Case ECF No. 9-5 filed 01/19/17 PageID.1301 Page 1 of 225 Exhibit 3 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1302 Page 2 of 225 IN THE UNITED STATES DISTRICT COURT FOR THE WESTERN DISTRICT OF MICHIGAN SOUTHERN DIVISION ___________________________________________ ) ) UNITED STATES OF AMERICA, ) Plaintiff, ) ) v. ) ) ENBRIDGE ENERGY, LIMITED ) PARTNERSHIP, ) ENBRIDGE PIPELINES (LAKEHEAD) L.L.C., ) ENBRIDGE ENERGY PARTNERS, L.P., ) ENBRIDGE ENERGY MANAGEMENT, L.L.C., ) ENBRIDGE ENERGY COMPANY, INC. , ) ENBRIDGE EMPLOYEE SERVICES, INC., ) ENBRIDGE OPERATIONAL SERVICES, INC., ) ENBRIDGE PIPELINES INC., and ) ENBRIDGE EMPLOYEE SERVICES CANADA ) INC., ) ) Defendants. ) ___________________________________________ ) Civil Action No. 1:16-cv-914 Judge Gordon J. Quist CONSENT DECREE REVISED FOLLOWING PUBLIC COMMENT PERIOD Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1303 Page 3 of 225 TABLE OF CONTENTS BACKGROUND ............................................................................................................... 1 JURISDICTION AND VENUE ...................................................................................... 10 APPLICABILITY ............................................................................................................ 11 DEFINITIONS ................................................................................................................. 12 CIVIL PENALTY ............................................................................................................ 20 PAYMENTS FOR REMOVAL COSTS RELATING TO LINE 6B DISCHARGES ................................................................................................. 22 INJUNCTIVE MEASURES ............................................................................................ 25 A. ORIGINAL US LINE 6B ................................................................................................ 25 B. REPLACEMENT OF LINE 3 ......................................................................................... 25 C. HYDROSTATIC PRESSURE TESTING ....................................................................... 28 D. IN-LINE INSPECTION BASED SPILL PREVENTION PROGRAM .......................... 30 (I) In-Line Inspections...................................................................................................... 30 (II) Review of ILI Data...................................................................................................... 32 (III) Identification of Features Requiring Excavation ........................................................ 37 (IV) Predicted Burst Pressure/Fitness for Service .............................................................. 44 (V) Dig Selection Criteria .................................................................................................. 46 (VI) Remaining Life Determinations/Reinspection Intervals ............................................. 72 E. MEASURES TO PREVENT SPILLS IN THE STRAITS OF MACKINAC ................. 74 F. DATA INTEGRATION .................................................................................................. 80 G. LEAK DETECTION AND CONTROL ROOM OPERATIONS ................................... 83 (I) Assessment of Alternative Leak Detection Technologies .......................................... 83 (II) Report on Feasibility of Installing External Leak Detection System at the Straits of Mackinac .............................................................. 84 (III) Requirements for New Lakehead Pipelines and Replacement Segments ................... 85 (IV) Leak Detection Requirements for Pipelines within the Lakehead System ................. 93 (V) Leak Detection Requirements for Control Room ..................................................... 101 H. SPILL RESPONSE AND PREPAREDNESS ............................................................... 110 I. NEW REMOTELY CONTROLLED VALVES ........................................................... 124 J. INDEPENDENT THIRD PARTY CONSENT DECREE COMPLIANCE VERIFICATION................................................................................. 126 REVIEW AND APPROVAL OF DOCUMENTS ........................................................ 136 ii Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1304 Page 4 of 225 REPORTING REQUIREMENTS ................................................................................. 137 INFORMATION COLLECTION AND RETENTION ................................................ 141 STIPULATED PENALTIES ......................................................................................... 143 FORCE MAJEURE ....................................................................................................... 147 DISPUTE RESOLUTION ............................................................................................. 149 EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS ...................................... 151 COSTS ........................................................................................................................... 154 NOTICES ....................................................................................................................... 154 EFFECTIVE DATE ....................................................................................................... 156 RETENTION OF JURISDICTION ............................................................................... 156 MODIFICATION .......................................................................................................... 156 TERMINATION ............................................................................................................ 157 PUBLIC PARTICIPATION .......................................................................................... 159 SIGNATORIES/SERVICE............................................................................................ 160 INTEGRATION ............................................................................................................ 160 FINAL JUDGMENT ..................................................................................................... 160 APPENDICES ............................................................................................................... 161 iii Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1305 Page 5 of 225 BACKGROUND Plaintiff United States of America, on behalf of the United States Environmental Protection Agency (“EPA”) and the United States Coast Guard (“USCG”), filed this Consent Decree concurrently with a complaint against nine related parties – namely, Enbridge Energy, L.P., Enbridge Pipelines (Lakehead) L.L.C., Enbridge Energy Partners, L.P., Enbridge Energy Management, L.L.C., Enbridge Energy Company, Inc., Enbridge Employee Services, Inc., Enbridge Operational Services, Inc., Enbridge Pipelines Inc. and Enbridge Employee Services Canada Inc. (hereinafter “Enbridge” or “Defendants”). The Complaint alleges that Defendants own and operate the Enbridge Mainline System – one of the world’s largest pipeline systems with more than 3,000 miles of pipeline corridors in the United States and Canada. According to Enbridge, the Mainline System is the single largest conduit of liquid petroleum into the United States, delivering on-average 1.7 million barrels of oil into the U.S. each day – a figure that accounts for 23% of the U.S. crude oil imports. The portion of the Mainline System within the United States is known as the Lakehead Pipeline System (“Lakehead System”) and includes a network of pipelines that are grouped within right-of-ways that collectively span 1,900 miles from the international border near Neche, North Dakota to delivery points in the Midwest, New York, and Ontario. The products transported by these pipelines allegedly include natural gas liquids and a variety of light and heavy crude oils. The Complaint asserts claims against Enbridge under Sections 309 and 311 of the Clean Water Act (“CWA”), 33 U.S.C. §§ 1319 and 1321, and Section 2702 of the Oil Pollution Act (“OPA”), 33 U.S.C. § 2702, with respect to two oil spills that occurred in 2010 as the result of unlawful discharges of oil from two Lakehead System pipelines (“2010 Oil Spills”). The Complaint alleges that the first oil spill occurred when Lakehead System Line 6B (“Line Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1306 Page 6 of 225 6B”) ruptured near Marshall, Michigan on July 25, 2010 and, over the course of two days, repeatedly discharged harmful quantities of oil to navigable waters of the United States, including Talmadge Creek and the Kalamazoo River, and adjoining shorelines (“Line 6B Discharges”). The Complaint alleges that the second spill occurred two months later when another Lakehead System pipeline – known as Line 6A – developed a large leak near Romeoville, Illinois and discharged harmful quantities of oil to navigable waters of the United States, including an unnamed tributary to the Des Plaines River, and adjoining shorelines (“Line 6A Discharges”). Enbridge contends that the Romeoville Discharge was caused by a third-party water pipeline failure that damaged Line 6A. The Complaint alleges that the Line 6B Discharges resulted in the release of at least 20,082 barrels of oil. The Complaint further alleges that, as a result of such releases, the Kalamazoo River was closed in places over a three-year period while Enbridge engaged in an extensive cleanup effort in accordance with a series of orders issued by EPA under Section 311(c) of CWA, 33 U.S.C. § 1321(c), starting with an initial order issued on July 26, 2010. Such cleanup efforts included, among other things, dredging sections of the river as far downstream as 38 miles from the confluence of Talmadge Creek. As a result of removal actions conducted by Enbridge pursuant to administrative orders issued by EPA, portions of the Kalamazoo River were re-opened for recreational use beginning in April of 2012. By June 21, 2012, remaining sections of the Kalamazoo River were re-opened, although portions of the Kalamazoo River were closed again during dredging activities in 2013 and 2014. All portions of the Kalamazoo River have been open since October of 2014. 2 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1307 Page 7 of 225 In the fall of 2014, Enbridge completed removal activities required under a 2013 EPA Order that required, among other things, dredging in the Kalamazoo River. After Enbridge completed that work, EPA transitioned the lead for continuing removal activities to the State of Michigan. Pursuant to a Consent Judgment in Michigan Dep’t. of Envtl. Quality v. Enbridge Energy Partners, L.P. et al., 15-1411-CE (Calhoun County Circuit Court May 13, 2015), several of the Defendants committed, among other things, to perform additional response actions with respect to Line 6B Discharges. That Consent Judgment also recognizes that Enbridge entities have reimbursed approximately $10 million in expenses incurred by the Michigan Department of Environmental Quality and other state agencies for response activities, including emergency response, and natural resource damage assessment activities. As a result of the Line 6A Discharges and the Line 6B Discharges, Enbridge has incurred substantial removal costs and expenses, including costs and expenses associated with removing oil and oil-contaminated materials from public and private property, including properties owned by Enbridge. The Defendants have previously resolved claims for natural resources damages (“NRD”) resulting from the Line 6B Discharges through two interrelated settlements in Michigan Dep’t. of Envtl. Quality v. Enbridge Energy Partners, L.P. et al., 15-1411-CE (Calhoun County Circuit Court May 13, 2015), and United States et al. v. Enbridge Energy, Ltd. P’ship, et al., Civil Action No. 1:15-cv-00590-GJQ (December 3, 2015). Pursuant to these settlements, Enbridge will complete or has completed restoration projects along the Kalamazoo River. Projects that will be completed include, without limitation: (i) restoring and monitoring of 320 acres of wetlands impacted by the Line 6B Discharges and response activities, (ii) permanently restoring, creating or otherwise protecting at least 300 additional acres of wetland habitat in 3 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1308 Page 8 of 225 compensation for wetland losses, and (iii) conducting further studies and evaluations of waters affected by the Line 6B Discharges and restoration of functions provided by large woody debris removed from the Kalamazoo River as part of the removal actions. Enbridge has also provided funding to the State for monitoring of fish contamination, fish populations and macroinvertebrate populations along Talmadge Creek and the Kalamazoo River. Pursuant to these settlements, Enbridge has paid approximately $4 million that will be used to fund additional restoration projects that will be implemented by natural resource trustees, reimburse natural resource damage assessment costs of federal and tribal trustees, and support ongoing restoration planning activities of natural resource trustees. To date, the USCG has billed Enbridge approximately $57.8 million in costs related to the Line 6B Discharges, which includes most (but not all) of the costs charged against the Oil Spill Liability Trust Fund (“Fund”) as of October 1, 2015. Enbridge fully paid all bills received from USCG with respect to the Line 6B Discharges. The Complaint alleges that the Line 6A Discharges resulted in the release of at least 6,427 barrels of oil. Enbridge undertook efforts to clean up the spill, including the removal of oil from contaminated storm sewers and from a publicly-owned treatment works. In connection with the discharges from Line 6A, the USCG has billed Enbridge for $659,027 in removal costs, which includes all of the costs charged against the Fund as of October 1, 2015. Enbridge fully paid all such bills. On September 30, 2013, the NTSB issued a Pipeline Accident Brief concerning the Line 6A Discharges. The NTSB determined that the probable cause of the Line 6A Discharges was erosion caused by water jet impingement from a leaking 6-inch diameter water pipe located 6 inches below the Line 6A pipe. The NTSB further determined that the 4 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1309 Page 9 of 225 interruption of the cathodic protection currents by the close proximity of the improperly installed water pipe contributed to the Line 6A Discharges. Enbridge was not the owner or operator of the water pipe referred to in the NTSB Accident Brief. The NTSB did not issue any safety recommendations to Enbridge or any other entity concerning the Line 6A Discharges. Subsequent to the 2010 Oil Spills, Enbridge undertook a number of steps to reduce the potential for future oil discharges from its pipelines and improve the safety and integrity of the Lakehead System. Among other things, Enbridge undertook the following actions since the 2010 Oil Spills: Lakehead Plan: Pursuant to a corrective action order issued by the Pipeline and Hazardous Materials Safety Administration “(PHMSA”), Enbridge developed and implemented the “Lakehead Plan,” which outlines specific actions and timelines for safety improvements to specified pipelines within the Lakehead System, including procedures for ongoing inspection, replacement, and testing of Enbridge’s lines. Pipeline Replacement: After the Line 6B Discharges, rather than repairing Line 6B, Enbridge decided to replace the pipeline, which had been in operation for 43 years. As a result, in 2014, Enbridge completed construction of a new 285-mile pipeline (“New Line 6B”) to replace the entirety of original Line 6B (“Original Line 6B”) between Griffith, Indiana and the international border near Sarnia, Ontario. Enbridge thereafter ceased operation of Original Line 6B and removed remaining oil from Original Line 6B. In-line Inspections. After the 2010 Oil Spills, Enbridge substantially expanded, and improved upon, its use of in-line inspection (“ILI”) technology for maintaining the Lakehead System pipelines. ILI technology involves the 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1310 Page 10 of 225 insertion of an ILI tool – commonly called a “pig” – into a pipeline for the purpose of sizing and identifying flaws in the pipe, such as cracks or corrosion, that need to be excavated and repaired. After 2010, Enbridge increased the frequency and type of its ILI Tool Runs, as well as boosted the number of excavations conducted as a result of such investigations. As of September of 2014, Enbridge estimated that it had completed 180 ILI runs since the 2010 Oil Spills, resulting in 5,700 excavations on the Lakehead System. Hydrostatic Pressure Testing: In 2012, after a third oil transmission pipeline known as Line 14 on the Lakehead System ruptured in a pasture near Grand Marsh, Wisconsin, PHMSA ordered Enbridge to implement various remedial measures, including hydrostatic pressure testing of the pipeline. Such testing, which is mandatory for all new pipelines, involves pressurizing the pipeline with water to a point where the pipeline will rupture if it contains unrepaired or undiscovered features with a burstpressure at or near the maximum test pressure. Enbridge completed hydrostatic pressure testing of 196 miles of Line 14 in 2012 without experiencing a leak or rupture. In accordance with another PHMSA corrective action order, Enbridge used hydrostatic pressure testing to confirm the integrity of 326 miles of Lakehead System Line 2 oil transmission pipeline between Neche, North Dakota and Superior, Wisconsin in 2015. Improvements to Emergency Response: Enbridge represents that it spent $50 million since the 2010 Oil Spills to improve equipment, training, and overall response in the event of a failure of a Lakehead System pipeline. Most recently, in September of 2015, hundreds of personnel from Enbridge, EPA, and USCG, together with state and local officials, conducted a full-scale exercise to test plans to respond to a spill in the Straits of Mackinac. Additionally: 6 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1311 Page 11 of 225 a) Enbridge revised its emergency response planning documents, known as Integrated Contingency Plans (ICPs), which were approved by PHMSA. Enbridge also developed Tactical Response plans for specific areas within the Lakehead System, including the Straits of Mackinac. b) Enbridge represents that it has implemented the spill response training recommended by the U.S. Federal Emergency Management Agency (“FEMA”) to improve the coordination between Enbridge and government emergency responders. Such training includes, among other things, Incident Command System (“ICS”) Level 100 through Level 300 training for all appropriate personnel listed in the ICPs, including employees assigned to incident management teams (“IMT”) and senior managers who may serve as a qualified individual in the event of a spill. c) Enbridge represents that it purchased additional emergency response equipment to enhance Enbridge’s existing equipment inventories across the Lakehead System. Newly available equipment includes incident command post trailers, decontamination trailers, work boats, submerged oil trailers, portable dam systems, tanks, boom, skimmers, and rig mats. Enbridge also contracted with additional emergency response contractors as reflected in Enbridge’s revised ICPs. d) Enbridge reorganized its emergency management department to improve its emergency planning and response capabilities. Enbridge represents that it has hired approximately 20 additional staff to support emergency response actions, including four Emergency Response Coordinators within its U.S. Operations. Enbridge formed an internal Emergency Response Advisory Team 7 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1312 Page 12 of 225 that meets quarterly, to ensure that emergency preparedness and planning is consistent within the Enbridge system and to share lessons learned across its pipelines. e) Enbridge has conducted outreach to the public and has developed publicly available training materials in an effort to better inform the public of the warning signs of a leak, potential hazards, the location of Enbridge pipelines, and the methods of notifying Enbridge of a leak. Enbridge represents that it conducted 250 community outreach sessions in 2013 alone. Installation of Valves: Pursuant to a Corrective Action Order issued by PHMSA, Enbridge installed 55 new remotely controlled valves that would reduce the impacts of a potential oil spill on certain water crossings. Improved Environmental Management: Enbridge implemented measures to improve its internal management and oversight of the safety and reliability of its entire pipeline system. Specifically: a) Enbridge created the Operations and Integrity Committee and the Safety and Reliability Committee. Enbridge senior executives participate in both of these committees. b) Enbridge created the role of Vice President, Enterprise Safety and Operational Reliability, which directs and oversees a dedicated team to support and direct company-wide safety and reliability. Pipeline Control: Enbridge established a Pipeline Control department with increased staffing dedicated to leak detection, which includes on-shift personnel who are dedicated to technical support of pipeline operators and to aid in the 8 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1313 Page 13 of 225 analysis of leak detection alarms. In addition, Enbridge has revised training requirements for leak detection analysts, pipeline operators, and other decision support staff, and currently requires operators to receive training that addresses issues such as in pipeline hydraulics, column separation analysis, incident investigation, emergency response, fatigue management, and leak detection training. Enbridge also requires semi-annual control room personnel team training that includes a focus on allowing operators to recognize and respond to unexpected conditions that may arise on the Enbridge system, including leak alarms originating from the SCADA or MBS systems. Straits of Mackinac: Enbridge has taken a number of steps to improve spill prevention on Line 5, including the Line 5 crossing at the Straits of Mackinac. These steps include: 1) conducting regular inspections using ILIs, divers, and remotely-operated vehicles to confirm the integrity of Line 5 in the Straits; 2) increasing the frequency of inspections and pipeline repairs above and beyond what is otherwise required by law; and 3) partnering with Michigan Technological University to develop new technology that will aid in inspecting the line. In 2015, Enbridge Pipelines, Inc. (“EPI”) transferred to Enbridge Employee Services Canada Inc. (“EESCI”) property owned by EPI in 2010; EESCI is a successor and assign of EPI. Enbridge acknowledges that EPA, in its discretion, (1) may share with PHMSA any information and proposed or final submittals provided by Enbridge or the Independent Third Party under the Consent Decree, and (2) may seek technical assistance from, and otherwise consult with, PHMSA concerning matters under the Consent Decree. 