ENBRIDGE PIPELINES (OZARK) L.L.C. — Notice of Probable Violation

party submissionOfficial PDF420135004_Operator Petition For Reconsideration_11062015.pdf#

party submissionOfficial PDF420135004_Operator Response to Notice_04262013.pdf#

420135004_NOPV PCP PCO_03042013_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED March 4, 2013 Mr. Richard Adams Vice President, U. S. Operations Enbridge Pipelines, LLC City Center Office 1409 Hammond Ave. Superior, WI 54880-5247 CPF 4-2013-5004 Dear Mr. Adams: In November 2011, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your Enbridge Pipeline, LLC Cushing Terminal (Enbridge) in Cushing, OK. 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. §195.432 Inspection of in-service breakout tanks. (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).#

420135004_NOPV PCP PCO_03042013_text.pdf, page 2API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd edition, December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)). 6.3.2.1 All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection. (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. Enbridge did not properly determine the shell corrosion rates necessary to establish the external inspection intervals as required by API Standard 653, 6.3.2.1, incorporated by reference into Part 195. Paragraph 6.3.2.1 of API Standard 653 requires the external inspection interval to be determined by subtracting the minimum required shell thickness from the measured shell thickness and dividing the result by four times the actual shell corrosion rate. The shell corrosion rate is calculated by dividing the measured metal loss by the time over which it occurred. The metal loss is determined by subtracting a more recent shell thickness measurement from a shell thickness measurement made earlier in time at the same location on the breakout tank. The change in shell thickness is then divided by the time interval between measurements to determine a corrosion rate. Some of the Enbridge calculations of metal loss were negative, indicating the shell plate had increased in thickness over time. This occurred because the methodology used by Enbridge to measure the shell plate thickness was flawed. Consequently, tanks #1014, #2228, and #3011 had improperly calculated inspection intervals. 2. §195.432 Inspection of in-service breakout tanks. (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). (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. 2#

420135004_NOPV PCP PCO_03042013_text.pdf, page 3API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd edition, December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)). 6.9.3.2 It is the responsibility of the owner/operator to review the inspection findings and recommendations, establish a repair scope, if needed, and determine the appropriate timing for repairs, monitoring, and/or maintenance activities. Typical timing considerations and examples of repairs are: a. Prior to returning the tank to service— repairs critical to the integrity of the tank (e.g., bottom or shell repairs). b. After the tank is returned to service—minor repairs and maintenance activity (e.g., drainage improvement, painting, gauge repairs, grouting, etc.). c. At the next scheduled internal inspection—predicted or anticipated repairs and maintenance (e.g., coating renewal, planned bottom repairs, etc.). d. Monitor condition for continued deterioration—(e.g., roof and/or shell plate corrosion, settlement, etc.). The owner/operator shall ensure that the disposition of all recommended repairs and monitoring is documented in writing and that reasons are given if recommended actions are delayed or deemed unnecessary. 4.5.2 Foundation Repair or Replacement 4.5.2.1 If there is a need for foundation repair or replacement, foundations shall be restored to the tolerance limits of 10.5.6. 4.5.2.2 Concrete pads, ringwalls, and piers, showing evidence of spalling, structural cracks, or general deterioration, shall be repaired to prevent water from entering the concrete structure and corroding the reinforcing steel. C.1.1.1 Concrete Ring d. Check that runoff rainwater from the shell drains away from tank. C.1.1.5 Site Drainage a. Check site for drainage away from the tank and associated piping and manifolds. Enbridge did not complete some breakout tank repairs identified by the API 653 standard and the required inspections as necessary to maintain a tank condition suitable for safe operation or in the alternative provide engineering justification for not making the repairs. The issues include failing to make repairs to cracked or deteriorated ringwalls and failing to modify the grade so that water drains away from the tanks. Inadequate repairs were found on tanks #1014, #1015, #1016, #1153, and #1154. 3. §195.432 Inspection of in-service breakout tanks. (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). 3#

