a different cause. Regardless of the cause of the variation, the excursion is not permitted to exceed MOP for an indefinite amount of time. In order to comply with the operating pressure restriction in § 195.406(a), an operator’s pipeline system must be capable of achieving timely pressure reduction in the event of a surge or other type of variation from normal operation. B. Analysis and Findings In the present case, Respondent’s system experienced multiple pressure excursions above MOP for periods longer than ten minutes. Respondent took action to reduce pressure at the first sign of exceeding MOP, but Respondent was not able to bring pressure back to within MOP in a timely manner. Pressure excursions lasting more than ten minutes on multiple occasions over the course of several years, even if unintentional, are not merely “variations from normal operations” permitted under the regulation. Such long-lasting and regular excursions suggest that relief equipment, operating procedures, or both were not adequate to ensure operations in accordance with § 195.406. Accordingly, PHMSA finds Respondent violated § 195.406(a) by operating its pipeline above MOP for durations exceeding 10 minutes on 17 occasions. PHMSA also finds Respondent violated § 195.406(b) by failing to prevent pressure from exceeding 110% of MOP. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies . . . . The Notice alleged that Respondent violated § 195.402(a) by failing to follow its written procedures that required Respondent to identify activity along the right-of-way that could pose a hazard or compromise the safety, integrity or operation of the pipeline and right-of-way. The Notice alleged there were encroachments in Respondent’s right-of-way, such as large quantities of junk, abandoned cars, and oil storage tanks. In its written submissions and at the hearing, Respondent did not contest the alleged violation, but did request modification of the proposed compliance order, which is discussed below. Having considered the evidence, PHMSA finds Respondent violated § 195.402(a) by failing to follow its written procedures for inspecting pipeline rights-of-way. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent.#

420125010_Final Order_09022014_text.pdf, page 1615 ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122 (2011), Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations.42 The Notice proposed a total civil penalty of $149,800 for the violations in Items 2, 4, and 5. The Notice did not proposed a civil penalty for Item 1. In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, PHMSA must consider the following criteria: the nature, circumstances and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; the good faith of Respondent in attempting to comply with the pipeline safety regulations; and the effect on Respondent’s ability to continue in business. In addition, PHMSA may consider the economic benefit gained from violation without any reduction because of subsequent damages, and such other matters as justice may require. Item 2: The Notice proposed a civil penalty of $61,500 for Respondent’s violation of 49 C.F.R. § 195.410. Respondent failed to place line markers in sufficient number over each buried pipeline so that its location is accurately known. With regard to the nature, circumstances, and gravity of the violation, PHMSA finds that pipeline integrity or safe operation was potentially compromised at road or railroad crossings and other areas where third party damage is a risk of releasing hazardous liquid affecting the public, property, and environment. Respondent was cognizant of the regulatory requirement and took some steps to address the issue by having line markings in some locations, but Respondent did not achieve compliance on every pipeline segment. PHMSA finds the proposed penalty is supported by the record and there is not sufficient reason to adjust the penalty for culpability, good faith, effect on ability to continue in business, or history of prior offenses. Accordingly, having reviewed the record and considered the assessment criteria, PHMSA assesses Respondent a civil penalty of $61,500 for the violation of § 195.410. Item 4: The Notice proposed a civil penalty of $55,400 for Respondent’s violation of § 195.406. Respondent violated § 195.406(a) by failing to reduce pressure excursions to within MOP for durations exceeding 10 minutes. In addition, Respondent violated § 195.406(b) by failing to prevent pressure from exceeding 110% of MOP. With regard to the nature, circumstances, and gravity of the violations, PHMSA finds pipeline integrity or safe operation was potentially compromised resulting in an elevated risk of an overpressure condition and pipeline release affecting the safety of the public, property, and environment. 42 Subsequent to the actions that gave rise to this case, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub. L. No. 112-90, § 2(a), 125 Stat. 1905 (Jan. 3, 2012), increased the maximum civil penalty for a pipeline safety violation to $200,000 per violation for each day up to a maximum of $2,000,000 for a related series.#

420125010_Final Order_09022014_text.pdf, page 1716 Respondent was cognizant of the regulatory requirement and took some steps to address the problem by discovering issues with its overpressure monitoring system, but Respondent did not achieve compliance by preventing reoccurrence. PHMSA finds the proposed penalty is supported by the record and there is not sufficient reason to adjust the penalty for culpability, good faith, effect on ability to continue in business, or history of prior offenses. Accordingly, having reviewed the record and considered the assessment criteria, PHMSA assesses Respondent a civil penalty of $55,400 for the violation of § 195.406. Item 5: The Notice proposed a civil penalty of $32,900 for Respondent’s violation of § 195.402(a). Magellan failed to follow its written procedures for identifying activity along the pipeline right-of-way that could pose a hazard or compromise the safety, integrity or operation of the pipeline or right-of-way. Respondent did not contest the proposed penalty for this violation. Accordingly, having reviewed the record and considered the assessment criteria, PHMSA assesses Respondent a civil penalty of $32,900 for violation of § 195.402(a). In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, PHMSA assesses Respondent a total civil penalty of $149,800. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125-4915. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $149,800 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to each of the violations cited above. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids by pipeline or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601.#