9 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1314 Page 14 of 225 The Parties now wish to resolve the United States’ claims in the Complaint relating to the 2010 Oil Spills by, among other things, Enbridge (1) paying civil penalties, (2) reimbursing additional removal costs that have been incurred by the United States relating to the Line 6B Discharges, and (3) undertaking the measures set forth in Section VII of this Decree. The Parties recognize, and the Court by entering this Consent Decree finds, that this Consent Decree has been negotiated by the Parties in good faith and will avoid litigation between the Parties and that this Consent Decree is fair, reasonable, and in the public interest. THEREFORE, before the taking of any testimony, without the adjudication or admission of any issue of fact or law, and with the consent of the Parties, IT IS HEREBY ADJUDGED, ORDERED, AND DECREED as follows: JURISDICTION AND VENUE This Court has jurisdiction over the subject matter of the United States’ claims in this action pursuant to Sections 309(b), 311(b)(7)(E) and (n) of the CWA, 33 U.S.C. §§ 1319(b), 1321(b)(7)(E) and (n), and Section 1017(b) of OPA, 33 U.S.C. § 2717(b), and 28 U.S.C. §§ 1331, 1345, 1355. Venue is proper in the Western District of Michigan under Sections 309(b) and 311(b)(7)(E) of the CWA, 33 U.S.C. §§ 1319(b) and 1321(b)(7)(E), Section 1017(b) of OPA, 33 U.S.C. § 2717(b), and 28 U.S.C. §§ 1391 and 1395 because claims asserted in the Complaint in this action arose in this district and Enbridge is located and doing business in this district. For purposes of this Decree, or any action to enforce this Decree, Enbridge consents to the Court’s jurisdiction over this Decree (or action to enforce the Decree) and over themselves, and they consent to venue in this judicial district. 10 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1315 Page 15 of 225 For purposes of this Consent Decree, Enbridge agrees that the Complaint states claims upon which relief may be granted pursuant to Sections 301 and 311 of the Clean Water Act, 33 U.S.C. §§ 1311 and 1321, and Section 2702 of OPA, 33 U.S.C. § 2702. Notice of the commencement of this action has been given to the States of Michigan and Illinois, as required by CWA Section 309(b), 33 U.S.C. § 1319(b). APPLICABILITY The obligations of this Consent Decree apply to and are binding upon the United States, and upon Enbridge and any successors, assigns, or other entities or persons otherwise bound by law. Each of the Defendants shall be jointly and severally liable for all of Enbridge’s obligations under this Consent Decree. No transfer of ownership or operation of any portion of the Lakehead System, whether in compliance with the procedures of this Paragraph or otherwise, shall relieve Enbridge of its obligation to ensure that the terms of the Decree are implemented. At least 30 Days prior to such transfer, Enbridge shall provide a copy of this Consent Decree to the proposed transferee and shall simultaneously provide written notice of the prospective transfer, together with a copy of the proposed written agreement, to EPA, the United States Attorney for the Western District of Michigan, and the United States Department of Justice, in accordance with Section XVI (Notices). Any attempt to transfer ownership or operation of the Lakehead System without complying with this Paragraph constitutes a violation of this Decree, provided, however, that in the case of any transfer to an entity controlled by Enbridge, Enbridge may satisfy the prior notification requirement of this Paragraph by providing notice to EPA and the United States, in accordance with Section XVI (Notices), at least 30 Days prior to the transfer, without providing a copy of the transfer agreement. 11 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1316 Page 16 of 225 Enbridge shall provide a copy of this Consent Decree to all officers, employees, agents and contractors whose duties might reasonably include compliance with any provision of this Decree. After the Effective Date, Enbridge shall require compliance with the Consent Decree as a material term of any contract with a third party whose duties might include compliance with any provision of this Decree. Likewise, Enbridge shall require such third-parties to flow down the same requirement to subcontractors whose duties might include compliance with any provision of this Decree. In any action to enforce this Consent Decree, Enbridge shall not raise as a defense the failure by any of its officers, directors, employees, agents, or contractors to take any actions necessary to comply with the provisions of this Consent Decree. DEFINITIONS Terms used in this Consent Decree that are defined in the CWA, or in regulations promulgated thereunder, shall have the meanings assigned to them in the Act or such regulations, unless otherwise provided in this Decree. Whenever the terms set forth below are used in this Consent Decree, the following definitions shall apply: “2010 Oil Spills” shall mean the Line 6A Discharges and Line 6B Discharges as defined below. “Area Contingency Plan” shall have the meaning set forth in the National Contingency Plan at 40 C.F.R. § 300.5. “Axially-Aligned Crack” shall mean any type of Crack feature that is oriented in the direction of the pipeline’s axis as opposed to the pipeline’s circumference. “Axial Grooving” and “Axial Slotting” shall mean any metal loss feature with a width less than 10 millimeters and a length greater than 30 millimeters. 12 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1317 Page 17 of 225 “Batch Pig” shall mean a type of device generally known as a “pig” that is inserted into a pipeline for the purpose of separating different batches or shipments of oil within the pipeline. “Column Separation” shall mean the condition where a pipeline segment is not entirely filled with liquid or is partly void. “Community Outreach” shall mean Enbridge’s program to inform and encourage public participation and education regarding Enbridge’s Lakehead System. The term “public” shall include citizens, entities or organized groups that may be impacted by any Lakehead pipeline. “Complaint” shall mean the Complaint filed by the United States in this action. “Consent Decree” or “Decree” shall mean this Decree and all Appendices attached hereto (listed in Section XXV). “Control Room” shall mean any operations center where Lakehead System pipelines are remotely monitored, operated and controlled by personnel using a Supervisory Control and Data Acquisition System, including the operations center in Edmonton, Alberta, Canada. “Corrosion feature” shall mean any feature on a pipeline detected by any tool, field measurement device, or other field observation that detects metal loss due to corrosion; provided, however, that for purposes of this Consent Decree, “corrosion features” shall not include any feature that Enbridge is able to determine reflects metal loss that is attributable to a grinding repair rather than to corrosion. 13 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1318 Page 18 of 225 “Crack feature” shall mean any feature on a pipeline detected by any tool, field measurement device, or other field observation that detects any crack or crack-like feature on the pipeline, whether the Feature Type is classified as crack-like, crack field, notch-like, surface-breaking lamination, linear indication, seam-weld manufacturing anomaly, hook cracks, or any other label denoting a crack or cluster of cracks. In addition, for purposes of this Consent Decree, Crack features shall be deemed to include Axial Slotting features, Axial Grooving features, selective seam Corrosion features and features identified in ILI reports as Seam Weld Anomaly A/B. “Day” shall mean a calendar day unless expressly stated to be a business day. In computing any period of time under this Consent Decree, where the last Day would fall on a Saturday, Sunday, or U.S. federal holiday, the period shall run until the close of business of the next business day. “Defendants” shall have the same meaning as the term “Enbridge” as defined below. “Dig List” shall mean the list of Crack features, Corrosion features and Geometric features required to be excavated in accordance with Section VII.D. “Effective Date” shall have the definition provided in Section XVII. “Enbridge” shall mean Enbridge Energy, L.P., Enbridge Pipelines (Lakehead) L.L.C., Enbridge Energy Partners, L.P., Enbridge Energy Management, L.L.C., Enbridge Energy Company, Inc., Enbridge Employee Services, Inc., Enbridge Operational Services, Inc., Enbridge Pipelines Inc., Enbridge Employee Services Canada Inc., and any of their successors and assigns. 14 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1319 Page 19 of 225 “EPA” shall mean the United States Environmental Protection Agency and any of its successor departments or agencies. “Established Maximum Operating Pressure” or “Established MOP” or “MOP” shall mean, with respect to each Lakehead System Pipeline segment, the MOP value listed for that segment in column C of the spreadsheet located at https://www.epa.gov/enbridgespill-michigan/enbridge-revised-maximum-operating-pressure-values. For purposes of identifying the MOP value applicable to any particular pipeline segment, pipeline segments are identified (in column B of the above-cited spreadsheet) by the milepost location at the beginning of the segment, and each pipeline segment includes the entire distance between the listed milepost location and the milepost location listed for the next pipeline segment identified on the spreadsheet. “Feature Requiring Excavation” shall have the meaning set forth in Paragraph 36. “Field Burst Pressure” shall mean, with respect to each Crack feature and each Corrosion feature located on any section of a Lakehead System Pipeline that is excavated, whether for repair or mitigation of features, investigation of features or otherwise, the Predicted Burst Pressure of such feature calculated based on field measurements of feature length and depth obtained during examination of the feature at the time of the excavation. “Future Removal Costs” shall mean all costs, including direct and indirect costs, incurred and paid by the United States in responding to the Line 6B Discharges that were, or will be, charged against the Oil Spill Liability Trust Fund after October 1, 2015. “Geometric feature” shall mean any feature that involves deformation of the pipe as defined in 4.28 of API 1163 (1st Edition), including any bend, buckle, dent, ovality, 15 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1320 Page 20 of 225 ripple, wrinkle or other change that affects the roundness of the pipe’s cross section or straightness of the pipe. “High Consequence Area” or “HCA” shall have the meaning set forth in 49 C.F.R. § 195.450. “ILI Burst Pressure” shall mean, with respect to each Crack feature and each Corrosion feature, the Predicted Burst Pressure of such feature calculated based on ILI measurements of feature length and depth. “Initial Linefill” shall mean the initial process of starting pumps and filling a new pipeline with oil before deliveries of product can commence. “Interest” shall mean the interest rate specified in 28 U.S.C. § 1961 as of the date interest accrues under the Consent Decree. “Joint” shall refer to a single length of pipe, typically 40 feet or less, between two adjacent girth welds. “Lakehead ICPs” shall mean the integrated contingency plans for Lakehead System Pipelines. “Lakehead System” shall mean the portion of the Mainline System within the United States that is comprised of fourteen pipelines – Lines 1, 2B, 3, 4, 5, 6A, 6B, 10, 14, 61, 62, 64, 65, and 67 – and all New Lakehead Pipelines. “Lakehead System Pipeline” shall mean any pipeline that is part of the Lakehead System. “Line 6A Discharges” shall mean the discharges of oil into the environment from Lakehead System Line 6A oil transmission pipeline that occurred on or about 9, 2010, near Romeoville, Illinois. 16 September Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1321 Page 21 of 225 “Line 6B Discharges” shall mean the discharges of oil into the environment from Lakehead System Line 6B oil transmission pipeline that occurred on July 25-26, 2010, near Marshall, Michigan. “Local Emergency Responder” shall mean a person who works in close proximity to the Lakehead System and is among those responsible for going to the scene of an emergency such as an oil spill to provide assistance. “Material Balance System” or “MBS Leak Detection System” shall mean the computational pipeline monitoring system used by Enbridge to detect leaks or ruptures in the Lakehead System. “MBS Segment” shall mean a section of pipeline that is bounded on each end by adjacent flowmeters. “NCP” shall mean the National Oil and Hazardous Substances Contingency Plan, as codified in 40 C.F.R. Part 300. “New Lakehead Pipeline” shall have the meaning set forth in Paragraph 84.a. “Oil Spill Liability Trust Fund” shall mean the fund established pursuant to 26 U.S.C. §§ 4611 and 9509. “OneSource” shall mean the data-integration database described in Subsection VII.F of the Consent Decree. “OPA” shall mean the Oil Pollution Act of 1990, Pub. L. No. 101-380, 104 Stat. 484, 33 U.S.C. §§ 2701-2761. 17 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1322 Page 22 of 225 “Original US Line 3” shall mean the segment of Lakehead System Line 3 oil transmission pipeline currently operating between Neche, North Dakota and Superior that Enbridge is required to replace under Section VII.B of this Consent Decree. “Original US Line 6B” shall mean the 285-mile pipeline between Griffith, Indiana and the international border near Sarnia, Ontario that Enbridge replaced in 2014. “OSROs” shall mean oil spill response organizations. “Overlapping MBS Segment” shall mean a section of pipe integrating two or more MBS Segments for the purpose of establishing and maintaining temporary leak detection capability, as provided in Paragraph 94. “Paragraph” shall mean a portion of this Decree identified by an arabic numeral. “Parties” shall mean the United States and Enbridge. “Past Removal Costs” shall mean all costs, including, but not limited to, direct and indirect costs, incurred and paid by the United States in responding to the Line 6B Discharges and charged against the Oil Spill Liability Trust Fund as of October 1, 2015. “Pipeline and Hazardous Materials Safety Administration” or “PHMSA” shall mean the Pipeline and Hazardous Materials Safety Administration and any of its successor departments or agencies. “Predicted Burst Pressure” shall mean the lowest estimated pressure at which a feature is predicted to burst or rupture, calculated as specified in this Consent Decree. “PREP Guidelines” shall mean the guidelines prepared for the National Preparedness for Response Exercise Program used in emergency preparedness planning. 18 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1323 Page 23 of 225 “Priority Feature” shall have the same meaning as defined in Paragraph 33.b. “Remaining Life” shall mean the estimated period time remaining before a Crack feature or Corrosion feature is predicted to grow to the point where its Predicted Burst Pressure is less than or equal to the Established MOP at the location of the feature. “Remotely-Controlled Valve” shall mean any valve that is designed to be closed remotely by an operator from a Control Room. “Replacement Segment” shall have the same meaning as set forth in Paragraph 84.b. “Rupture Pressure Ratio” or “RPR” shall mean, with respect to any Crack or Corrosion feature, the Predicted Burst Pressure of such feature divided by the pressure at 100 percent Specified Minimum Yield Strength. “Section” shall mean a portion of this Decree identified by a roman numeral. “Sectionalize” shall mean the closure of all Remotely-Controlled Valves within any portion of a pipeline. “Shutdown” shall refer to the operational period between (1) the initial cessation of pumping operations in a pipeline, or section of pipeline, through which oil has been actively flowing and (2) the point where the flow rate within the pipeline, or section of pipeline, is zero. “Specified Minimum Yield Strength” or SMYS shall have the same meaning as defined at 49 C.F.R. § 195.2. 