420135004_NOPV PCP PCO_03042013_text.pdf, page 4(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd edition, December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)). 6.3.1.2 The interval of such inspections shall be consistent with conditions at the particular site, but shall not exceed one month. Enbridge did not perform the monthly inspections of its breakout tanks as required by 49 CFR 195 and API Standard 653, incorporated by reference. According to the Enbridge Work Order List Report for monthly breakout tank inspections, breakout tank 1181 was inspected on January 4, 2011 but not inspected again until March 1, 2011, a span of 56 days with no February inspection. Breakout tank 1182 was inspected on January 29, 2011 but not inspected again until March 7, 2011, a span of 37 days with no February inspection. The January Work Order List indicates that breakout tank 3364 was not inspected until February 1 but inspected again on February 28 with no January inspection. There are several additional Cushing Terminal breakout tanks where the inspections are not being performed according to the API Standard 653 requirement. Enbridge must modify its inspection schedule to meet the requirement of performing API Standard 653 routine in-service inspections. 4. §195.565 How do I install cathodic protection on breakout tanks? After October 2, 2000, when you install cathodic protection under Sec. 195.563(a) to protect the bottom of an aboveground breakout tank of more than 500 barrels (79.5m3) capacity built to API Specification 12F, API Standard 620, or API Standard 650 (or its predecessor Standard 12C), you must install the system in accordance with API Recommended Practice 651. However, installation of the system need not comply with API Recommended Practice 651 on any tank for which you note in the corrosion control procedures established under Sec. 195.402(c)(3) why compliance with all or certain provisions of API Recommended Practice 651 is not necessary for the safety of the tank. §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 SP 0169 (incorporated by reference, see § 195.3). 4#

420135004_NOPV PCP PCO_03042013_text.pdf, page 5Enbridge did not meet at least one of the applicable criteria for cathodic protection on some Cushing Terminal breakout tanks as required by API RP 651 and NACE SP 0169. The Operator uses the 100 mV polarization criterion on a portion of the breakout tanks and the -850 mV with consideration of IR drop criterion on others. The inspection found several breakout tanks where Enbridge was not meeting the specified criteria or had not taken the appropriate measurements to determine if the specified criterion was being met. For example, Enbridge states that the 100mV criterion is being used tank #1153 but only energized (on) readings were taken during the 2011 annual survey. To determine if the 100 mV criterion is being met, the operator must compare the polarized measurement, eliminating IR drop, (instant off) to the depolarized measurement. However, no instant off readings were taken in 2011 to determine if the 100mV of polarization was achieved. Without instant off readings, the only check that can be made is against the -850mV with consideration of IR drop criterion (energized reading). Several of the energized readings taken using the profile tube did not meet the -850mV criterion even before considering IR drop (20 feet, -625mV, 25 feet, -607mV, 30 feet, -684mV, 40 feet, -702mV). As another example, the records for tank #1295 do not show any depolarization measurements so one of the -850mV criteria must be applied. Some of the structure-to-soil measurements did not meet either of the -850mV criteria listed in NACE SP0169 or API RP651 for 2009, 2010, or 2011. Enbridge records indicate that a new groundbed was installed in 2010 but some of the 2011 structure-to-soil readings were still not meeting one of the -850 mV criteria. Tank #2211, which was cited in a previous enforcement action (CPF 4-2010-5008) for exceeding the API 653 internal inspection interval, was diagnosed with a depleted groundbed as early as 2007. The tank was scheduled to be taken out of service in 2012 but Enbridge continued to operate the tank with deficient cathodic protection in 2009, 2010, and 2011. Other examples of tanks not meeting one of the cathodic protection criteria include #1182, #2218, #1320, #2212, #2215, and #2223. 5. §195.581Which pipelines must I protect against atmospheric corrosion and what coating material may I use? You must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. (b) Coating material must be suitable for the prevention of atmospheric corrosion. (c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for which you demonstrate by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will- (1) Only be a light surface oxide; or (2) Not affect the safe operation of the pipeline before the next scheduled inspection. 5#

420135004_NOPV PCP PCO_03042013_text.pdf, page 6§195.583 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. Enbridge has not consistently applied coating material (paint) to all of its breakout tanks in the Cushing Terminal suitable for the prevention of atmospheric corrosion as required by 195.581(a). Enbridge has several tanks at their Cushing, OK terminal that have not been completely painted and have an atmospheric corrosion scale on the unpainted exterior surface. Enbridge argues that the corrosion scale is a form of protective coating and that the tanks do not need to be painted to protect them from atmospheric corrosion. However, according to the Operator, the bottom four feet on these tanks has been painted “to protect the floor-to-shell (“chime”) weld and appurtenance area.” The acknowledgment that a portion of the tank had to be painted for protection from atmospheric corrosion indicates that corrosion damage is occurring and constitutes a contradiction to the Operator’s argument that the corrosion scale is adequate protection from atmospheric corrosion. 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 $78,700 as follows: Item number PENALTY 1 $33,700 4 $45,000 Warning Items With respect to item(s) 2, 3, and 5 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 Enbridge Pipeline being subject to additional enforcement action. Proposed Compliance Order With respect to item(s) 1 and 4 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Enbridge Pipeline. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. 6#

420135004_NOPV PCP PCO_03042013_text.pdf, page 7Response 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 you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). 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 4-2013-5004 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 7#