420125010_Final Order_09022014_text.pdf, page 1817 With regard to the violation of § 195.575 (Item 1), Respondent argued that it would be inappropriate to include the proposed requirement to clear shorted casings because that is not the only method to comply with § 195.575.43 PHMSA agrees that the terminology of the compliance order should be changed to recognize the regulation permits operators to address shorted casings either by electrical isolation or by electrically interconnecting and cathodically protecting the pipeline and casing a single unit. With regard to the violation of § 195.402(a) (Item 5), Respondent argued the proposed compliance order should be revised to reflect Magellan’s written maintenance program, which requires at a minimum, aerial surveillance once a year and an integrity assessment to identify areas that may require maintenance. 44 Respondent also argued that it should be allowed to use other methods of patrolling if a right-of-way cannot be inspected aerially due to obstructions.45 PHMSA concludes that Respondent must achieve compliance with § 195.402(a) by having and following written procedures that implement the right-of-way inspection and maintenance requirements.46 Respondent must ensure proper patrolling practices are followed and must remedy existing encroachments and vegetation that could adversely affect pipeline safety, or that could impair observation of the right-of-way during inspection. PHMSA does not find the compliance order warrants modification to the degree suggested by Respondent. Notwithstanding, PHMSA agrees the compliance order should recognize that Respondent may use methods of inspection like walking or driving if a right-of-way is not capable of being aerially inspected. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 195.575 (Item 1), Respondent must perform tests to determine if casings are metallically or electrolytically shorted. If as a result of those tests, a casing is determined to be metallically or electrolytically shorted, Respondent must evaluate inline inspection (ILI) data of that location for indications of corrosion or metal loss and make any required repairs to the carrier pipe. If ILI data from the past five years is not available for that location, Respondent must perform studies using ILI or an alternative technology to determine if there is corrosion or metal loss requiring repairs. Respondent must also address the shorted casings either by electrically isolating the buried or submerged pipeline from other metallic structures, or by electrically interconnecting and cathodically protecting the pipeline and structure as a single unit. Respondent must submit a plan to perform the actions 43 Brief at 11. 44 Supp. Response at 2. 45 Brief at 3. 46 See §§ 195.401 and 195.412.#

420125010_Final Order_09022014_text.pdf, page 1918 2. 3. 4. 5. 6. required in this paragraph within 30 day of receipt along with its written procedures for addressing both metallically and electrolytically shorted casings. With respect to the violation of § 195.410 (Item 2), Respondent must install additional line markers at the identified locations in the Barnsdall, Tulsa, Oklahoma City, Odessa to El Paso, and Cimarron inspection units so that the location of the pipeline is accurately known. With respect to the violation of § 195.406 (Item 4), Respondent must review the design of its overpressure protection systems and make changes necessary to prevent instances of exceeding MOP for longer than a surge event. Respondent must also perform a review of the establish MOP for each pipeline segment, check the set points of each overpressure device, ensure each overpressure device is correctly tagged, and check each inspection form to ensure the tag numbers, maximum pressures, and set points are all correct. With respect to the violation of § 195.402(a) (Item 5), Respondent must make appropriate changes to its written operations and maintenance procedures for inspecting rights-of-way to ensure such procedures are followed. Respondent must also remedy any encroachments and vegetation that could adversely affect pipeline safety or that could impair observation of the right-of-way during inspection. The procedures must include provisions for each method of inspection used, including walking or driving if Respondent uses those methods to inspect rights-of-way that are not capable of being aerially inspected. Submit documentation demonstrating compliance with this Compliance Order within 180 days of receipt of this Order. Documentation must be submitted to the Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration, 8701 South Gessner, Suite 1110, Houston, TX 77074. It is requested that Respondent maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. It is requested that these costs be reported in two categories: (1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and (2) total cost associated with replacements, additions and other changes to pipeline infrastructure. The Director, Southwest Region, OPS may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent and demonstrating good cause for an extension. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000 for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States.#