19 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1324 Page 24 of 225 “Startup” shall refer to the operational period between (1) the commencement of pumping operations in a pipeline that had been previously shut down and (2) the point where oil in the pipeline achieves a Steady State. “Steady State” shall mean the pipeline hydraulic condition that exists when all the pipeline operating parameters remain nearly constant over time. “Supervisory control and data acquisition system” or “SCADA system” shall have the same meaning as defined by 49 C.F.R. § 195.2. “Tool Run” shall mean the process of running an ILI tool with sensors through a pipeline, or section of pipeline, for the purpose of detecting, sizing, and classifying Crack features, Corrosion features, and Geometric features. “Transient-State” shall mean the operational condition when oil is moving through a pipeline, or section of pipeline, at a rate or pressure that is in flux. “United States” shall mean the United States of America, acting on behalf of EPA and the United States Coast Guard. “USCG” shall mean the United States Coast Guard and any of its successor departments or agencies. “Valve Segment” shall mean each segment of pipeline between two adjacent Remotely-Controlled Valves. CIVIL PENALTY Within 30 Days after the Effective Date, Enbridge shall pay the sum of sixty-one million dollars ($61,000,000), plus Interest, as a civil penalty for the Line 6B Discharges and an additional sum of one million dollars ($1,000,000), plus Interest, as a civil penalty for the Line 6A 20 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1325 Page 25 of 225 Discharges. Interest shall accrue on both amounts from the date on which the Consent Decree is lodged with the Court. Enbridge shall pay the civil penalties due by FedWire Electronic Funds Transfer ("EFT") to the U.S. Department of Justice in accordance with instructions to be provided to Enbridge by the Financial Litigation Unit (“FLU”) of the United States Attorney’s Office for the Western District of Michigan. Such monies are to be deposited in the Oil Spill Liability Trust Fund. The payment shall reference the Civil Action docket number assigned to this case and DOJ Number 90-5-1-1-10099 (for the line 6B Discharges) and DOJ Number 90-5-1-1-10124 (for the Line 6A Discharges), and shall specify that the payment is made for CWA civil penalties to be deposited into the Oil Spill Liability Trust Fund pursuant to 33 U.S.C. § 1321(s) and 26 U.S.C. § 9509(b)(8). Any funds received after 11:00 a.m. Eastern Standard Time shall be credited on the next business day. At the time of payments, Enbridge shall send a copy of the EFT authorization form and the EFT transaction record, together with a transmittal letter, which shall state that the payment is for the civil penalty owed pursuant to the Consent Decree in this case, and shall reference the Civil Action Number assigned to this case, and DOJ Number 90-5-1-1-10099 (for the Line 6B Discharges) and DOJ Number 90-5-1-1-10124 (for the Line 6A Discharges), to the United States in accordance with Section XVI, of this Decree (Notices) and by email to acctsreceivable.CINWD@epa.gov and by mail to: EPA Cincinnati Finance Office 26 Martin Luther King Drive Cincinnati, Ohio 45268 21 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1326 Page 26 of 225 Enbridge shall not deduct or capitalize the civil penalties paid under this Section in calculating federal income tax in the United States or Canada, any state income tax, or any provincial or territorial tax. PAYMENTS FOR REMOVAL COSTS RELATING TO LINE 6B DISCHARGES Payment for Past Removal Costs. Within 30 Days after the Effective Date, Enbridge shall pay $5,438,222 plus Interest accruing from the date of lodging of the Consent Decree to reimburse the Oil Spill Liability Trust Fund for Past Removal Costs. Payment shall be made in accordance with Paragraph 17.a (Past Removal Cost Payments). Payment for Future Removal Costs. Enbridge shall reimburse the Oil Spill Liability Trust Fund for all Future Removal Costs billed by USCG that are consistent with the NCP. On a periodic basis, USCG will send Enbridge a bill for payment of Future Removal Costs that includes an itemized costs summary identifying direct and indirect costs incurred by the United States for removal actions pertaining to the Line 6B Discharges. Enbridge shall make all payments within 30 Days after its receipt of each bill requiring payment, except as otherwise provided in Paragraph 18, in accordance with 17.b (“Future Removal Cost Payments”). Enbridge shall be liable for interest on the total amount of each bill, accruing as of the date payment of each bill became due. For the purposes of this Section (Payment for Removal Costs Relating to Line 6B Discharges), the term “interest” shall mean the interest rate specified in 28 U.S.C. § 1961 as of the date payment of a bill becomes due. Payment Instructions Past Removal Cost Payments. Enbridge shall pay the Past Removal Costs due under Paragraph 15 by EFT to the U.S. Department of Justice account, in accordance with 22 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1327 Page 27 of 225 current EFT procedures, referencing the Federal Project Number E10527 and DOJ Case Number 90-5-1-1-10099. Such payment shall be made in accordance with instructions provided to Enbridge by the FLU of the United States Attorney for the Western District of Michigan following lodging of the Consent Decree. Any payments received by the Department of Justice after 4:00 p.m. (Eastern Time) will be credited on the next business day. Future Removal Cost Payments. For all payments of Future Removal Costs under Paragraph 16, Enbridge shall make such payment by Fedwire EFT, referencing the Federal Project Number E10527 and DOJ Case Number 90-5-1-1-10099, in accordance with instructions to be provided. Notice of Payment: At the time of each payment made under this Section, Enbridge shall send a copy of the EFT authorization form and the EFT transaction record, together with a transmittal letter, to the United States in accordance with Section XVI (Notices), and to: Commandant (CG-LCL) Attn: Brian Judge, Chief Office of Claims and Litigation U.S. Coast Guard Stop 7213 2703 Martin Luther King Jr. Avenue SE Washington, D.C. 20593-7213 Director (NPFC) ATTN: LCDR LaCresha Johnson CG National Pollution Funds Center US Coast Guard Stop 7605 2703 Martin Luther King Jr Ave SE Washington, DC 20593-7605 In its transmittal letter, Enbridge shall state the payment is for removal costs owed pursuant to this Consent Decree and shall reference the Civil Action Number assigned to this case, the Federal Project Number E10527, and DOJ Case Number 90-5-1-1-10099. 23 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1328 Page 28 of 225 Contesting Future Response Costs. Enbridge may submit a Notice of Dispute, initiating the procedures of Section XIII (Dispute Resolution), regarding any Future Removal Costs billed under Paragraph 16 (Payment for Future Removal Costs) if it determines that the bill has a mathematical error or included a cost item that is not within the definition of Future Removal Costs, or if it believes that the bill includes costs that were the direct result of an action that was not consistent with the NCP. Such Notice of Dispute shall be submitted in writing within 30 Days after receipt of the bill and must be sent to the United States pursuant to Section XVI (Notices). Such Notice of Dispute shall specifically identify the contested Future Removal Costs and the basis for objection. If Enbridge submits a Notice of Dispute, Enbridge shall pay all uncontested Future Removal Costs within 30 Days after Enbridge’s receipt of the bill requiring payment. Simultaneously, Enbridge shall establish, in a duly chartered bank or trust company, an interest-bearing escrow account that is insured by the Federal Deposit Insurance Corporation (FDIC), and remit to that escrow account funds equivalent to the amount of the contested Future Removal Costs. Enbridge shall send to the United States, as provided in Section XVI (Notices), a copy of the transmittal letter and check paying the uncontested Future Removal Costs, and a copy of the correspondence that establishes and funds the escrow account, including, but not limited to, information containing the identity of the bank and bank account under which the escrow account is established as well as a bank statement showing the initial balance of the escrow account. If the United States prevails in the dispute, Enbridge shall pay the sums due (with accrued interest) to the United States within 7 Days after the resolution of the dispute. If Enbridge prevails concerning any aspect of the contested costs, Enbridge shall pay that portion of the costs (plus associated accrued interest) for which they did not prevail to the United States within 7 Days after the resolution of the dispute. Enbridge shall be disbursed any balance 24 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1329 Page 29 of 225 of the escrow account. All payments to the United States under this Paragraph shall be made in accordance with Paragraph 17 (Payment Instructions). The dispute resolution procedures set forth in this Paragraph in conjunction with the procedures set forth in Section XIII (Dispute Resolution) shall be the exclusive mechanisms for resolving disputes regarding Enbridge’s obligation to reimburse the United States for its Future Removal Costs. INJUNCTIVE MEASURES Enbridge shall fund and perform all injunctive measures set forth in Section VII as detailed in Subsections VII.A-J below and in Appendices A to F, which are incorporated into Section VII. Except as otherwise specifically provided in this Consent Decree, requirements of this Section VII shall apply to all of the Lakehead System. A. ORIGINAL US LINE 6B Enbridge is permanently enjoined from operating, or allowing anyone else to operate Original US Line 6B for the purpose of transporting oil, gas, diluent, or any hazardous substance. Nothing in this Paragraph shall be construed to preclude Enbridge from removing pumps or other equipment from Original US Line 6B and reusing such equipment. B. REPLACEMENT OF LINE 3; EVALUATION OF REPLACEMENT OF LINE 10 Replacement of Line 3 in the United States. Enbridge shall replace the segment of the Lakehead System Line 3 oil transmission pipeline that spans approximately 292 miles from Neche, North Dakota, to Superior, Wisconsin (“Original US Line 3”), provided that Enbridge receives all necessary approvals to do so. Enbridge shall seek all approvals necessary for the replacement of Original US Line 3, and provide approval authorities with complete and adequate information needed to support such 25 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1330 Page 30 of 225 approvals, as expeditiously as practicable, and Enbridge shall respond as expeditiously as practicable to any requests by approval authorities for supplemental information relating to the requested approvals. If Enbridge receives approvals necessary for replacement of Original US Line 3, Enbridge shall complete the replacement of Original US Line 3 and take Original US Line 3 out of service, including depressurization of Original US Line 3, as expeditiously as practicable. Within 90 Days after Original US Line 3 is taken out of service, Enbridge shall purge remaining oil from Original US Line 3 by running a cleaning pig through the line, and Enbridge shall complete final clean-out and decommissioning of Original US Line 3 within one year thereafter. Until decommissioning of Original U.S. Line 3 in accordance with Subparagraph 22.b, Enbridge shall limit the operating pressure in each segment of Original US Line 3 that Enbridge continues to operate so that the operating pressure within such segment does not exceed the MOP value specified for that segment in https://www.epa.gov/enbridge-spillmichigan/enbridge-revised-maximum-operating-pressure-values, unless and until Enbridge has completed hydrostatic pressure testing that validates use of an increased operating pressure, and has submitted to EPA a report summarizing the hydrostatic pressure test procedures and results. Under no circumstances shall a hydrostatic pressure test be deemed to validate an operating pressure within any hydrostatic pressure test segment that is higher than 80% of the lowest test pressure achieved in such test segment. If Enbridge has not taken all portions of Original US Line 3 out of service by December 31, 2017, Enbridge shall comply with the additional requirements set forth below: On an annual basis with the exception of the final year of service for the Original US Line 3, Enbridge shall complete valid ILIs of all portions of Original 26 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1331 Page 31 of 225 US Line 3 that Enbridge continues to operate, using the most appropriate tools for detecting, charactering, and sizing all of the following: Crack Features, Corrosion Features, and Geometric Features; Enbridge shall identify, excavate and mitigate or repair all Features Requiring Excavation detected in the ILIs required pursuant to Subparagraph 22.d.(1), in accordance with the requirements of Subsection VII.D; and Enbridge shall clean all portions of Original US Line 3 that Enbridge continues to operate and shall use biocide treatments to reduce microbiological activity on a quarterly basis. After Original US Line 3 is taken out of service, Enbridge shall be permanently enjoined from operating, or allowing anyone else to operate, any portion of the pipeline for the purpose of transporting oil, gas, diluent or any hazardous substance. Nothing in this Paragraph shall be construed to preclude Enbridge from removing pumps or other equipment from Original US Line 3 and reusing such equipment. Evaluation of Replacement of Portions of Line 10 within the United States: Within 120 Days of the Effective Date of the Consent Decree, Enbridge shall submit to EPA a report evaluating replacement of the entire portion of the Lakehead System Line 10 oil transmission pipeline between the Canadian border near Niagara Falls, NY, and the terminus of the pipeline near West Seneca, NY (“US Line 10”). The report shall evaluate replacement of the entire US Line 10. The Report shall also include a separate evaluation of replacement of the short segment of the pipeline that crosses the Niagara River at Grand Island, NY. The evaluation shall contain a discussion of the number, density, and severity of Crack features and Corrosion features found on 27 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1332 Page 32 of 225 US Line 10, as well as comparison of these features to those on the 21-mile section of Line 10 to be replaced near Hamilton, Ontario. C. HYDROSTATIC PRESSURE TESTING No less than 60 Days prior to any hydrostatic pressure testing undertaken pursuant to the terms of this Consent Decree, Enbridge shall prepare and submit to EPA a plan and schedule for hydrostatic pressure testing of the pipeline. The plan shall describe in detail how Enbridge will conduct the hydrostatic pressure test and demonstrate that the hydrostatic pressure test will comply with all requirements of Paragraph 25 below. Enbridge shall conduct the hydrostatic pressure test in accordance with the plan and schedule. Procedures for Hydrostatic Pressure Testing. All hydrostatic pressure tests conducted by Enbridge under this Consent Decree shall comply with the following testing procedures and requirements: The sections of each pipeline to be hydrostatically pressure tested shall be divided into various test segments, each of which will be separately pressurized as provided below in this Paragraph. Each test segment shall be able to meet the requirements specified in Subparagraph 25.b below. Within each test segment, hydrostatic pressure testing shall be performed over a continuous eight hour period, in accordance with the specifications set forth below in this Subparagraph: Enbridge shall maintain a pressure of at least 1.25 x MOP for four hours at all locations in each test segment. 28 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1333 Page 33 of 225 Enbridge shall maintain an operating pressure not less than 1.1 x MOP for the remainder of the continuous eight hour test period at all locations in each test segment. Enbridge shall complete the tests as soon as is practicable, but in no event shall testing take longer than 270 Days from the date of EPA’s receipt of the plan and schedule. Additional water may not be added to any tested line segment while the test is underway. At least 30 Days before conducting any pressure test, Enbridge shall provide written notification to EPA and all relevant federal agencies (e.g. PHMSA and Coast Guard) and relevant local emergency responders. Within 120 Days of completing each required hydrostatic pressure test, Enbridge shall prepare and submit to EPA a report describing the test and summarizing the results of the test, including a description of any features that leaked or ruptured during the test and planned corrective actions, including a schedule of completion, that Enbridge plans to take to address issues identified during the hydrostatic pressure test. Line Failure During Hydrostatic Pressure Testing: Enbridge shall take the following actions in the event of a leak or rupture of the pipeline during a hydrostatic pressure test: Enbridge shall immediately take all necessary and appropriate actions to prevent the discharge from the pipeline from reaching or spreading upon any body of water, including wetlands, or adjoining shoreline or area of dryland that could channel the release toward a body of water, including wetlands, or adjoining shoreline. Nothing in this Consent Decree is intended to waive, modify, or suspend Enbridge’s duty under the Clean Water Act to prevent 29 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1334 Page 34 of 225 discharges of oil or hazardous substances into or upon the waters of the United States or adjoining shorelines, as well as discharges of pollutants from a point source to waters of the United States, unless permitted, and to comply with all NPDES and state-issued permit conditions. Within 90 Days of the rupture or leak, Enbridge shall complete and submit to EPA an investigatory report of the pipeline failure. The report shall include a discussion of the failure mechanism based upon a laboratory or other investigation of the section of pipe with the rupture or leak. In addition, the report shall present findings and conclusions as to whether Enbridge’s ILI tools missed, or underestimated the size of, the metallurgical feature that caused the rupture or leak. If the feature was missed or undersized by such tools, Enbridge shall propose a plan and schedule for undertaking corrective action to ensure that similar features do not pose a threat to any Lakehead System Pipeline. D. IN-LINE INSPECTION BASED SPILL PREVENTION PROGRAM (I) In-Line Inspections Enbridge shall implement the requirements of this Subsection VII.D.(I) in order to assure timely identification and evaluation of all features, including features that pose either leak or rupture threats, whether such features are located in the base metal (either interior or exterior surfaces), long seam, or girth welds. Such features may include, but are not limited to, Crack or Crack-like features, including stress corrosion cracks, crack fields, and hook cracks, seam weld anomalies, including lack of fusion anomalies, Selective Seam Corrosion, Axial Slotting and Axial Grooving, other Corrosion features, dents, and other Geometric features. For the purposes of this Consent Decree, the terms “rupture” and “leak” shall include any “discharge” within the meaning of Section 311 of the CWA, 33 U.S.C. § 1321(a)(2). 30 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1335 Page 35 of 225 Enbridge shall conduct periodic In-Line Inspections (“ILIs”) of each pipeline in accordance with this Consent Decree using ILI tools that are most appropriate for accurately detecting, characterizing and sizing all Crack features, Corrosion features and Geometric features that are present or anticipated on the particular pipeline being inspected. After the Effective Date of the Consent Decree, Enbridge shall complete valid ILIs of the entire length of each pipeline using, at a minimum, each of the following: (1) an ILI tool that is most appropriate for accurately detecting, characterizing and sizing all Crack features that may be present, (2) an ILI tool that is most appropriate for accurately detecting, characterizing and sizing all Corrosion features that may be present, and (3) an ILI tool that is most appropriate for accurately detecting, characterizing and sizing all Geometric features that may be present. Until termination of this Consent Decree in accordance with Section XX, below, Enbridge shall periodically re-inspect each Lakehead System Pipeline using ILI tools that meet all of the requirements described above in this Paragraph 28. Except as provided in Paragraph 70, all ILIs required under this Consent Decree shall be scheduled and completed in accordance with the re-inspection interval requirements in Paragraphs 65 and 66, below. Enbridge shall require each of its ILI vendors to notify Enbridge immediately of any instance in which the vendor determines that (i) a scheduled ILI of any Lakehead System Pipeline could not be completed due to an ILI tool malfunction or other circumstance that prevented the collection of valid, reliable data, or (ii) a completed ILI of any Lakehead System Pipeline is not valid or reliable for any reason. In each such case involving an incomplete or invalid ILI, Enbridge shall take all steps necessary to complete a valid ILI within the timeframes specified in Paragraphs 65 and 66. 