420135004_NOPV PCP PCO_03042013_text.pdf, page 8PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Enbridge a Compliance Order incorporating the following remedial requirements to ensure the compliance of Enbridge with the pipeline safety regulations: 1. 2. 3. 4. In regard to Item Number 1 of the Notice pertaining to improperly determining the shell corrosion rates, Enbridge must modify its program to correctly determine the shell thicknesses and corrosion rates on all of the breakout tanks in the Cushing Terminal and re-determine the external inspection intervals for each breakout tank. In regard to Item Number 4 of the Notice pertaining to failing to achieve adequate cathodic protection on some of the breakout tanks and piping in the Cushing Terminal, Enbridge must take appropriate actions to remedy all cathodic protection deficiencies and show by structure-to-soil measurements that one or more of the cathodic protection criteria listed in NACE SP0169 or API RP651 has been achieved. In regard to Item Number 1 of the Notice, Enbridge must submit, for PHMSA approval, a shell thickness measurement procedure within 30 days of receipt of this Order. The Operator must then complete shell thickness re-measurements according to the approved procedure for all Cushing Terminal breakout tanks within 180 days of receiving PHMSA approval for the procedure. The Operator must also propose an initial shell re-measurement interval appropriate to determine a valid shell corrosion rate, and once the second measurement has been completed, recalculate the external inspection interval for all Cushing Terminal breakout tanks. Enbridge must complete the entire process to properly determine the external inspection intervals within 60 months from of receipt of this Order. In regard to Item Number 4 of the Notice, Enbridge must submit to PHMSA, a plan, with dates, to correct all cathodic protection deficiencies within 30 days of receipt of this Order. The Operator must complete correction of all deficiencies within 12 months of receipt of this Order. It is requested (not mandated) that Enbridge Pipeline, LLC 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. 8#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 1Official PDFSeptember 2, 2016 Mr. Mark Maki President Enbridge Pipelines (Ozark), LLC 1100 Louisiana Street Suite 3300 Houston, TX 77002 Re: CPF No. 4-2013-5004 Dear Mr. Maki: Enclosed is the Decision on the Petition for Reconsideration filed by Enbridge Pipelines (Ozark), LLC, in the above-referenced case. For the reasons explained therein, the Decision grants the Petition and modifies the civil penalty and compliance terms of the October 16, 2015 Final Order. The penalty terms are set forth in the Decision. 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. This Decision constitutes the final administrative action in this proceeding. Service of this Decision is made pursuant to 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Acting Associate Administrator for Pipeline Safety Enclosure cc: Mr. R. M. Seeley, Regional Director, Southwest Region, OPS Mr. Darren Hunter, Counsel for Enbridge Pipelines (Ozark), LLC, Rooney Rippie & Ratnaswamy, LLP, Kingsbury Center, Suite 600, 350 W. Hubbard Street, Chicago, Illinois 60654 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420135004_Decision on the Petition for Reconsideration_09022016_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 ) ) Enbridge Pipelines (Ozark), LLC, ) CPF No. 4-2013-5004 a subsidiary of Enbridge, Inc., ) ) Petitioner. ) ____________________________________) DECISION ON PETITION FOR RECONSIDERATION In November 2011, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Enbridge Pipelines (Ozark), LLC (Enbridge or Petitioner), at the company’s Cushing Terminal in Cushing, Oklahoma. The Cushing Terminal includes 87 crude oil storage tanks with approximately 20 million barrels in shell capacity.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (Notice) to Enbridge on March 3, 2013, which alleged certain violations of the pipeline safety regulations and proposed a civil penalty of $78,700.2 The Notice also proposed ordering Petitioner to take certain measures to correct the alleged violations. Enbridge responded to the Notice by letter dated April 26, 2013 (Response).3 The company contested one of the allegations of violation, provided certain information regarding the corrective actions it had taken, but did not request a hearing.4 On October 16, 2015, pursuant to 49 C.F.R. § 190.213, PHMSA issued a Final Order in this proceeding.5 The agency found that Enbridge had committed violations of § 195.432(b) (Item 1) 1 See www.enbridge.com. Current as of May 9, 2016. 2 Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), C.P.F. No. 4- 2013-5004, (Mar. 4, 2013) (on file with PHMSA). 3 Respondent’s Response to Notice (Response), (Apr. 26, 2013) (on file with PHMSA). 4 Id.#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 3CPF No. 4-2013-5004 Page 2 and §§ 195.565 and 195.571 (Item 4), as alleged in the Notice.6 The Final Order assessed a civil penalty of $33,700 for Item 1 and $45,000 for Item 4 and ordered corrective actions for both items, set forth in the compliance order that was part of the Final Order.7 The Final Order also issued warnings for probable violations of 49 C.F.R. § 195.432 (b) and (c) (Items 2 and 3) and § 195.581 (Item 5).8 In accordance with § 190.243, Enbridge filed a timely Petition for Reconsideration of the Final Order on November 9, 2015, seeking reconsideration of the finding of violation in Item 1 and its associated civil penalty and compliance terms.9 For the reasons stated below, I find that the finding of violation, civil penalty and compliance terms for Item 1 should be withdrawn for lack of sufficient evidence. Accordingly, as noted below, I am granting the Petition by withdrawing Item 1 of the Final Order in its entirety. The other provisions of the Final Order are otherwise affirmed without modification. Standard of Review Pursuant to 49 C.F.R. § 190.243, an operator may petition for reconsideration of a final order issued under § 190.213 and PHMSA may consider additional facts or arguments if the petitioner submits a valid reason explaining why such information was not presented prior to issuance of the final order. PHMSA may grant or deny, in whole or in part, a petition for reconsideration without further proceedings, but may request additional information or comment if deemed appropriate. Discussion Item 1 in the Final Order found that Petitioner violated 49 C.F.R. § 195.432(b), which states: § 195.432 Inspection of in-service breakout tanks. (a) … (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). 5 In the Matter of Enbridge Pipelines (Ozark), LLC, Final Order, C.P.F. No. 4-2013-5004 (Oct. 16, 2015) (Final Order) (available at www.phmsa.dot.gov/pipeline/enforcement). 6 Id. 7 Id. 8 Id. 9 Petitioner’s Petition for Reconsideration (Petition), (Nov. 9, 2015) (on file with PHMSA). Enbridge did not seek reconsideration of Items 2 through 5.