420125010_Final Order_09022014_text.pdf, page 2019 WARNING ITEMS With respect to Items 3, 6, 7, 8, 9, 10 and 11, the Notice alleged probable violations of Part 195, but considered them to be warning items. A warning item issued pursuant to 49 C.F.R. § 190.205 constitutes an allegation that OPS has identified a potential issue, which if found in a future inspection, may subject the operator to an enforcement action. Unlike other alleged violations, PHMSA does not make a finding as to whether an allegation contained in a warning was proven by evidence in the record. An operator may respond to a warning. In this case, Respondent responded to Items 3, 8, 9 and 10. The warnings in the Notice were for: 49 C.F.R. § 195.567 (Item 3) – Respondent’s alleged failure to maintain test lead wires in a condition to enable obtaining electrical measurements and to determine whether cathodic protection complies with applicable criteria. In its response, Respondent did not dispute that test leads were damaged or destroyed, but contended that no violation was proven because Respondent had a reasonable amount of time to correct the conditions under § 195.401.47 49 C.F.R. § 195.402(a) (Item 6) – Respondent’s alleged failure to follow its written procedures for marking exposed pipe. 49 C.F.R. § 195.571 (Item 7) – Respondent’s alleged failure to ensure that cathodic protection on pipelines met applicable criteria. 49 C.F.R. § 195.573(d) (Item 8) – Respondent’s alleged failure to ensure that cathodic protection on the bottom of breakout tanks met applicable criteria. In its response, Respondent did not dispute that cathodic protection failed to meet applicable criteria, but contended that no violation was proven because evidence in the record did not relate to Respondent’s inspection intervals.48 49 C.F.R. § 195.583(c)49 (Item 9) – Respondent’s alleged failure to provide protection against atmospheric corrosion at certain locations. Respondent did not dispute that atmospheric corrosion was observed at 22 locations on its pipeline facility, but contended that no violation was proven because evidence did not relate to Respondent’s inspection intervals or show that the corrosion would affect safe operations.50 49 C.F.R. § 195.430 (Item 10) – Respondent’s alleged failure to maintain adequate firefighting equipment at each pump station and breakout tank area. Respondent did not 47 Supp. Response at 19-22. 48 Supp. Response at 22-23. 49 The Notice erroneously cited this regulation as § 195.573(c). 50 Supp. Response at 23-25.#

420125010_Final Order_09022014_text.pdf, page 2120 dispute that it only had fire extinguishers at most pump stations and breakout tank areas, and that it relied on public firefighting agencies and cooperatives. Respondent contended, however, there is no obligation under the regulation for operators to confirm whether local firefighting organizations have adequate firefighting equipment.51 49 C.F.R. § 195.432(b) (Item 11) – Respondent’s alleged failure to have an inspection program and methodology that meets the requirements for inspecting the physical integrity of in-service breakout tanks according to API Standard 653 (incorporated by reference, see § 195.3). Respondent is warned that if a probable violation of these provisions is identified in the future, Respondent may be subject to additional enforcement. Under 49 C.F.R. § 190.243, Respondent may submit a petition for reconsideration of this Final Order to the Associate Administrator for Pipeline Safety, PHMSA, 1200 New Jersey Avenue SE, East Building, 2nd Floor, Washington, D.C. 20590, no later than 20 days after receipt of the Final Order by Respondent. Any petition submitted must contain a statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of any civil penalty assessed. All other terms of the order, including the corrective action, remain in effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ________________________________ __________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety 51 Supp. Response at 16-19.#

420125010_Closure Letter_03042016_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED March 4, 2016 Mr. Michael Pearson Senior Vice President, Technical Services Magellan Pipeline Company, L.P. P.O. Box 22186 Tulsa, OK 74172 CPF 4-2012-5010 Dear Mr. Pearson: On various dates in 2010 and 2011, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code conducted inspections of the Magellan Pipeline, L.P., (Magellan, the Operator) Duncan to Ft. Smith, Tulsa, Barnsdall, Oklahoma City, Cimarron & Osage, Orion East, Orion West, Odessa to El Paso, Longhorn East, and Longhorn West pipeline units, the Tulsa, OK control center and O&M procedures. As a result of the inspections, on March 23, 2012 a Notice of Probable Violation with Proposed Civil Penalties and Proposed Compliance Order was issued to Magellan Pipeline, L.P. (Magellan, the Operator) CPF 4-2012-5010. Magellan responded by letter on April 27, 2012, by requesting a hearing. Magellan also submitted a supplemental response on August 17, 2012 prior to the hearing. The hearing was held on August 28, 2012 at the PHMSA Southwest Region offices. Magellan submitted a Post-Hearing Brief dated October 29, 2012. On September 2, 2014, PHMSA issued a Final Order that included a civil penalty of $149,800 and a Compliance Order. Magellan responded to the Final Order with submissions on October 8, 2014 and March 6, 2015. PHMSA also performed field verifications of the Final Order in March 2015. This letter is to inform you no further action is necessary and this case is now closed. Thank you for your cooperation. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#