31 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1336 Page 36 of 225 Within 30 Days of the Effective Date of the Consent Decree, Enbridge shall submit to EPA a schedule that will identify each ILI scheduled to be initiated on any pipeline during a 12 month period following the Effective Date of the Consent Decree. Thereafter in each Semi-Annual Report required pursuant to Paragraph 143, Enbridge shall identify each ILI that is scheduled to be initiated on any pipeline during the 12-month period after the close of the reporting period covered by that Semi-Annual Report. Each ILI schedule referred to in this Paragraph shall be consistent with the re-inspection interval requirements in Paragraphs 65 and 66, below. Enbridge shall perform all ILIs in accordance with the schedules referred to in Paragraph 29 and the requirements of Paragraphs 65, 66, and 70 below. The Parties may agree to modify any ILI schedule without the need for Court approval, provided that the modified schedule remains consistent with the requirements in Paragraphs 65, 66, and 70. Compliance with Tool Specifications: Enbridge shall assure that ILI tools are operated consistently within manufacturer/vendor specifications, including tool speed. In each Semi-Annual Report required under Paragraph 143, Enbridge shall report each instance in which any ILI tool operates outside tool specifications. In such reports, Enbridge shall also evaluate the causes of the failure to adhere to the tool specifications and describe all steps that Enbridge has taken, or plans to take, to prevent or reduce the likelihood of a recurrence. (II) Review of ILI Data Enbridge shall require each of its vendors of ILI services to submit an initial report to Enbridge promptly after each ILI of any Lakehead System Pipeline (“Initial ILI Report”), except in cases where the ILI vendor has previously notified Enbridge in accordance with Paragraph 28.c that an ILI could not be completed or was not valid. This Initial ILI Report shall 32 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1337 Page 37 of 225 include all data relating to all features detected by the ILI tool, as well as all information relevant to tool speed and performance. Enbridge shall require submission of Initial ILI Reports in accordance with the following schedule: In the case of ILI tools used to assess Crack features, Initial ILI Reports shall be submitted to Enbridge within 120 Days after the tool is removed from the pipeline at the conclusion of the in line inspection. In the case of ILI tools used to assess Corrosion features, Initial ILI Reports shall be submitted to Enbridge within 90 Days after the tool is removed from the pipeline at the conclusion of the in line inspection. In the case of ILI tools used to assess Geometric features, Initial ILI Reports shall be submitted to Enbridge within 60 Days after the tool is removed from the pipeline at the conclusion of the in line inspection. Priority Features Enbridge shall require each of its vendors of ILI services to notify Enbridge of any Priority Feature identified during an ILI and to provide Enbridge with the ILI data relating to such Priority Feature immediately upon identification of the Priority Feature, without waiting for preparation and submission of the Initial ILI Report. For the purposes of this Consent Decree, a “Priority Feature” shall mean any Crack feature, Corrosion feature, or Geometric feature that may require priority attention over other features based upon criteria specified by Enbridge in its contract or work order with the vendor for ILI services. In such a contract or work order, Enbridge shall define a Priority Feature as including, among other things, any feature that the ILI vendor may consider to be an immediate 33 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1338 Page 38 of 225 threat to the integrity of the pipeline. At a minimum, Priority Features shall include features that meet the criteria set forth in Appendix A. Within two (2) Days after receiving notification of any Priority Feature, Enbridge shall review the ILI data relating to each such feature and any other relevant information and determine whether such feature was correctly identified and whether the feature was previously repaired or mitigated. As expeditiously as practicable after making such determinations, but in no event more than two (2) Days after doing so, Enbridge shall determine whether such Priority Feature is a Feature Requiring Excavation in accordance with Section VII.D.(III), and add such Priority Feature to the Dig List in accordance with Paragraph 37, and determine whether a point pressure restriction is required for such Priority Feature and, if so, establish such pressure restriction, in accordance with Paragraphs 47 - 59 below. Enbridge shall excavate and repair or mitigate each Priority Feature that qualifies as a Feature Requiring Excavation, in accordance with the timetables set forth in Subsection VII.D.(V), below. Data Quality Review Within 30 Days after receiving any Initial ILI Report, Enbridge shall complete a preliminary review of the Initial ILI Report. As part of the preliminary review, Enbridge shall identify all concerns with respect to the quality of any reported ILI data, and Enbridge shall identify all pipeline sections and/or features affected by the identified data quality concerns. 34 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1339 Page 39 of 225 With respect to all pipeline sections and/or features for which Enbridge did not identify data quality concerns during its preliminary review of any Initial ILI Report, Enbridge shall immediately proceed to evaluate whether such pipeline sections and/or features include any Feature Requiring Excavation, consistent with the requirements in Subsection VII.D.(III), below. With respect to all pipeline sections and/or features for which Enbridge identified data quality concerns during its preliminary review of any Initial ILI Report, Enbridge shall complete any evaluations required to resolve all of the identified data quality concerns as expeditiously as practicable. Except with respect to any investigative dig programs required under Subparagraph 34.e below, Enbridge shall complete all data quality evaluations of ILI data within 180 Days after the ILI tool is removed from the pipeline at the conclusion of any ILI investigation. During its preliminary review of the Initial ILI Report, Enbridge may also identify potential data quality concerns if there is a significant discrepancy between the data provided in the Initial ILI Report and the data provided in the most recent previous assessment of the same pipeline with respect to the severity, density or type of detected Features Requiring Excavation. For purposes of this Subparagraph 34.e, a discrepancy with respect to the severity of reported features shall be considered significant if at least 60% of the population of reported features are either (A) more severe than previously reported and more severe than predicted by the most recent assessment of anticipated feature growth, or (B) less severe than previously reported. Further, for the purpose of this Subparagraph 34.e, a discrepancy with respect to the 35 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1340 Page 40 of 225 density of reported features shall be considered significant if the number of reported features is at least 20% greater or 20% less than the number of features previously reported. Whenever Enbridge identifies a significant discrepancy with respect to the severity, density or type of features, within the meaning of this Subparagraph 34.e, Enbridge shall conduct an investigation to evaluate the accuracy and reliability of the data provided in the Initial ILI Report currently under consideration. If Enbridge is unable to account for identified discrepancies based on a review of available information, including repair records, ILI tool differences (including differing tool tolerances and detection thresholds), algorithm differences, or other relevant information, Enbridge may conduct an investigative dig program to collect field measurements of a sufficient number of relevant features to assess the accuracy and reliability of the data presented in the Initial ILI Report. Enbridge shall validate and document the precision and accuracy of all field measurement equipment and procedures used in any investigative digs. Enbridge shall assure that any equipment used to obtain field measurements is capable of accurately detecting and sizing all features or anomalies at and above the relevant ILI tool tolerance. If a comparison of field measurements obtained during an investigative dig program and ILI data relating to the same features or pipeline sections demonstrates a systematic bias or scatter in the reported ILI data, Enbridge shall determine the nature and magnitude of any bias or error. Enbridge may adjust the reported ILI data to correct for any demonstrated bias or scatter, as provided below in this Subsection VII.D.(II). 36 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1341 Page 41 of 225 The data quality evaluations undertaken by Enbridge pursuant to this Subsection VII.D. (II), including any investigatory dig programs undertaken pursuant to Subparagraph 34.e, shall not affect or delay Enbridge’s obligation to timely identify Features Requiring Excavation and complete Dig Lists as provided in Paragraph 37, below. Pending completion of any investigative dig program pursuant to Subparagraph 34.e, Enbridge shall use the ILI-reported values applicable to any features under investigation for purposes of identifying Features Requiring Excavation and compiling the Dig List, in accordance with Subsection VII.D.(III). Upon completion of any investigative dig program, Enbridge may revise the Dig List to the extent that ILI data adjusted in accordance with Subparagraph 34.e.(3) results in changes in the identification of Features Requiring Excavation. Enbridge shall repair or mitigate, at the time of the investigative dig, any feature found during the investigative dig that meets one or more of the dig-selection criteria in Subsection VII.D.(V), below. (III) Identification of Features Requiring Excavation Following each ILI, Enbridge shall evaluate each feature identified in the Initial ILI Report to determine whether the feature is a Feature Requiring Excavation. For the purposes of this Consent Decree, the term “Feature Requiring Excavation” shall mean any Crack feature, Corrosion feature, or Geometric feature that meets one or more of the dig-selection criteria in Subsection VII.D.(V), below. With respect to Crack features and Corrosion features, Enbridge shall apply three methods to identify a Feature Requiring Excavation. First, Enbridge shall estimate the lowest pressure at which the feature is predicted to rupture or leak (“Predicted Burst Pressure”) using the procedures set forth in Subsection VII.D.(IV), below. Second, Enbridge shall estimate the amount of time remaining until the 37 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1342 Page 42 of 225 feature is predicted to rupture or leak (“Remaining Life”) using the procedures set forth in Subsection VII.D.(VI), below. Finally, Enbridge shall consider other unique characteristics of the feature using the criteria set forth in Subsection VII.D.(V). With respect to Geometric features, Enbridge shall apply only the latter method in identifying a Feature Requiring Excavation. Following each ILI of any Lakehead System Pipeline, other than an ILI that is determined to be invalid as provided in Paragraph 28.c, above, Enbridge shall identify all Crack features, Corrosion features, and Geometric features detected by the ILI that are Features Requiring Excavation and add such features to the electronic list of features scheduled for excavation and repair or mitigation (“Dig List”) in accordance with the schedule below, but in no event shall such actions occur more than 180 Days after the ILI tool is removed from the pipeline at the conclusion of any ILI investigation. METHOD OF IDENTIFYING FEATURES REQUIRING EXCAVATION APPLICABLE DEADLINES FOR INDENTIFYING FEATURES REQUIRING EXCAVATION AND PLACING SUCH FEATURES ON THE DIG LIST Features that are identified as Features Requiring Excavation based upon their Predicted Burst Pressure Enbridge shall complete identification of all such Features Requiring Excavation and add such features to the Dig List within five Days of calculating the Predicted Burst Pressure of the features in accordance with Subsection VII.D.(IV), below. Features that are identified as Features Requiring Excavation based upon their Remaining Life Enbridge shall complete identification of all such Features Requiring Excavation and add such features to the Dig List within five Days of calculating the Remaining Life of the features in accordance with Subsection VII.D.(VI) below. 38 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1343 Page 43 of 225 METHOD OF IDENTIFYING FEATURES REQUIRING EXCAVATION APPLICABLE DEADLINES FOR INDENTIFYING FEATURES REQUIRING EXCAVATION AND PLACING SUCH FEATURES ON THE DIG LIST Features that are identified as Features Requiring Excavation based upon reasons other than their Predicted Burst Pressure or their Remaining Life Enbridge shall complete identification of all such Features Requiring Excavation and add such features to the Dig List within 5 Days of completing the preliminary review of the Initial ILI Report, provided that such a review does not identify any data quality concerns relating to the feature. For those features with data quality concerns, Enbridge shall complete identification of all Features Requiring Excavation and add such features to the Dig List within 5 Days after resolving those data quality concerns. For each Feature Requiring Excavation placed on the Dig List, including any Feature Requiring Excavation placed on the Dig List pursuant to Subparagraph 40.c, below, Enbridge shall take the following actions: Establish excavation and repair deadlines that take into account the level of the threat posed by the feature, but in no event shall the deadline for any feature exceed the number of Days allotted for excavation and repair of the feature as set forth Subsection VII.D.(V), below. If a feature meets more than one dig-selection criteria in Subsection VII.D.(V), below, Enbridge shall excavate and repair the feature in accordance with the shortest applicable timetable for excavation and repair of the feature, and Establish any pressure restriction required for such feature pursuant to Subsection VII.D.(V), below. In any case where such a feature is subject to more than one pressure restriction under Subsection VII.D.(V), Enbridge shall establish the pressure restriction that results in the lowest operating pressure at the location of the feature. 39 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1344 Page 44 of 225 (1) Although the pressure restriction requirements in Subsection VII.D.(V) for any individual feature are expressed in terms of “point pressure restriction values” (i.e., the maximum permissible pressure at the location of the feature), the pressure restriction requirement may be satisfied by limiting the discharge pressure at the nearest upstream pump station to a level that assures compliance with the point pressure restriction value at the location of the feature. (2) In any case where a feature subject to a pressure restriction under VII.D.(V) is located in a pipeline segment for which any discharge pressure restriction has been established, Enbridge must maintain compliance with the applicable discharge pressure restriction even if it reduces operating pressure at the location of such feature below the level established under Section VII.D.(V). Following each ILI, Enbridge shall excavate and repair or mitigate all identified Features Requiring Excavation on the pipeline that was the subject of the ILI, in accordance with Subsection VII.D.(V). During such excavations, Enbridge shall obtain and record field measurements of all features on the excavated sections of such pipeline, except as provided below in this Paragraph 39. If Enbridge excavates any additional sections of such pipeline following the ILI, including investigative digs pursuant to Paragraph 34.e, above, Enbridge shall also obtain and record field measurements of all features on such additional pipeline sections, except as provided below in this Paragraph. In cases where an excavated section of pipe contains a high volume of unreported features, Enbridge need not collect and record field measurements of all features observed in the field, provided that (1) Enbridge obtains and records field measurements of all features that were identified by the ILI, as well as the five worst features not identified by the ILI; 40 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1345 Page 45 of 225 (2) Enbridge records the total number of unreported features that are detectible within ILI tool specifications and includes that information in its next Semi-Annual Report; and (3) Enbridge repairs or mitigates the features on such section of pipe by sleeving or replacing such section of pipe, or by grinding or blasting and recoating features on such section of pipe. In the case of unreported Crack features and unreported Corrosion features, features with the lowest predicted burst pressures shall be deemed to be the worst features. Notwithstanding the foregoing, Enbridge shall not be required for purposes of this Paragraph to record any field measurement values that are below the ILI tool detection thresholds. Within 30 Days after completing excavation of all Features Requiring Excavation identified on a pipeline based on any Initial ILI Report, Enbridge shall complete an analysis of field data obtained during all excavations conducted on such pipeline subsequent to the ILI, including investigative digs pursuant to Paragraph 34.e, above, and determine whether field data indicate that the ILI tool tended to understate the actual severity of features on the excavated sections of the pipeline (“ILI tool depth bias”). In performing the analysis required by this Paragraph, Enbridge shall consider all field data that has sufficient precision and reliability to assess the accuracy of the ILI-reported data. This determination shall be based on a statistical analysis indicating either that (i) field measurements of feature depths on excavated sections of the pipeline exceed ILI-reported feature depths on excavated sections of the pipeline by more than one tool tolerance, or that (ii) burst pressures of features on excavated pipe segments calculated using field measurement values of feature length and depths (“Field Burst Pressure”) are lower than burst pressures for the same features calculated using the ILI-reported feature length and depth (“ILI Burst Pressure”). Both Field Burst Pressure and ILI Burst Pressure values shall be 41 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1346 Page 46 of 225 calculated in accordance with Subsection VII.D.