#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 4CPF No. 4-2013-5004 Page 3 The Final Order determined the Petitioner had violated § 195.432(b) by failing to inspect the physical integrity of three in-service breakout tanks at its Cushing, Oklahoma facility, in accordance with American Petroleum Institute (API) Standard 653 (Standard).10 Specifically, PHMSA found that the Petitioner violated section 6.3.2.1 of the Standard by failing to properly determine the corrosion growth rates for several tanks in the Cushing facility.11 To illustrate, the Final Order noted that recorded shell-plate corrosion growth rates for three tanks in the Cushing facility were negative, indicating the methodology used by the Petitioner was flawed and inconsistent with the Standard.12 The Final Order further explained that even when considering pertinent variables such as steel tolerances and measurement differentials, the Petitioner’s methodology could only be effective if corrosion rates were completely uniform across the tanks.13 The Order also found that the negative values showed the company’s methodology for calculating the corrosion growth rates was not in accordance with sound engineering principles. In its Petition, Enbridge contends it did not violate § 195.432(b) and PHMSA wrongly concluded that the negative corrosion growth rates recorded for the three Cushing Terminal tanks implied that the company had employed an incorrect methodology.14 Enbridge argues that it applied the formula for corrosion growth rates as prescribed in the Standard and that the recorded negative values did not indicate noncompliance. Enbridge explains that it calculated metal loss, a component of the corrosion growth-rate calculation, by using the minimum (thinnest) thickness measurement taken on each tank and comparing it to the thickness measurements from the previous inspection for each tank.15 Enbridge further explains that using the minimum thickness measurement “add[ed] conservatism” to the metal-loss and corrosion-rate calculations.16 In its Petition, Enbridge further argues that the Notice erroneously alleged that the Standard required corrosion growth rates to be calculated by determining metal loss at the same location on each tank during each inspection.17 The Petition includes expert opinions stating that “tak[ing] measurements at random locations on the tank to determine general corrosion rates” is compliant with the Standard.18 10 API Standard 653, “Tank Inspection Repair, Alteration, and Reconstruction” (3rd edition, December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008) and errata (April 2008)), has been incorporated by reference into 49 C.F.R. Part 195 under 49 C.F.R. § 195.3. 11 Final Order, at 2. 12 Id. at 3. 13 Id. 14 Petition, at 3. 15 Petition, at 3-4; Response, at 2. 16 Response, at 2. 17 Petition, at 3. 18 Id. at 4.#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 5CPF No. 4-2013-5004 Page 4 The crux of this Petition involves the question of what constitutes the proper methodology for calculating external inspection intervals and tank-shell corrosion growth rates, which are prescribed by the Standard. Section 6.3.2.1 of the Standard states that external inspections shall occur at least every five years, or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in shells, and N is the shell corrosion rate in mils per year), whichever is less. Section 3.11 of the Standard defines corrosion rate (N) as “[t]he total metal loss divided by the period of time over which the metal loss occurred.” To calculate the corrosion rate (N) for a tank shell, metal loss must first be determined. The Standard, however, does not prescribe a specific methodology for calculating metal loss, nor does it specify a methodology for determining the thicknesses of tank shell-plates, an essential component of the metal loss calculation. In this case, OPS bears the burden of proving, by a preponderance of the evidence, that the Petitioner failed to calculate the inspection interval in accordance with the Standard. The “Shell Thickness Evaluation” reports (Reports) provided by the Petitioner during the PHMSA inspection show that the inspection intervals for the three tanks at issue were set at five years or less.19 The reports show that Enbridge had recorded shell-plate thickness measurements for each course of the individual tanks during the most recent inspections.20 The evidence does not reflect that Enbridge inspectors took more than a single shell-plate thickness measurement for each tank course; however, the Petitioner asserts that several shell-plate thickness measurements were taken and the smallest (thinnest) readings were recorded in the report as the thickness determinations for each course.21 Further, the Reports show that corrosion rates were calculated for each tank course based on these minimum shell-plate thickness readings by utilizing the formula prescribed in Section 3.11 of the Standard, total metal loss divided by the period of time over which the metal loss occurred.22 The Reports also show that the formula prescribed in Section 6.3.2.1 was applied as prescribed in calculating the inspection intervals for the three subject tanks.23 Finally, the Reports reflect that the ultimate inspection interval for each tank was based on the shortest interval calculated from all of the individual tanks’ courses.24 19 Pipeline Safety Violation Report (Violation Report), (Jul. 9, 2012), at 39-41. 20 Id. 21 Response, at 2. 22 See Violation Report, at 39, the calculations for Tank 1014 are as follows: RCA = (.593) – (.5198) = .07 corrosion allowance, N = .028 / 5.62 = .0049 mils / year, .07 / 4 (.0049) = 3.73 years (report reflects 3.67 years); Violation Report at 40, the calculations for Tank 2228 are as follows: RCA = (1.078 ) – (.8910) = .187 corrosion allowance, N = .091 / 9.80 = .009 mils / year, .187 / 4 (.009) = 5.05 years (report reflects 5.04 years); Violation Report at 41, the calculations for Tank 3011 are as follows: RCA = (.934) – (.8616) = .0724 corrosion allowance, N = .038 / 9.08 = .004 mils / year, .0724 / 4 (.004) = 4.525 years (report reflects 3.67 years). 23 Id. 24 Id. at 39-41.#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 6CPF No. 4-2013-5004 Page 5 I have carefully reviewed the entire record in this case and cannot determine that the methodology used by Enbridge to calculate the tank inspection intervals under the Standard was wrong or that it violated 49 C.F.R. § 195.432(b). First, I agree with the Petitioner that the negative corrosion growth rates recorded by Enbridge inspectors do not show that the company’s methodology was inherently flawed.25 Negligible or negative corrosion rates may occur while properly employing the corrosion-rate calculation set forth in the Standard, as argued by the Petitioner and its experts.26 This is because the calculations for tank shell corrosion rates and metal loss include shell-plate thickness measurements that can be affected by several variables, including steel tolerances, measurement differentials, and differing rates of corrosion. Those variables can result in negative metal loss calculations, even when the Standard is followed appropriately. Second, I agree with Enbridge that API 653 does not require that shell-plate thickness measurements be taken at the same location on each tank during each inspection when determining metal loss. Rather, the Standard is silent on the exact methodology that must be used for making the metal loss determination. While Enbridge’s methodology of using a minimum thickness reading for each tank course to determine a general corrosion rate may not be considered the optimal practice because single, anomalous readings can skew general corrosion rates, the Petitioner’s methodology did not expressly violate 49 C.F.R. § 195.432 or API 653.27 The Notice and Final Order found fault with Petitioner’s practice of taking shell-plate thickness measurements across each tank shell and using the lowest reading in the metal loss calculation for that tank. While the evidence shows Enbridge inspectors did not calculate the average shell- plate thicknesses when determining metal loss of the tanks in accordance with sound engineering practices, the Petitioner’s methodology does not expressly violate the requirements of Sections 6.3.2.1 or 3.11 of the Standard, as neither directly prescribes a methodology for determining shell-plate thickness measurements. Based on the evidence of record, I find there is insufficient evidence to show that Enbridge violated either the Standard or § 195.432(b). Accordingly, I grant the Petition for Reconsideration with respect to Item 1 of the Final Order. The finding of violation, the proposed penalty of $33,700, and the associated terms of the compliance order are hereby withdrawn. 25 Id. The Enbridge “Shell Thickness Evaluation” reports include shell corrosion rates for each tank course on the subject tanks. Several corrosion rates recorded for the tank courses were negative, in negligible amounts. 26 Petition, at 3. 27 Enbridge even argues that “there are variables that affect the [shell corrosion rate] calculation” in support of their argument that measuring in the same location on each tank is not the correct methodology. Petition, at 5.#