(IV), below, and Appendix B, except that the Field Burst Pressure value for each feature may be calculated using all recorded depth measurements for the feature, rather than using the maximum reported feature depth value and a flaw profile approximation, such as parabolic or rectangular. If Enbridge uses a statistical analysis of Field Burst Pressure values and ILI Burst Pressure values for features on excavated sections of any pipeline for the determination required in this Paragraph 40, and that analysis indicates that Field Burst Pressure values are greater than or equal to ILI Burst Pressure values, ILI-reported values concerning the length and depth of reported features shall be considered acceptable for purposes of this Paragraph 40, and Enbridge shall not be required to adjust any predicted burst pressure values previously calculated in accordance with Subsection VII.D.(IV), below, or any Remaining Life estimates calculated under Subsection VII. D.(VI), below, and Enbridge will not be required to add any new features to the Dig List. If Enbridge uses a statistical analysis of Field Burst Pressure values and ILI Burst Pressure values for features on excavated sections of any pipeline for the determination required in this Paragraph 40, and that analysis indicates that Field Burst Pressure values are lower than ILI Burst Pressure calculations on such excavated pipeline sections, Enbridge shall (i) revise the calculated burst pressure values previously calculated in accordance with Subsection VII.D.(IV) below, for all remaining unrepaired features on such pipeline, to appropriately account for the reduction in burst pressure values established on the basis of field measurements, and (ii) revise Remaining Life estimates previously calculated in accordance with Subsection VII.D.(VI), below, for all unrepaired features on such pipeline to appropriately account for additional information regarding feature depth obtained during excavations. To the extent that the revised 42 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1347 Page 47 of 225 burst pressure or Remaining Life calculations indicate that any features remaining on such pipeline are Features Requiring Excavation, such features shall be added to the Dig List within 5 Days after completing the relevant calculations. If Enbridge does not undertake a statistical analysis comparing Field Burst Pressure values and ILI Burst pressure values of features on excavated sections of a pipeline pursuant to this Paragraph 40, Enbridge must complete a statistical analysis that compares field measurements of feature depth and ILI-reported feature depth on such excavated pipeline sections for the determination that is required by this Paragraph 40. Except as provided in Subparagraph 40.a, above, if field measurements of feature depth exceed ILI-reported feature depth values by more than one tool tolerance, Enbridge shall quantify the magnitude of any ILI tool depth bias. Not more than five (5) Days after determining the magnitude of any ILI tool depth bias, Enbridge shall add the ILI tool bias to the ILI-reported depth of all unrepaired features, and complete revised Predicted Burst Pressure calculations and Remaining Life calculations in accordance with Subsections VII.D.(IV) and VII.D.(VI), below, and determine whether any additional features qualify as Features Requiring Excavation when the revised feature depth values are taken into account. Upon determining that any feature is a Feature Requiring Excavation, Enbridge shall add such feature to the Dig List immediately, but in no event longer than 5 Days after the determination required by this Paragraph 40. For each ILI investigation, Enbridge shall maintain electronic records relating to ILI data, including, but not limited to: (1) identification of the ILI tool used for each inspection, the types of features the ILI tool is being used to detect, characterize, and size, and the basis for Enbridge’s determination that the ILI tool used is the most appropriate tool for accurately detecting, characterizing and sizing such features; (2) any notification from the ILI vendor that an 43 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1348 Page 48 of 225 ILI could not be completed or was invalid; (3) information relating to any Priority Features, including the date the vendor notified Enbridge of the feature, the date Enbridge confirmed the feature, if applicable, and excavation/repair date of each such feature; (4) information identifying the ILI vendor and tool; (5) in the case of corrosion tools, Enbridge’s determinations whether the tool is capable of detecting Axial Slotting and seam weld anomaly A/B features; (6) the date on which the ILI tool was removed from the pipeline at the conclusion of the ILI; (7) the date Enbridge received the Initial ILI Report from the vendor; (8) the date on which Enbridge completed its preliminary review of the Initial ILI Report; (9) a description of each data quality concern identified by Enbridge in its preliminary review of the Initial ILI Report, and the pipeline section(s) affected by each such identified data quality concern; (10) the date or dates on which Enbridge resolved each identified data quality concern, and a description of how the concern was resolved; (11) the date or dates on which each feature was classified as a Feature Requiring Excavation or non-injurious feature; (12) the date that each Feature Requiring Excavation was added to the Dig List; (13) the date that each Feature Requiring Excavation was scheduled for excavation and repair or mitigation; and (14) the date each Feature Requiring Excavation was actually excavated and repaired. Notwithstanding any corporate record retention policy, Enbridge shall maintain such records until five years after termination of the Consent Decree, and Enbridge shall make such records available to the United States upon request. (IV) Predicted Burst Pressure/Fitness for Service Except as provided below in this Paragraph 42, Enbridge shall calculate the Predicted Burst Pressure of all Crack features and Corrosion features identified by ILI tools, in accordance with the requirements of this Subsection VII.D.(IV). Enbridge shall not be required to calculate the Predicted Burst Pressure of: 44 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1349 Page 49 of 225 any feature that Enbridge verifies was previously excavated and mitigated by installation of a sleeve around the section of pipe where the feature is located; any feature that Enbridge verifies was mitigated by grinding or blasting and recoating, provided that the feature dimensions reported by the ILI, factoring in the ILI tool tolerance, are no larger than the dimensions of the mitigated feature at the time mitigation was performed; any Crack feature for which the ILI tool reported a saturated signal; provided, however, that all such Crack features shall be excavated and repaired or mitigated in accordance with the dig selection criteria for “Crack feature with a Saturated Signal” in Subsection VII.D.(V); or Crack or Corrosion features within dents. For purposes of the Consent Decree, the Predicted Burst Pressure of a feature refers to the lowest pressure in the pipeline at the location of the feature that would be predicted to result in failure of the feature. Enbridge shall calculate the Predicted Burst Pressure of features in accordance with the inputs and procedures in Appendix B. Following each ILI to assess any pipeline for Crack features or Corrosion features, Enbridge shall complete initial Predicted Burst Pressure calculations and initial Remaining Life calculations for all Crack or Corrosion features, as applicable (except as provided in Paragraph 42) as expeditiously as practicable after completing data quality review of the feature and/or pipeline section where the feature is located, in accordance with Subsection VII.D.(II), above, but in no event later than: In the case of any Priority Feature, two Days after receiving the Priority Feature notification referred to in Paragraph 33 above, and 45 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1350 Page 50 of 225 In the case of all other features, the earlier of: (1) 8 weeks after completing data quality review with respect to the feature and/or pipeline section where the feature is located, and (2) 175 Days after the ILI tool was removed from the pipeline at the conclusion of the ILI. Notwithstanding any corporate record retention policy, Enbridge shall maintain electronic records documenting all Predicted Burst Pressure calculations, and all Remaining Life calculations, including inputs and the dates on which such calculations were completed with respect to particular features, until five years after termination of the Consent Decree. Enbridge shall make such records available to the United States upon request. (V) Dig Selection Criteria Enbridge shall excavate and repair or mitigate all features that meet dig selection criteria set forth below in this Subsection VII.D.(V). During each excavation required pursuant to this Subsection VII.D.(V), Enbridge shall: (i) inspect all excavated portions of the pipeline and collect field measurements of features on excavated portions of the pipeline, as provided in Paragraph 39; (ii) determine, based on an analysis of field measurement values of feature length and depth and any other relevant field observations, whether such excavated portions of the pipeline contain any additional features, not previously identified on the Dig List, that satisfy one or more of the dig selection criteria identified in this Subsection VII.D.(V); and (iii) repair or mitigate all such additional features in accordance with this Subsection VII.D.(V). Except as provided below in this Subparagraph or in Subparagraphs 46.c g, Enbridge shall complete the excavation, repair and mitigation of all Features Requiring Excavation in accordance with the timeframes specified in Tables 1 through 5, or other timeframe 46 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1351 Page 51 of 225 authorized pursuant to Paragraph 49, below. In the case of any features that are determined to meet dig selection criteria in this Subsection VII.D.(V) based on an analysis of field measurement values for feature length and depth or other field observations, rather than being placed on the Dig List based on an analysis of ILI-reported values for feature length and depth, Enbridge shall repair or mitigate such features at the time of the excavation. Except as provided below in Subparagraphs 46.c – g, pending completion of the excavation and repair or mitigation of Features Requiring Excavation, Enbridge shall establish and maintain interim pressure restrictions at the location of such features, in accordance with and to the extent provided below in this Subsection VII.D.(V). In lieu of the timetables below in this Subsection VII.D.(V) for excavation and repair or mitigation of Features Requiring Excavation, Enbridge may, subject to the limitations set forth in Subparagraphs 46.e and f, below, and subject to EPA disapproval as provided in Subparagraph 46.m, below, adopt and implement an alternate plan and timetable for excavation and repair or mitigation of specified Features Requiring Excavation (“Alternate Plan”) as specified below in this Paragraph 46 if the requirements set forth in either Subparagraph 46.c.(1) or (2) are satisfied. Enbridge demonstrates that compliance with the applicable timetables below in this Subsection VII.D.(V) for repair or mitigation of the specified features is not practicable due to the extraordinary scope or complexity of the required excavation and repair or mitigation of the specified features. For purposes of this subparagraph, the cost of an excavation and repair or mitigation shall not be sufficient by itself to establish the scope or complexity of a required excavation or the practicability of the applicable timetables in this Subsection VII.D.(V). 47 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1352 Page 52 of 225 Enbridge proposes to replace a section of pipeline, rather than repairing all identified Features Requiring Excavation in that section of pipeline, and it is not practicable to complete replacement of such pipeline section in accordance with the applicable timetables in this Subsection VII.D.(V). Whenever Enbridge determines that compliance with the circumstances described in Paragraph 46.c.(1) or (2) are present, Enbridge shall, subject to EPA disapproval in accordance with Subparagraph 46.m below, develop and implement an Alternate Plan for excavation and repair or mitigation of such feature, that satisfies the requirements set forth below in this Paragraph 46. An Alternate Plan may include provisions for excavation and repair of more than one Feature Requiring Excavation, subject to the limitations in Subparagraph 46.e. Each such Alternate Plan shall (i) include a timetable for completing, as expeditiously as practicable, excavation and repair or mitigation of each Feature Requiring Excavation covered by the Plan, and (ii) identify all interim measures, including interim pressure restrictions, that are included in the Alternate Plan in order to assure and maintain compliance with the requirements of Subparagraph 46.g.(1). In lieu of one or more requirements below in this Subsection VII.D.(V) relating to the establishment of interim pressure restrictions for particular Features Requiring Excavation, Enbridge may, subject to the limitations set forth in Subparagraphs 46.e. and f, below, and subject to EPA disapproval as provided in Subparagraph 46.m, below, adopt and implement alternate interim pressure restriction requirements for specified Features Requiring Excavation in accordance with Subparagraph 46.g, below, if Enbridge demonstrates that (i) compliance with the interim pressure restriction provisions below in Subsection VII.D.(V) 48 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1353 Page 53 of 225 applicable to the specified features would significantly impair operability of the pipeline pending completion of the repair or mitigation of the specified features, or (ii) that compliance with the interim pressure restrictions below in this Subsection VII.D.(V), will result in significant adverse effects on pipeline integrity in the period prior to mitigation or repair of the feature. During the life of the Consent Decree, Enbridge may not submit more than a total of forty proposals that include either Alternate Plans as provided for in Paragraph 46.c or alternate interim pressure restrictions as provided in Paragraph 46.d , and such proposals may not cover more than a cumulative total of 200 excavations of Joints with Features Requiring Excavation. A single excavation may include two or more contiguous Joints, provided that the maximum number of contiguous Joints in an excavation does not exceed 10. Notwithstanding any other provision of this Paragraph 46, Enbridge may not adopt and implement an Alternate Plan as provided for in Subparagraph 46.c or an alternate pressure restriction as provided for in Subparagraph 46.d for any saturated signal Crack feature that presents a rupture threat. For purposes of this Subparagraph, a feature shall be deemed to present a rupture threat if the ILI-measured length of the feature is equal to or longer than the leak-rupture boundary as determined in accordance PR-218-05404. For purposes of this Consent Decree, the leak-rupture boundary shall be two times the value of the variable “c” as determined in equation numbers 9 and 10 at p. 25 of PR-218-05404 (May 2011). Subject to Subparagraph 46.c, Enbridge may adopt an Alternate Plan governing excavation and mitigation or repair of features, as provided in Subparagraph 46.c, or alternate pressure restriction requirements and timetables as provided in Subparagraph 46.d, for specified features if: 49 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1354 Page 54 of 225 Enbridge completes an Engineering Assessment (“EA”), using best engineering practices and principles, that demonstrates that the Alternate Plan or alternate pressure restriction requirements adopted by Enbridge will achieve a level of safety for all Features Requiring Excavation covered by the Alternate Plan or by the alternate pressure restriction requirements that is greater than or equal to the level of safety achieved through compliance with the requirements of this Subsection VII.D.(V) applicable to such feature or features; and Within 10 Days after completing the EA and at least 10 Days prior to any deadline for excavation, and repair or mitigation of such feature or features under applicable provisions of this Subsection VII.D.(V), Enbridge provides EPA with a written notification that: a) describes, in the case of an Alternate Plan as provided for in Subparagraph 46.c, (i) the measures that Enbridge proposes to implement for a specified feature or set of features, including any interim pressure restrictions or other interim measures that will be implemented until excavation and repair or mitigation of features is completed, and (ii) the timelines for implementing all such measures and completing the excavation, and repair or mitigation of such features as expeditiously as practicable; and b) describes, in the case of any alternative interim pressure restriction as provided in Subparagraph 46.d, the alternate interim pressure restriction as well as the timeline for implementing such alternate interim pressure restriction as expeditiously as practicable, 50 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1355 Page 55 of 225 c) explains how the Alternate Plan or alternate interim pressure restriction adopted by Enbridge meet all applicable requirements and conditions in Subparagraphs 46.c - f above, and d) includes a copy of the EA, signed by a registered professional engineer who certifies that the EA is accurate and consistent with the requirements of this Paragraph. Any Alternate Plan provided for in Subparagraph 46.c may include, as one element of the Plan, establishment of a temporary pressure restriction pending excavation and repair or mitigation of the feature or features covered by the Plan. For purposes of this Consent Decree, pressure restrictions or other interim measures prior to excavation shall not constitute repair or mitigation of a feature. Nothing in this Subparagraph shall be construed to allow Enbridge to adopt and implement any Alternate Plan or alternate interim that does not comply with all applicable laws and regulations. Unless Enbridge receives a notification in accordance with Subparagraph 46.m that EPA has disapproved an Alternate Plan provided for in Subparagraph 46.c. or an alternate interim pressure restriction and timetable provided for in Subparagraph 46.d, Enbridge shall implement each proposed Alternate Plan and each proposed alternate interim pressure restriction and timetable in accordance with the timetable for implementation of such Alternate Plan or alternate interim pressure restriction as set forth in the applicable notification submitted pursuant to Paragraph 46.g.(2). In each instance for which Enbridge proposes or implements an Alternate Plan as provided for in Subparagraph 46.c or an alternate interim pressure restriction as provided 51 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1356 Page 56 of 225 for in Subparagraph 46.d, Enbridge shall maintain all documentation relating to the selection and implementation of the Alternate Plan or alternate interim pressure restriction, and Enbridge shall make such documents available to EPA upon request, consistent with the requirements of Section X (Information Collection and Retention). In each Semi-Annual Report required pursuant to Paragraph 143, below, Enbridge shall include, for each Lakehead System Pipeline, a complete description of all instances during the reporting period in which Enbridge adopted and/or implemented an Alternate Plan as provided for in Subparagraph 46.c or an alternate interim pressure restriction as provided for in Subparagraph 46.d. For each such instance, the description shall provide all of the following information: (i) a detailed description of each Alternate Plan and each alternate interim pressure restriction adopted and/or implemented by Enbridge during the reporting period, including a description of the number of Features Requiring Excavation covered by each Alternate Plan and each alternate interim pressure restriction, and a description of the timetables for implementing each Alternate Plan or alternate interim pressure restriction; (ii) an explanation of how the conditions in Subparagraphs 46.c – f. are satisfied with respect to each such Alternate Plan and each alternate interim pressure restriction; (iii) a discussion of the basis for selecting each such Alternate Plan and each such alternate interim pressure restriction, including the basis for all alternate timetables established by Enbridge, and a description of relevant supporting information; (iv) documentation of the date Enbridge completed the EA and the date Enbridge provided the notification referred to in Subparagraph 46.g.(2); (v) a detailed description of the analysis comparing the level of safety achieved by each such Alternate Plan and/or the alternate interim pressure restriction with the level of safety that would be achieved through compliance with the requirements of Subsection VII.D.(V); (vi) a description of activities undertaken by 52 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1357 Page 57 of 225 Enbridge during the reporting period to implement each such Alternate Plan and each such alternate interim pressure restrictions, and (vii) the dates on which Enbridge completed implementation of any component of each such Alternate Plan and each such alternate interim pressure restriction during the reporting period. To the extent that any Alternate Plan as provided in Subparagraph 46.c or any alternate interim pressure restriction as provided in Subparagraph 46.d is not fully implemented during the reporting period covered by a SemiAnnual Report, Enbridge shall describe additional implementation activities and update the status of its implementation of the established timetables for such Alternate Plan and the timetables for implementation of any such alternate interim pressure restrictions in subsequent Semi-Annual Reports. If EPA determines that any Alternate Plan as provided for in Subparagraph 46.c or any alternate interim pressure restriction as provided for under Subparagraph 46.d, (i) does not achieve a level of safety equal to or greater than the level of safety achieved for such feature through application of the requirements of Section VII.D.(V), or (ii) does not satisfy any condition or requirement in Subparagraphs 46.c - f, EPA shall notify Enbridge in writing of its disapproval of the Alternate Plan or alternate interim pressure restriction adopted by Enbridge. Following any such written disapproval of an Alternate Plan under Subparagraph 46.c for excavation and mitigation or repair of one or more Features Requiring Excavation, Enbridge shall complete the excavation and repair or mitigation of each feature covered by such Alternate Plan within 30 Days after receipt of notification of the disapproval of the Alternate Plan, or by the applicable deadline as originally established below in this Subsection VII.D.(V) for excavation and repair or mitigation of each such feature, whichever is later. Following any disapproval of any alternate pressure restriction under Subparagraph 46.d 53 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1358 Page 58 of 225 with respect to any Feature Requiring Excavation, Enbridge shall limit the operating pressure at the location of each such feature so that the pressure at each such location does not exceed the level authorized in this Subsection VII.D.(V), unless the feature has already been excavated and mitigated or repaired in accordance with this Subsection VII.D.(V) at that point. Dig-Selection Criteria and Pressure Restriction Requirements for Crack Features: Enbridge shall excavate and repair or mitigate each Crack feature that meets one (or more) of the Dig Selection Criteria set forth in Table 1, in accordance with the timeframes specified in column 2 of Table 1. Enbridge shall also establish pressure restrictions for such Crack features consistent with applicable requirements and timeframes specified in column 3 of Table 1. The requirements set forth in Table 1 are applicable to Crack features in all sections of pipelines, regardless of whether the feature is located in an High Consequence Area or not. Enbridge shall also excavate and repair or mitigate Crack features that intersect or interact with Corrosion features or Geometric features, and establish appropriate pressure restrictions for such interacting features, as provided in Table 5 and Paragraph 59, below. A Crack feature may satisfy more than one dig selection criterion in Table 1 or Table 5. In such a case, Enbridge shall repair or mitigate the feature in accordance with the shortest deadline established under any applicable dig selection criteria. In any case where such a feature is subject to more than one pressure restriction under this Subsection VII.D.(V), Enbridge shall establish the pressure restriction that results in the lowest operating pressure at the location of the feature. 54 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1359 Page 59 of 225 Table 1 – Criteria and Timelines Governing Excavation, Repair and Imposition of Pressure Restrictions for Crack Features Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated Pressure Restriction – Maximum allowable pressure at location of feature until feature is repaired/mitigated As expeditiously as practicable but not to exceed 30 Days No later than 2 Days after determination that feature meets dig selection criteria, operating pressure at the location of the feature shall be limited to 80% of the highest actual operating pressure at that location during the last 60 Days. As expeditiously as practicable, but not to exceed 30 Days No later than 2 Days after determination that feature meets dig selection criteria, operating pressure at the location of the feature shall be limited to the Predicted Burst Pressure ÷ 1.25 or the highest actual operating pressure at that location over the last 60 Days, whichever is lower As expeditiously as practicable, but not to exceed 30 Days No later than 2 Days after determination that feature meets dig selection criteria, operating pressure at the location of the feature shall be limited to the Predicted Burst Pressure ÷ 1.25 or the highest actual operating pressure at that location over the last 60 Days, whichever is lower Crack feature with a saturated signal Crack feature with a Predicted Burst Pressure that is less than the Established Maximum Operating pressure (“MOP”) Any Crack feature with a depth greater than 70% of the wall thickness and Predicted Burst Pressure that is less than the established MOP 55 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1360 Page 60 of 225 Table 1 – Criteria and Timelines Governing Excavation, Repair and Imposition of Pressure Restrictions for Crack Features Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated Pressure Restriction – Maximum allowable pressure at location of feature until feature is repaired/mitigated Not to exceed 180 Days except as provided below in Paragraph 49 No later than 2 Days after determination that feature meets dig selection criteria, operating pressure at the location of the feature shall be limited to the Predicted Burst Pressure ÷ 1.25 Any Crack feature with a Remaining Life (determined in accordance with Subsection VII.D.(VI), below) that is less than 5 years (i.e., a feature that is predicted to grow, within five years (or less), to a point where its Predicted Burst Pressure will be less than the established MOP). 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days N/A Any Crack feature with a Remaining Life that is less than 2 x the planned re-inspection interval. 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days N/A Dig Selection Criteria Any Crack feature with a Predicted Burst Pressure that is less than 1.25 x the established MOP a. If Enbridge concludes and documents that it is not practicable to complete the excavation and repair or mitigation of any Feature Requiring Excavation on any Lakehead System Pipeline within any 180 Day period specified in Table 1 through 5 of this Subsection 56 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1361 Page 61 of 225 VII.D.(V), due to seasonal considerations or unusual circumstances, Enbridge may, subject to the requirements specified below in this Paragraph, complete the excavation and repair of such Features Requiring Excavation as expeditiously as practicable after the applicable 180-Day time period, but not to exceed 365 Days from the date the feature was placed on the Dig List. For purposes of this Paragraph, seasonal considerations or unusual circumstances may include: situations in which excavations during winter months will substantially reduce potential adverse impacts of the excavation on wetland ecosystems and the risk that the identified feature will result in a leak or rupture is low; situations in which excavations during periods of low flow conditions will substantially reduce adverse impact on riverine or floodplain ecosystems and the risk that the identified feature will result in a leak or rupture is low; or situations involving excavations near known populations of Threatened or Endangered Species where a delay in the excavation will reduce adverse impacts on the identified species and the risk that the identified feature will result in a leak or a rupture is low. For purposes of this Paragraph, neither the number of required excavations, nor the costs of any required excavation, nor the availability of staff, contractors or equipment, nor the ability to obtain a permit or authorization, shall be considered unusual circumstances that establish the impracticability of completing excavation and repair of features within a 180 Day time period. For each instance in which Enbridge asserts that an excavation is subject to an extended deadline pursuant to the provisions of this Paragraph 49, Enbridge shall include in the next Semi-Annual Report required pursuant to Paragraph 143: (1) a detailed description of the seasonal consideration or unusual circumstances that supports extension of the excavation deadline; (2) an explanation of the specific reasons why the seasonal considerations or unusual 57 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1362 Page 62 of 225 circumstances caused such a delay; and (3) a schedule for completing the excavation within 365 Days from the date the Feature Requiring Excavation was placed on the Dig List. If it is not practicable, as described in this Paragraph, to meet an applicable 180 Day deadline in Tables 1 through 5, above, for excavating and repairing or mitigating any Feature Requiring Excavation, Enbridge shall, prior to expiration of the 180-Day period, establish and/or maintain appropriate pressure restrictions limiting the maximum operating pressure at the location of each such feature, as provided below in this Paragraph 49. The maximum operating pressure at the location of each such feature shall not exceed the following: In the case of any feature for which a pressure restriction was previously required pursuant to this Subsection VII.D.(V), Enbridge shall limit the maximum allowable operating pressure at the location of the feature as follows: a) In the case of Geometric Features listed in Table 4 or 5, Enbridge shall reduce the maximum allowable operating pressure at the location of the feature by an additional 5% below the previously established operating pressure restriction; b) In the case of Crack Features, Enbridge shall recalculate the Predicted Burst Pressure of each feature, taking into consideration the predicted growth of the feature (in terms of both length and depth) between the time of the ILI and the end of the prescribed 180-Day period for repair or mitigation of such feature, and if the recalculated Predicted Burst Pressure of any feature is less than 1.25 x the Established MOP at the location of the feature, Enbridge shall limit the maximum allowable operating pressure at the location of the feature to the recalculated Burst Pressure divided by 1.25. 58 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1363 Page 63 of 225 c) In the case of Corrosion Features, Enbridge shall recalculate the Predicted Burst Pressure of each feature, taking into consideration the predicted growth of the feature (in terms of both length and depth) between the time of the ILI and the end of the prescribed 180-Day period for repair or mitigation of such feature, and if the recalculated Predicted Burst Pressure of any feature is less than 1.39 x the Established MOP at the location of the feature, Enbridge shall limit the maximum allowable operating pressure at the location of the feature to the recalculated Burst Pressure divided by 1.39. In the case of any Crack Feature or Corrosion Feature for which a pressure restriction was not required under this Subsection VII.D.(V), Enbridge shall limit the operating pressure at the location of the feature to the predicted burst pressure of the feature divided by 1.39. Enbridge shall maintain any pressure restriction referred to in Subparagraph 49.c until excavation and repair or mitigation of the feature has been completed. In each Semi-Annual Report required pursuant to Section IX (Reporting Requirements) of this Consent Decree, Enbridge shall identify all instances in which it was not practicable to complete excavation and mitigation or repair of Features Requiring Excavation on any Lakehead System Pipeline in accordance with a 180-Day timeframe established in Tables 1 through 5 of this Subsection VII.D.(V), the reason it was impracticable to meet the deadline, and the date when excavation and repair was completed or will be completed. Dig-Selection Criteria for Corrosion Features: Enbridge shall excavate and repair or mitigate each Corrosion feature that meets one (or more) of the Dig Selection Criteria set forth 59 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1364 Page 64 of 225 in the Table 2, below, and establish pressure restrictions for identified Corrosion features as provided in Paragraph 52. In the case of Corrosion features located in any HCA, Enbridge shall complete the excavation and repair or mitigation in accordance with the timeframes specified in column 2 of Table 2. In the case of Corrosion features that are not located within an HCA, Enbridge shall complete the excavation and repair or mitigation of the feature in accordance with the timeframe specified in column 3 of Table 2. Enbridge shall also excavate and repair or mitigate Corrosion features that intersect or interact with Crack features, dents, or other Geometric features and establish pressure restrictions for such interacting features, as provided in Table 5 and Paragraph 59 below. A Corrosion feature may satisfy more than one dig selection criterion. In such a case, Enbridge shall repair or mitigate the feature in accordance with the shortest deadline established under any applicable dig selection criteria. In any case where such a feature is subject to more than one pressure restriction under this Subsection VII.D.(V), Enbridge shall establish the pressure restriction that results in the lowest operating pressure at the location of the feature. Table 2 – Criteria and Timelines Governing Excavation and Repair of Corrosion Features Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCA Any Corrosion feature with a depth greater than 80% of the wall thickness of the joint where the feature is located. Wall thickness shall be determined in accordance with Appendix B, Paragraph 4. As expeditiously as practicable, but not to exceed 30 Days 60 Non-HCA As expeditiously as practicable, but not to exceed 30 Days Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1365 Page 65 of 225 Table 2 – Criteria and Timelines Governing Excavation and Repair of Corrosion Features Dig Selection Criteria Any Corrosion feature with a Predicted Burst Pressure is less than the established MOP Any Corrosion feature with a Predicted Burst Pressure that is less than 1.39 times the established maximum operating pressure With respect to any Lakehead System Pipeline other than those portions of Original US Line 3 that are located outside an HCA, any Corrosion feature with a depth greater than 50% wall thickness but less than 80% of wall thickness. Wall thickness shall be determined in accordance with Appendix B, Paragraph 4. Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCA As expeditiously as practicable, but not to exceed 30 Days Not to exceed 180 Days except as provided in Paragraph 49 Non-HCA As expeditiously as practicable, but not to exceed 30 Days 365 Days Not to exceed 180 Days except as provided in Paragraph 49 365 Days N/A With respect to those portions of Original US Line 3 that are located outside an HCA, any Corrosion feature with a depth greater than 65% wall thickness but less than 80% of wall thickness. Wall thickness shall be determined in accordance with Appendix B, Paragraph 4. 61 365 Days Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1366 Page 66 of 225 Table 2 – Criteria and Timelines Governing Excavation and Repair of Corrosion Features Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCA Non-HCA Any Corrosion feature with a Remaining Life (determined in accordance with Subsection VII.D.(VI), below) that is less than 5 years (i.e., a feature that is predicted to grow, within five years (or less), to a point where its Predicted Burst Pressure will be less than the Established MOP); provided that this dig selection criterion shall not apply to Original U.S. Line 3, which is subject to annual ILIs 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Any Corrosion feature with a Remaining Life that is less than 2 times the planned re-inspection interval. 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Enbridge shall establish pressure restrictions for Corrosion features identified in Table 2, as provided below in this Paragraph, and Enbridge shall maintain such pressure restrictions until such time as the feature has been excavated and repaired. Within 2 Days after determining that any Corrosion feature has a depth greater than 80% of the wall thickness of the joint where the feature is located, Enbridge shall 62 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1367 Page 67 of 225 limit the operating pressure at the location of such feature to not more than 80% of the highest actual operating pressure at that location during the last 60 Days. Within 2 Days after determining that any feature has a Rupture Pressure Ratio (“RPR”) less than 1.00 or a Predicted Burst Pressure that is less than 1.39 times the Established MOP, Enbridge shall limit operating pressure at the location of the feature to the Predicted Burst Pressure divided by 1.39. Dig-Selection Criteria for Axial Slotting, Axial Grooving, Selective Seam Corrosion and Seam Weld Anomaly A/B features. Prior to running each ILI, Enbridge shall determine whether the ILI tool design is adequate for assessing Axial Corrosion features, including Axial Slotting, Axial Grooving and Selective Seam Corrosion, and Crack features identified in the ILI report as Seam Weld Anomaly A/B features. In the case of ILI inspections performed using Circumferential Magnetic Flux Leakage or any other ILI tool determined to be adequate in accordance with the preceding Subparagraph 53.a, Enbridge shall excavate and repair or mitigate features that meet the dig selection criteria in Table 3, below, and establish pressure restrictions for such features as provided in Paragraph 54. In the case of features located within an HCA, Enbridge shall complete the excavation and repair or mitigation of features in accordance within the applicable timeframe specified in column 2 of Table 3. In the case of features not located within an HCA, Enbridge shall complete the excavation and repair or mitigation of features in accordance with the applicable timeframe in column 3 of Table 3. Enbridge shall also excavate and repair or mitigate Axial Slotting, Axial 63 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1368 Page 68 of 225 Grooving, Selective Seam Corrosion features and Seam Weld anomaly A/B features that intersect or interact with Crack features, dents, or other Geometric features and establish pressure restrictions for such interacting features, if applicable, as provided in Table 5, and Paragraph 59, below. Table 3 – Criteria and Timelines Governing Excavation and Repair of Axial Slotting, Axial Grooving, Selective Seam Corrosion and Seam Weld A/B Anomalies Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCA Non-HCA Any corrosion morphology associated with Axial Slotting, Axial Grooving or Selective seam Corrosion of or along a longitudinal seam weld, including any such features in the heat affected zone Not to exceed 180 Days except as provided in Paragraph 49 365 Days Any Axial Slotting feature located on the pipe body where the Predicted Burst Pressure of the feature is less than or equal to 1.25 x the established MOP Not to exceed 180 Days except as provided in Paragraph 49 365 Days Seam Weld Anomaly A/B where the Predicted Burst Pressure of the feature is less than or equal to 1.25 x the established MOP. (This criterion applies to features that have characteristics of Crack-like features but are detected by CMFL tools or other tools capable of detecting axial corrosion) Not to exceed 180 Days except as provided below in Paragraph 49 365 Days 64 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1369 Page 69 of 225 Table 3 – Criteria and Timelines Governing Excavation and Repair of Axial Slotting, Axial Grooving, Selective Seam Corrosion and Seam Weld A/B Anomalies Dig Selection Criteria Any Axial Slotting or seam weld anomaly A/B feature with a Remaining Life (determined in accordance with Subsection VII.D.