420135004_Decision on the Petition for Reconsideration_09022016_text.pdf, page 7CPF No. 4-2013-5004 Page 6 Conclusion For the reasons stated above, the Petition for Reconsideration is granted. The finding of violation in Item 1 of the Final Order, the associated penalty of $33,700, and the associated compliance terms are hereby withdrawn. All other terms of the Final Order and Compliance Order remain in effect as set forth therein. This Decision on Reconsideration is the final administrative action in this proceeding. ___________________________________ __________________________ Alan K. Mayberry Date Issued Acting Associate Administrator for Pipeline Safety#

420135004_Closure Letter_ 11072016_text.pdf, page 1Official PDFCERTIFIED MAIL – RETURN RECEIPT REQUESTED November 7, 2016 Mr. Brad Shamla Vice President, U.S. Operations Enbridge Storage (Cushing) L.L.C. 1100 Louisiana Street, Suite 3300 Houston, TX 77002 Re: CPF No. 4-2013-5004 Dear Mr. Shamla: On October 16, 2015, a Final Order was issued in the above-referenced case. The Final Order made a finding of violation and specified actions to be taken by Enbridge Storage (Cushing) L.L.C. (Enbridge). On September 2, 2016, a Decision on the Petition for Reconsideration was issued in the above- referenced case. The Decision on the Petition for Reconsideration withdrew Item 1 of the Final Order. Based on a PHMSA review it has been determined that Enbridge has completed the requirements of the Final Order. This letter is to inform you that 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#