(VI), below) that is less than 5 years (i.e., a feature that is predicted to grow, within five years (or less), to a point where its Predicted Burst Pressure will be less than the established MOP). Any Axial Slotting or seam weld anomaly A/B feature with a Remaining Life that is less than 2 x the planned reinspection interval. Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCA Non-HCA 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/ mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Enbridge shall establish pressure restrictions for features identified in Table 3, as provided below in this Paragraph, and Enbridge shall maintain such pressure restrictions until such time as the feature has been excavated and repaired. Within 2 Days after determining that any feature described in Table 3 has a Rupture Pressure Ratio (“RPR”) less than 1.00 or a Predicted Burst Pressure that is less than 1.25 times the Established MOP, Enbridge shall limit 65 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1370 Page 70 of 225 operating pressure at the location of the feature to not more than 80% of the Predicted Burst Pressure. Dig-Selection Criteria for Dents and Other Geometric Features. Enbridge shall excavate and repair or mitigate each dent and other Geometric feature that meets one (or more) of the Dig Selection Criteria set forth in Table 4, and establish pressure restrictions for identified Geometric features as provided in Paragraph 57. In the case of dents or other Geometric features located in any HCA, Enbridge shall complete the excavation and repair or mitigation in accordance with the timeframes specified in column 2 of Table 4. In the case of dents or other Geometric features that are not located within an HCA, Enbridge shall complete the excavation and repair or mitigation of the features in accordance with the timeframe specified in column 3 of Table 4. Enbridge shall also excavate and repair or mitigate dents or other Geometric features that intersect or interact with Crack features or Corrosion features, and establish appropriate pressure restrictions for such interacting features, as provided in Table 5 and Paragraph 59 below. A dent or other Geometric feature may satisfy more than one dig selection criterion. In such a case, Enbridge shall repair or mitigate the feature in accordance with the shortest deadline established under any applicable dig selection criteria. In any case where such a feature is subject to more than one pressure restriction under Subsection VII..D.(V), Enbridge shall establish the pressure restriction that results in the lowest operating pressure at the location of the feature. 66 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1371 Page 71 of 225 Table 4 – Criteria and Timelines for Excavation and Repair of Dents and Other Geometric Features Category Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCAs Non-HCAs A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth greater than 6% of the nominal diameter of the pipeline As expeditiously as practicable, not to exceed 30 Days As expeditiously as practicable, not to exceed 60 Days A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth that is greater than or equal to: a. 3% of the nominal diameter of the pipeline, in the case of a pipeline with a nominal diameter greater than or equal to 12 inches, OR Not to exceed 60 Days Not to exceed 180 Days, except as provided above in Paragraph 49 b. 0.250 inches in the case of any pipeline with a nominal diameter less than 12 inches. A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth that is greater than or equal to: a. 2% of the nominal diameter of the pipeline, in the case of a pipeline with a nominal diameter greater than or equal to 12 inches, OR Not to exceed 180 Days, except as provided in Paragraph 49 b. 0.250 inches in the case of any pipeline with a nominal diameter less than 12 inches. 67 365 Days Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1372 Page 72 of 225 Table 4 – Criteria and Timelines for Excavation and Repair of Dents and Other Geometric Features Category Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated HCAs Non-HCAs A dent on the bottom of the pipeline (below the 4 and 8 o’clock positions) with a depth that is greater than 6% of the nominal diameter of the pipeline. Not to exceed 180 Days, except as provided in Paragraph 49 With respect to any Lakehead System Pipeline other than those portions of Line 61 that are not in an HCA, any dent that affects pipe curvature at a girth weld or a longitudinal seam weld where the depth of the dent is greater than or equal to: a. 2% of the nominal diameter of the pipeline, provided that the diameter is equal to, or greater than, 12 inches, OR Not to exceed 180 Days, except as provided in Paragraph 49 Not to exceed 180 Days, except as provided in Paragraph 49 365 Days N/A 365 Days b. 0.250 inches for any pipeline with a nominal diameter less than 12 inches With respect to those portions of Line 61 that are located outside of an HCA, any dent that affects the pipe curvature at a girth weld or a longitudinal weld and is shown to have a remaining life that is less than 2 times the planned reinspection interval determined through a fatigue assessment using a Finite Element Analysis (FEA) approach utilizing the ABAQUS or ANSYS FEA models. 68 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1373 Page 73 of 225 Enbridge shall establish pressure restrictions for dents or other Geometric features identified in Table 4, as provided below in this Paragraph 57, and Enbridge shall maintain such pressure restriction until such time as the feature has been excavated and repaired. Within 2 Days after determining that any dent feature has a depth greater than 6% of nominal pipeline diameter (whether the dent is located on the top or bottom of the pipeline), Enbridge shall limit the operating pressure at the location of the feature to not more than 80% of the highest actual operating pressure at that location during the last 60 Days. After identifying any dent feature located on the top of the pipeline that has a depth that is greater than or equal to: 3 % of the nominal diameter of the pipeline, in the case of a pipeline with a nominal diameter greater than or equal to 12 inches, or 0.250 inches, in the case of any pipeline with a nominal diameter less than 12 inches, Enbridge shall limit the operating pressure at the location of the feature to not more than 80% of the highest actual operating pressure at that location during the last 60 Days if the feature is not repaired or mitigated within the applicable timeframe specified in Table 4. Dig-Selection Criteria for Interacting Features: Within 30 Days after receiving any Initial ILI Report, Enbridge shall review the integrated database required under Paragraph 74 for the purpose of determining whether any feature reported by the ILI tool intersects or interacts with a feature of a different feature type that was detected during a previous ILI Tool Run but not repaired or mitigated (e.g., a Crack feature in the same location as a previously reported corrosion or dent feature; a Corrosion feature in the same location as a previously reported dent). Enbridge shall excavate and repair all such intersecting/interacting features that meet the dig 69 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1374 Page 74 of 225 selection criteria set forth below, within the applicable timeframes identified in columns 2 and 3 of Table 5, and establish pressure restrictions as provided in Paragraph 59. Table 5 – Criteria and Timelines for Excavation and Repair of Intersecting or Interacting Feature Types Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated High Consequence Area (“HCA”) Any dent located in the top of the pipeline (above the 4 and 8 o’clock positions) that has any indication of metal loss, cracking, or a stress riser. Any dent located in the bottom of the pipeline (below the 4 and 8 o’clock positions) that has any indication of metal loss, cracking, or a stress riser. Any case in which a Crack feature intersects or interacts with a Corrosion feature and the Predicted Burst Pressure of such interacting or intersecting features determined using the CorLASTM model (assessed as a Crack-like feature) is less than 1.25 x the established maximum operating pressure. As expeditiously as practicable, but not to exceed 30 Days Not to exceed 60 Days Not to exceed 180 Days, except as provided in Paragraph 49 70 Non-HCA As expeditiously as practicable, but not to exceed 60 Days, for each dent deeper than 2% of the outer diameter of the pipeline; otherwise, excavate and repair within 365 Days 180 Days for a dent deeper than 2% of the outer diameter of the pipeline; otherwise, excavate and repair within 365 Days Not to exceed 180 Days except as provided in Paragraph 49 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1375 Page 75 of 225 Table 5 – Criteria and Timelines for Excavation and Repair of Intersecting or Interacting Feature Types Dig Selection Criteria Maximum time from date that feature is placed on the Dig List until date that feature is repaired/mitigated High Consequence Area (“HCA”) Any intersecting or interacting Crack/Corrosion feature with a Remaining Life (determined in accordance with Subsection VII.D.(VI), below) that is less than 5 years (i.e., a feature that is predicted to grow, within five years or less, to a point where its Predicted Burst Pressure will be less than the Established MOP). 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Any intersecting or interacting Crack/Corrosion feature with a Remaining 365 Days, except that if Life that is less than 2 x the planned rethe Remaining Life of the inspection interval. feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Non-HCA 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days 365 Days, except that if the Remaining Life of the feature is ≤ 365 Days from the time the feature was added to the Dig List, then repair/mitigation shall be as expeditiously as practicable, and in no event longer than 30 Days Enbridge shall establish a pressure restriction for each interacting or intersecting feature in Table 5, as provided below in this Paragraph 59, and Enbridge shall maintain each such pressure restriction until such time as the feature has been excavated and repaired. Within 2 Days after determining that any intersecting or interacting Crack/Corrosion feature has a Predicted Burst Pressure that is less than 1.25 times the Established 71 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1376 Page 76 of 225 MOP, Enbridge shall limit operating pressure at the location of the feature to not more than 80% of the Predicted Burst Pressure. Within 2 Days after determining that any dent has an indication of cracking, metal loss or a stress riser, Enbridge shall limit operating pressure at the location of such feature to not more 80% of the highest actual operating pressure at the location of the feature over the last 60 Days. (VI) Remaining Life Determinations/Re-inspection Intervals Following each ILI to evaluate Crack features and each ILI to evaluate Corrosion features on any pipeline, Enbridge shall determine the Remaining Life of each detected Crack and Corrosion feature that does not meet any of the dig selection criteria in Subsection VII.D.(V) (other than dig selection criteria based on Remaining Life of the feature), except as provided below in Paragraph 61. For purposes of this Consent Decree, the Remaining Life of any Crack or Corrosion feature refers to the time period required for the feature to grow to the point where the Predicted Burst Pressure of the feature is less than or equal to the Established MOP, as determined in accordance with this Subsection. Enbridge shall not be required to calculate the Remaining Life of: any feature described in Subparagraphs 42.a - d, any feature that is placed on the Dig List, provided that Enbridge completes excavation and repair or mitigation of the feature in accordance with the timeframes specified in this Subsection VII.D.(V), or any feature that is stable, i.e. has not grown since the last ILI, provided that the frequency and magnitude of pressure cycles in the pipeline segment where the feature is 72 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1377 Page 77 of 225 located are not significantly different than the frequency and magnitude of pressure cycles in such pipeline segment at the time of the prior ILI. Enbridge shall determine the Remaining Life of each Crack feature, using representative values of actual operating parameters of the pipeline or pipeline segment, as applicable, including the number and magnitude of pressure cycles. In determining the number and magnitude of pressure cycles, Enbridge shall utilize the worst cycling quarter between the most recent valid crack ILI run and the immediately prior valid crack ILI run. For purposes of this subparagraph, the worst cycling quarter shall reflect the worst combination of cycling frequency and cycling magnitude for the applicable line or line segment during the period between the successive ILI runs. If Enbridge increases the operating pressure limit in any segment of a Lakehead System pipeline after determining the Remaining Life of Crack features in accordance with this Paragraph, Enbridge shall recalculate the Remaining Life of the unrepaired Crack features remaining in such line segment. Enbridge shall calculate the Remaining Life of each Crack feature using either a fatigue crack growth model or an SCC crack growth model, whichever yields the fastest projected growth rate and the shortest Remaining Life. In order to determine the Remaining Life of Corrosion features, Enbridge shall calculate a corrosion growth rate (“CGR”) for each pipeline based on an evaluation of changes in Corrosion features detected in successive ILIs in the case of each pipeline that has had at least one previous ILI to detect Corrosion features. In the case of any new pipeline that has not previously had an ILI to detect Corrosion features, Enbridge shall use a historical CGR estimate, which shall not be less than .005 inch per year. 73 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1378 Page 78 of 225 For each pipeline, the maximum interval between successive ILIs to assess Crack features shall not exceed one-half of the shortest Remaining Life of any unrepaired Crack feature in the pipeline, calculated as provided above. For each pipeline, the maximum interval between successive ILIs to assess Corrosion features shall not exceed one-half of the shortest Remaining Life of any unrepaired Corrosion feature in the pipeline, calculated as provided above in this Subsection VII.D.(VI). Notwithstanding any other provisions in the Consent Decree, the maximum interval between successive ILIs for any particular feature type (Crack, Corrosion, or Geometric feature) on each pipeline in the Lakehead System shall not exceed 5 years, except as provided below in this Paragraph 66. Until Original US Line 3 is taken out of service and depressurized as provided in Paragraph 22.a, Enbridge shall complete ILIs for each feature type on an annual basis, except that Enbridge need not conduct ILIs during the final 12 months that Original US Line 3 is in operation. E. MEASURES TO PREVENT SPILLS IN THE STRAITS OF MACKINAC Applicability: The requirements set forth in this Subsection VII.E shall apply to the section of Lakehead System Line 5 oil transmission pipeline (“Line 5”) that crosses the Straits of Mackinac (“Straits”) between Michigan’s upper and lower peninsulas. Specifically, such requirements shall apply to the 4.09-mile portion of Line 5 consisting of two 20-inch diameter seamless pipelines that cross the Straits (“Dual Pipelines”). Span Management Program Enbridge shall operate and maintain the Dual Pipelines to ensure that currents or ice do not impair the integrity of either pipeline. Enbridge shall also assure that each of the Dual Pipelines is well-supported in areas where the pipeline is suspended above the lake 74 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1379 Page 79 of 225 bed (“spans”). Further, Enbridge shall operate and maintain the Dual Pipelines to reduce the risk of a vessel’s anchor puncturing, dragging or otherwise damaging the pipeline. Nothing in this Paragraph shall be construed to limit or affect any liability of Enbridge in the event of any unpermitted discharges from the Dual Pipelines. As of the Effective Date, Enbridge shall ensure that all sections of the Dual Pipelines located within 65-feet of water or less are continuously covered in a buried trench on the floor of the Straits. For uncovered portions of the pipelines in water deeper than 65 feet, Enbridge shall at all times support and anchor the pipelines with a series of screw-anchor pipe supports (“Screw Anchors”) that are placed so that the maximum distance between adjacent Screw Anchors shall not exceed 75 feet. Each Screw Anchor shall hold the pipelines in place by means of a steel saddle connected to two ten-foot-long steel screws, with each screw augured into the floor of the Straits on either side of the pipelines. Enbridge shall complete periodic visual inspections of each of the Dual Pipelines as provided below in this Paragraph to ensure compliance with the requirements of Subparagraphs 68.a and 68.b, above. Enbridge shall complete the initial underwater visual inspection of each of the Dual Pipelines no later than July 31, 2016. As part of the initial visual inspection of each of the Dual Pipelines, Enbridge shall complete a survey of biota, including but not limited to mussels, present on the Dual Pipelines. In the event that the underwater inspection reveals one or more areas where a pipeline is not adequately covered or supported, Enbridge shall undertake repairs to address such areas no later than 60 Days after the completion of the inspection. 