420135004_Final Order_10162015_text.pdf, page 1Official PDFOctober 16, 2015 Mr. Mark Maki President Enbridge Pipelines (Ozark), LLC 1100 Louisiana Street Suite 3300 Houston, TX 77002 Re: CPF No. 4-2013-5004 Dear Mr. Maki: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a civil penalty of $78,700, and specifies actions that need to be taken by Enbridge Pipelines (Ozark), LLC, to comply with the pipeline safety regulations. 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 by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 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. Rodrick Seeley, Regional Director, Southwest Region, OPS Mr. Shaun Kavajecz, Senior Manager, US Pipeline Compliance, Enbridge Energy Company, Inc. 26 E. Superior Street, Suite 309 Duluth, MN 55811 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420135004_Final Order_10162015_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 ) Enbridge Pipelines (Ozark), LLC, ) a subsidiary of Enbridge, Inc., ) CPF No. 4-2013-5004 ) ) ) Respondent. ) _____________________________________) FINAL ORDER During November 2011, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Enbridge Pipelines (Ozark), LLC (Enbridge or Respondent), at the company’s Cushing Terminal in Cushing, Oklahoma. Enbridge is a subsidiary of Enbridge, Inc., an international energy company involved in the generation, transport, storage and distribution of oil, gas and electricity assets, with its corporate headquarters in Calgary, Canada, and a United States headquarters in Houston, Texas.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated March 3, 2013, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Enbridge had committed various violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $78,700 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. The warning items required no further action, but warned the operator to correct the probable violation or face future potential enforcement action. Enbridge responded to the Notice by letter dated April 26, 2013 (Response). The company contested certain elements of the allegations of violation and provided information concerning the corrective actions it had taken. Respondent did not request a hearing and therefore has waived its right to one. FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows: 1 See www.enbridge.com. Current as of January 3, 2015.#

420135004_Final Order_10162015_text.pdf, page 3CPF No. 4-2013-5004 Page 2 Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states: § 195.432 Inspection of in-service breakout tanks. (a) … (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 Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to properly inspect the physical integrity of several in-service breakout tanks at its Cushing, Oklahoma facility, in accordance with American Petroleum Institute (API) Standard 653.2 Specifically, the Notice alleged that Enbridge failed to properly determine the shell corrosion rates used to establish proper external inspection intervals under subsection 6.3.2.1 of that standard. 3 According to the Notice, a critical element in the formula set forth in subsection 6.3.2.1 and used to calculate a shell inspection interval less than the five-year maximum is N, the shell corrosion rate. PHMSA alleged that this variable in the formula should be calculated by dividing the measured metal loss by the time over which it occurred. Metal loss, in turn, is determined by subtracting a more recent shell thickness measurement from one made earlier in time at the same location on the breakout tank. The change in shell thickness would then be divided by the time interval between measurements to determine a corrosion rate. PHMSA asserted that since some of Enbridge’s metal loss calculations were negative, such a result would mean that the shell plate had actually increased in thickness over time. PHMSA alleged that this result indicated the methodology used by Enbridge was flawed and inconsistent with API Standard 653. In its Response, Enbridge argued that it had followed “industry-accepted” inspection practices and that the corrosion growth-rate calculation it had used was the same as that set out in API Standard 653 and was “used industry-wide.” The company explained that when determining the proper inspection intervals, it had compared shell-plate thickness measurements taken at different locations, instead of multiple measurements taken at the same location. Enbridge 2 API Standard 653, “Tank Inspection Repair, Alteration, and Reconstruction” (3rd edition, December 2001, which includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008) and errata (April 2008)), has been incorporated by reference into 49 C.F.R. Part 195 under 49 C.F.R. § 195.3. 3 API Standard 653, subsection 6.3.2.1, states: “6.3.2.1 All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every five years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection.”#

420135004_Final Order_10162015_text.pdf, page 4CPF No. 4-2013-5004 Page 3 argued that there are many variables that can affect these calculations, such as steel tolerances, measurement differentials, and differing rates of corrosion across various portions of the tanks that might have resulted in what the company reported as “negative corrosion growth.” Enbridge argued that such a result merely indicated that the corrosion growth rate was “negligible.”4 I find Enbridge’s argument unpersuasive. Considering any possible tolerance variables, it is only feasible for Enbridge’s methodology to be effective in the unlikely event that corrosion rates were completely uniform across the tanks, but the actual measurements taken by Enbridge show that the corrosion rates were not, in fact, uniform. It is clear that the “negative growth rate” used by Enbridge is inconsistent with the company’s own measurements and is most likely the result of a flawed methodology in calculating corrosion growth rate under API Standard 653. While Enbridge may have intended to apply API 653 properly, the company failed to properly determine the corrosion growth rate in accordance with sound engineering principles. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to properly inspect the physical integrity of several of its in- service breakout tanks at the Cushing, Oklahoma facility in accordance with API Standard 653. Item 4: The Notice alleged that Respondent violated 49 C.F.R. §§ 195.565 and 195.571, which state: § 195.565 How do I install cathodic protection in breakout tanks? After October 2, 2000, when you install cathodic protection under § 195.563(a) to protect the bottom of an aboveground breakout tank of more than 500 barrels (79.5m3) capacity built to API Specification 12F, API Standard 620, or API Standard 650 (or its predecessor Standard 12C), you must install the system in accordance with API Recommended Practice 651. However, installation of the system need not comply with API Recommended Practice 651 on any tank for which you note in the corrosion control procedures established under § 195.402(c)(3) why compliance with all or certain provisions of API Recommended Practice 651 is not necessary for the safety of the tank. § 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 SP 0169 (incorporated by reference, see § 195.3). The Notice alleged that Respondent violated 49 C.F.R. §§ 195.565 and 195.571 by failing to meet at least one of the applicable criteria for cathodic protection on several Cushing Terminal breakout tanks, as required by API Recommended Practice 651 and NACE SP 0169. 4 Response, at 2.#

420135004_Final Order_10162015_text.pdf, page 5CPF No. 4-2013-5004 Page 4 Specifically, the Notice alleged that Enbridge used the 100 mV polarization criterion on a portion of the breakout tanks and the -850 mV with consideration of IR drop on others. According to PHMSA, its inspector had found several breakout tanks where Enbridge was not meeting the specified criteria or had not taken the appropriate measurements to determine if the specified criterion was being met. For example, the Notice alleged that Respondent operated multiple tanks (#1153, #1295, #2211, #1182, #2218, #1320, #2212, #2215 and #2223) that did not comply with one of the established cathodic protection compliance criteria. In its Response, Enbridge did not contest the allegations and noted that it had begun a corrective action plan at the end of 2012 to enable it to successfully acquire 100 mV polarization criterion or -850 mV with consideration of IR drop. In addition, one of the non-compliant tanks was demolished during the first quarter of 2012 and a second was scheduled for demolition in the fourth quarter of 2013.5 PHMSA commends Respondent’s efforts to ensure future compliance, but would note that past non-compliance is not excused as a result. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. §§ 195.565 and 195.571 by failing to meet at least one of the applicable criteria for cathodic protection on several of its Cushing Terminal breakout tanks as required by API Recommended Practice 651 and NACE SP 0169. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. Under 49 U.S.C. § 60122, 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. 6 In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I 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 Respondent’s ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $78,700 for the violations cited above. Item 1: The Notice proposed a civil penalty of $33,700 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to properly determine shell corrosion rates necessary to establish external inspection intervals in accordance with API Standard 653. Respondent’s method of ASSESSMENT OF PENALTY 5 Response, at 6. 6 The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub. L. No. 112-90, § 2(a)(1), 125 Stat. 1904, January 3, 2012, increased the civil penalty liability for violating a pipeline safety standard to $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations.#

420135004_Final Order_10162015_text.pdf, page 6CPF No. 4-2013-5004 Page 5 measuring thickness resulted in inconsistent and unhelpful results, and as a result, Enbridge lacked accurate data on the shell thickness of several breakout tanks at the company’s Cushing Terminal for years. This resulted in reduced safety and an elevated risk of failure because of an ineffective safety-inspection protocol. Enbridge has not presented any evidence or argument that would justify a reduction in the proposed penalty. Accordingly, having reviewed the record and considered the seriousness of the offense and assessment criteria, I assess Respondent a civil penalty of $33,700 for violation of 49 C.F.R. § 195.432(b). Item 4: The Notice proposed a civil penalty of $45,000 for Respondent’s violation of 49 C.F.R. §§ 195.565 and 195.571, for failing to meet at least one of the applicable criteria for cathodic protection on some Cushing Terminal breakout tanks, in accordance with API Recommended Practice 651 and NACE SP 0169. Enbridge neither contested the allegation of violation nor offered any reason for its non-compliance. The failure to maintain proper cathodic protection for the company’s breakouts tanks could have led to a failure at a major terminal, where safety violations pose a higher level of risk. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $45,000 for violation of 49 C.F.R. §§ 195.565 and 195.571. In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $78,700. 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. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $78,700 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 Items 1 and 4 in the Notice for violations of 49 C.F.R. §§ 195.432(b), and 195.565 and 195.571, respectively. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. 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:#

420135004_Final Order_10162015_text.pdf, page 7CPF No. 4-2013-5004 Page 6 1. With respect to the violation of § 195.432(b) (Item 1), Respondent must modify its breakout tank inspection program to correctly determine the shell corrosion rates by correctly calculating the shell thickness and corrosion rates on all of the breakout tanks in the Cushing Terminal and re-determining the external inspection intervals for each breakout tank. 2. With respect to the violation of §§ 195.565 and 195.571 (Item 4), Respondent must take appropriate action to remedy all cathodic protection deficiencies and show, by structure-to-soil measurements, that one or more of the cathodic protection criteria listed in NACE SP 0169 or API RP651 have been achieved. 3. With respect to the violation of § 195.432(b) (Item 1), Respondent must submit, for PHMSA approval, a shell-thickness measurement procedure within 30 days of receipt of this Order. Enbridge must then complete shell thickness re-measurements according to the approved procedure for all Cushing Terminal breakout tanks within 180 days of receiving PHMSA approval for the procedure. Enbridge must also propose an initial shell re-measurement interval appropriate to determine a valid shell corrosion rate, and once the second measurement has been completed, recalculate the external inspection interval for all Cushing Terminal breakout tanks. Enbridge must complete the entire process to properly determine the external inspection intervals within 60 months from receipt of this Order. 4. With respect to the violation of § 195.565 (Item 4), Respondent must submit to PHMSA, a plan, with dates, to correct all cathodic protection deficiencies within 30 days of receipt of this Order. Enbridge must complete correction of all deficiencies within 12 months of receipt of this Order. 5. It is requested (not mandated) that Enbridge 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. The Director 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.#

420135004_Final Order_10162015_text.pdf, page 8CPF No. 4-2013-5004 Page 7 WARNING ITEMS With respect to Items 2, 3 and 5, the Notice alleged probable violations of Part 195 but did not propose a civil penalty or compliance order for these items. Therefore, these are considered to be warning items. The warnings were for: 49 C.F.R. § 195.432(b) and (d) (Items 2 and 3) ─ Respondent’s alleged failure to complete certain breakout tank repairs and to conduct required inspections necessary for safe operation or, in the alternative, provide engineering justification for not making such repairs; and 49 C.F.R. § 195.581 (Item 5) ─ Respondent’s alleged failure to consistently apply coating material to all of its breakout tanks suitable to prevent atmospheric corrosion. Enbridge presented information in its Response showing it had taken certain actions to address the cited items. If OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action. Under 49 C.F.R. § 190.243, Respondent has a right to submit a Petition for Reconsideration of this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA will accept petitions received no later than 20 days after receipt of service of this Final Order by the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all other 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#

420135004_Closure Letter_11072016.pdf, page 1Official PDFof Transportation U.S. Department 8701 S. Gessner, Suite 630 Houston, TX 77074 Pipeline and Administration Hazardous Materials Safety CERTIFIED MAIL - RETURN RECEIPT REQUESTED November 7, 2016 Mr. Brad Shamla Vice President, U.S. Operations Enbridge Storage (Cushing) L.L.C. 1100 Louisiana Street, Suite 3300 Houston, TX 77002 Re: CPF No. 4-2013-5004 Dear Mr. Shamla: On October 16, 2015, a Final Order was issued in the above-referenced case. The Final Order made a finding of violation and specified actions to be taken by Enbridge Storage (Cushing) L.L.C. (Enbridge). On September 2, 2016, a Decision on the Petition for Reconsideration was issued in the above- referenced case. The Decision on the Petition for Reconsideration withdrew Item 1 of the Final Order. Based on a PHMSA review it has been determined that Enbridge has completed the requirements of the Final Order. This letter is to inform you that 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#