75 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1380 Page 80 of 225 Within 60 Days of completing the repairs, Enbridge shall submit to EPA a report summarizing the findings of its inspection and any repair work done as a result of the inspection. After the initial visual underwater inspection pursuant to Paragraph 68.c, Enbridge shall complete periodic underwater visual inspections of each of the Dual Pipelines at intervals not to exceed 24 months, until termination of the Consent Decree. All such reinspections shall be completed by July 31 of the year in which the inspection is required. Following each such re-inspection of the Dual Pipelines, Enbridge shall complete any necessary repairs in accordance with Subparagraph 68.d and submit reports in accordance with Subparagraph 68.e. Biota Investigation Enbridge shall conduct an investigation to assess whether any of the biota found on the pipeline, including but not limited to mussels, impacts the integrity of the Dual Pipelines. Specifically, Enbridge shall assess whether the accumulation of mussels and other biota have impacted the integrity of the pipelines’ coating or the underlying metal, including areas where there are openings or “holidays” in the pipeline coating. The investigation shall evaluate whether the mussels and other biota are creating a corrosive environment by, among other things, fostering the growth of anaerobic sulfate-reducing bacteria (“SRB”) that may cause metal loss. Finally, the investigation should evaluate whether mussels and other biota are introducing features that may threaten the integrity of either of the Dual Pipelines due to the weight of such biomass or the pressure caused by current or ice movement around such biomass in areas where the pipelines are suspended above the floor of the Straits. 76 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1381 Page 81 of 225 No later than 60 Days after the initial visual underwater inspection referred to in Paragraph 68.c, Enbridge shall submit to EPA for approval a proposed plan for the investigation described in Subparagraph 69.a. The proposed plan shall identify the employees, consultants and contractors that will perform the investigation and describe the methods that they will use in inspecting, sampling, and evaluating whether biota have any adverse impact on pipeline coatings or on the Dual Pipelines. The proposed plan shall also propose a schedule for completing the investigation. Upon receipt of an EPA’s approval of its plan and schedule, Enbridge shall implement the plan in accordance with the schedule. No later than 60 Days after the completion of its investigation, Enbridge shall submit a final report to EPA for review and approval, describing the findings and results of the investigation. In the event that the investigation finds that zebra mussels and other biota have impaired, or threaten to impair, the Dual Pipelines, Enbridge shall supplement its final report with a proposed work plan to address such impairments, together with a proposed schedule for completing such work. Upon receipt of EPA approval of the work plan and schedule, Enbridge shall perform the work in accordance with the plan and schedule. Within 60 Days of completion of the work, Enbridge shall submit a final report documenting the work to EPA for review and comment. In-Line Inspections of the Dual Pipelines. The ILI schedule required pursuant to Paragraph 29 above, shall provide for Enbridge to complete valid ILIs of the Dual Pipelines in accordance with the following schedule: ILIs to detect, characterize, and size Corrosion Features and circumferential Crack Features on each of the Dual Pipelines completed no later than July 30, 2017. 77 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1382 Page 82 of 225 An ILI to detect, characterize, and size Geometric Features on each of the Dual Pipelines completed no later than one year following the Effective Date of the Consent Decree, or five years after the most recently completed inspection to detect and size Geometric Features on each of the Dual Pipelines, whichever is later. Investigation and Repair of axially-aligned features. Not later than December 31, 2017, Enbridge shall undertake and complete the actions in either Subparagraph 71.a or 71.b below to reduce or eliminate the potential that any axially-aligned Crack features in the Dual Pipelines will result in a leak or rupture: Enbridge shall conduct an investigation of the Dual Pipelines using an ILI tool that is most appropriate for detecting and sizing axially-aligned Crack features in the Dual Pipelines. In the event that the ILI tool identifies features that are Features Requiring Excavation, Enbridge shall complete the repair of such features on each of the Dual Pipelines as expeditiously as practicable. Such repair shall be completed in accordance with Subsection VII.D, above. In lieu of the actions set forth in the preceding subparagraph, Enbridge may elect to perform a hydrostatic pressure test of each of the Dual Pipelines. In the event that Enbridge selects this option, Enbridge shall comply with the procedures set forth in Section VII.C (Hydrostatic Pressure Testing) of this Consent Decree. Enbridge shall provide EPA with a copy of the test plan and procedure at least 90 Days before commencing the hydrostatic pressure test. Pipeline Movement Investigation Within 40 Days of identifying one or more cracks in the Dual Pipelines that qualify as a Feature Requiring Excavation, Enbridge shall submit to EPA for approval a proposed plan and schedule to investigate the cause of such cracking. The investigation shall 78 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1383 Page 83 of 225 include a non-destructive examination (“NDE”) of the pipeline to determine whether the cracking is associated with stress corrosion cracking or some other form of cracking. Further, the investigation shall consider and determine whether the cracking has been caused by the physical movement of the pipeline. Unless Enbridge can affirmatively rule out the possibility of pipeline movement, the proposed plan shall require the installation of instrumentation on the pipeline to detect and track movement of the pipeline over time. Upon receipt of the EPA’s approval of Enbridge’s plan and schedule, Enbridge shall conduct the investigation in accordance with the approved plan and schedule. Within 30 Days of completing the investigation, Enbridge shall submit to EPA, for review and approval, a final report with proposed findings and conclusions. The report shall identify corrective measures, if any, needed to repair or remediate the cause of the cracking and the schedule for completion. In the event that the cause of the cracking can be identified and corrected, Enbridge shall undertake and complete such corrective measures as expeditiously as practicable, but in no event later than 270 Days after the completion of the investigation. Quarterly Inspection Using Acoustic Leak Detection Tool: Within 90 Days of the Effective Date, Enbridge shall conduct an inspection of each Dual Pipeline using an acoustic ILI tool that is capable of detecting sounds associated with small leaks as the tool travels through the pipelines. After completing the initial investigation, Enbridge shall continually repeat the inspection once per calendar quarter for the duration of the Consent Decree. In the event that Enbridge should detect a leak, Enbridge shall immediately shut down and sectionalize the pipeline until the leak is repaired. 79 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1384 Page 84 of 225 F. DATA INTEGRATION As of the Effective Date, Enbridge shall operate and maintain a feature integration database (“OneSource”) for all pipelines in the Lakehead System. The OneSource shall integrate information about Crack features, Corrosion features, and Geometric features from multiple inline investigations of the pipelines and field measurement devices. Further, upon completion of the update required under Paragraph 77 below, the OneSource shall integrate additional information about Crack features, Corrosion features, and Geometric features collected through field measurements. The OneSource shall enable pipeline integrity-management personnel to identify and track any changes to any feature detected by an ILI tool on successive investigations (“Tool Runs”) of the pipeline. In addition, the OneSource shall enable such personnel to identify and evaluate features detected by different types of ILI tools that may overlap or otherwise interact. Enbridge’s integrity management personnel, including but not limited to personnel responsible for identifying Features Requiring Excavation in accordance with Subsections VII.D (III) - (VI), shall be able to access and view the OneSource from their desktop computers and laptops, and such personnel shall be able to search for, and view, a schematic image of each Joint of each Lakehead System Pipeline. Each schematic image of a Joint shall show: Information about the construction of each Joint, including (1) the location of the long-seam, (2) the type of long-seam, (3) the location of the girth welds, (4) the type of Joint coating, (5) the diameter of the Joint, (6) the specified minimum yield strength (SMYS) of the Joint, (7) the pipe manufacturer, (8) the year of manufacture, (9) the wall-thickness of the Joint based upon the manufacturing specification, and (10) whether the joint is located within an HCA; 80 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1385 Page 85 of 225 Information about each ILI tool that Enbridge has used to investigate the Joint, including (1) the type of tool, (2) the supplier of the tool, and (3) the date of the Tool Run; Information about each feature detected by each ILI tool, including (1) the predicted length and location of each feature taking into account the uncertainty of the ILI tool, (2) the predicted depth of each feature taking into account the uncertainty of the ILI tool, (3) each feature’s type and classification, (4) the rupture pressure ratio and/or the Predicted Burst Pressure of the feature, and (5) any comments made by ILI vendor regarding such feature; and Other pertinent details, including (but not limited to) the average wall thickness of the Joint as determined by ultra-sonic wall measurement tools. With respect to each type of ILI Tool, the OneSource shall include at least two successive ILI data sets – one data set from the most recently completed ILI Tool Run and other data set from the second most-recently completed ILI Tool Run. Once a data set for a type of ILI Tool has been superseded by two successive ILI Tool Runs of that tool type, Enbridge may elect to delete the data set from the OneSource, although Enbridge shall continue to preserve the data in accordance with Section X (Information Collection and Retention) of the Consent Decree relating to document preservation requirements. Update of OneSource Database: Within 365 Days of the Effective Date, Enbridge shall complete an update of the OneSource to add and integrate information from inspections of pipelines in the Lakehead System using non-destructive examination (“NDE”) methodologies. This update shall be limited to Joints that have been excavated and inspected within the 3-year period prior to the entry of the Consent Decree. 81 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1386 Page 86 of 225 For all such Joints, the updated OneSource will enable Enbridge’s integrity management personnel, including but not limited to personnel responsible for identifying Features Requiring Excavation in accordance with Paragraph 35, to overlay and compare information collected from ILI tools with the information collected from NDEs conducted in the field. The latter information shall include: Information about all repairs to the Joint, including (a) the types of repairs, (b) the location of sleeve-type repairs, and (c) the depth and size of all grindingrelated repairs; and Information about all unrepaired Crack features, Corrosion features and Geometric features, irrespective of whether such features were detected by ILI tools or not, including (a) the size and location of each feature, (b) the depth of each feature, (c) each feature’s type and classification, (d) the field-determined rupture pressure ratio and/or Predicted Burst Pressure of the feature. The updated OneSource shall also include a hyperlink by which Enbridge personnel, including but not limited to personnel responsible for identifying Features Requiring Excavation in accordance with Paragraph 35, can readily access other electronic databases that contain information collected during the NDE, including photographs of features and field notes taken by NDE personnel. After completing the initial update of the OneSource, Enbridge shall continuously update the database with information collected from new NDE investigations. Enbridge shall add such information to the OneSource as expeditiously as practicable, but in no event shall Enbridge take more than 60 Days after completing all field investigations relating to 82 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1387 Page 87 of 225 an ILI Tool Run to update the OneSource to include all data collected from the field investigations. Mandatory Use of the Data Integration Database to Prepare Dig List. Upon completion of a new ILI Tool Run, Enbridge shall update the OneSource to include the new ILI data, provided such data has passed through the quality-control procedures and determined by Enbridge to be reliable. Enbridge shall add the data to the OneSource as quickly as possible, but in no event later than 29 Days after the Enbridge receives the Initial ILI report. Once new ILI data has been added to the OneSource, Enbridge shall review such data for the purpose of identifying any overlapping, or otherwise interacting, features that may qualify as Features Requiring Excavation within the meaning of Paragraph 35. Enbridge shall complete such review as soon as is practicable, but in no event later than 180 Days after the ILI tool is removed from the pipeline. G. LEAK DETECTION AND CONTROL ROOM OPERATIONS (I) Assessment of Alternative Leak Detection Technologies Within 120 Days of the Effective Date, Enbridge shall prepare and submit a report to EPA regarding the feasibility and performance of alternative leak detection technologies (“ALD Report”). The technologies discussed in the ALD Report shall include: Computational pipeline monitoring technologies that monitor the pressure wave created by different size leaks and ruptures; External leak detection technologies, including fiber- optic cable distributed temperature sensing systems, fiber-optic distributed acoustic sensing systems, vapor sensing tubes, electrochemical hydrocarbon sensing cables, and any and all other technologies assessed by 83 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1388 Page 88 of 225 Enbridge as of the Effective Date using the External Leak Detection Experimental Research (ELDER) test apparatus; and Aerial-based technologies, including (but not limited to) infrared camerabased systems, laser-based spectroscopy, flame ionization detection systems, and any and all other technologies assessed by Enbridge as of the Effective Date. With respect to each of the above technologies, the ALD Report shall describe all laboratory and field tests/evaluations that Enbridge has conducted within the past five years, as well as all laboratory and field investigations that Enbridge considered or relied upon as a basis for any conclusions in the ALD Report; summarize the findings of all such tests/evaluations; identify all reports that Enbridge has submitted to PHMSA under the Lakehead Plan regarding ALD technology and discuss developments since such submissions; and provide an assessment of the feasibility or limitations of the ALD technology in different settings or environments, including underwater pipeline segments. (II) Report on Feasibility of Installing External Leak Detection System at the Straits of Mackinac Within 180 Days of the Effective Date, Enbridge shall submit to EPA for review a report assessing the feasibility of installing an alternative leak detection system at the Straits of Mackinac. For the purposes of conducting this assessment, Enbridge shall evaluate the following leak detection technologies: fiber-optic cable (acoustic and temperature), vapor sensing tube, negative pressure wave, and hydrocarbon sensing cable. Such technologies would supplement Enbridge’s existing MBS Leak Detection System, as well as the leak detection systems that 84 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1389 Page 89 of 225 Enbridge is required to implement under Paragraph 73 (Acoustic Leak Detection Tool) and Paragraph 102 (Rupture Detection System) of the Consent Decree. With respect to each technology, the report required by Paragraph 81 shall evaluate (i) the potential effectiveness of the technology in detecting leaks and ruptures of different sizes, (ii) the practicability of deploying the technology in the Straits of Mackinac, (iii) the practicability of long-term operation and maintenance of the technology, and (iv) the net present cost of the technology, taking into account the initial capital cost to install the technology and the annual expense to operate and maintain the technology. The report required pursuant to Paragraph 81 shall compare the relative performance of each of the evaluated technologies with respect to each of the factors enumerated in Paragraph 82 and any other factors that Enbridge may decide to add to its analysis. As a basis for comparison, Enbridge shall also evaluate the risks and benefits of each technology in the Straits of Mackinac versus the risks and benefits of continuing to rely solely upon the MBS Leak Detection System and those systems that Enbridge is required to implement under this Consent Decree. (III) Requirements for New Lakehead Pipelines and Replacement Segments Applicability. The requirements set forth in this Subsection VII.G.(III) shall apply to any New Lakehead Pipeline or any Replacement Segment of any pipeline that is part of the Lakehead System. For the purposes of this Consent Decree, the terms “New Lakehead Pipeline” and “Replacement Segment” shall mean the following: The term “New Lakehead Pipeline” shall mean the pipeline that will replace Original US Line 3, as well as mean any new pipeline that will replace one of the other pipelines that comprise the Lakehead System. In the event that Enbridge resumes operation of 85 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1390 Page 90 of 225 any other Lakehead System Pipeline that may be replaced after the Effective Date, the term “New Lakehead Pipeline” shall also apply to such pipeline or pipelines. The term “Replacement Segment” shall mean any modification of a Lakehead System Pipeline after the Effective Date for the purpose of (1) adding one (or more) pump stations to the pipeline or (2) replacing a section of the pipeline with a volume capacity greater than 45,000 cubic meters (“m3”). Installation of flowmeters: Each New Lakehead Pipeline or Replacement Segment shall have a flowmeter at all locations where oil (a) enters into the pipeline, (b) leaves the pipeline, or (c) passes through a pump station. In addition, Enbridge shall install flowmeters at additional locations between pump stations as needed to comply with the requirements of Paragraphs 88 or 90 below. All flowmeters shall be designed and constructed to monitor flow under all conditions, including during Startup and Shutdown, and to provide continuous real-time data to Enbridge’s Supervisory Control and Data Acquisition System (“SCADA”) and MBS Leak Detection System, as well as to the Rupture Detection System required under Paragraph 102 of this Consent Decree. Installation of flowmeters on pipelines that utilize In-Line Batch Interface Tools: For any New Lakehead Pipeline or Replacement Segment where Enbridge will deploy In-Line Batch Interface Tools for the purpose of physically separating products in the pipeline, Enbridge shall design and operate all flowmeters so that they shall not be taken out of service as the result of an In-Line Batch Interface Tool moving past the location of the flowmeter. Installation of other Instrumentation: In addition to the flowmeters required under Paragraph 85, each New Lakehead Pipeline or Replacement Segment shall include instrumentation for measuring temperature and pressure as described in Subparagraphs 87.a and 86 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1391 Page 91 of 225 87.b below. All instruments for measuring temperature and pressure shall provide continuous real-time data to Enbridge’s SCADA, MBS Leak Detection System, and Rupture Detection System, including during Startup and Shutdown periods. Pressure Transducer/transmitter: Enbridge shall install a pressure transducer/transmitter at all of the following locations: each location where oil enters the pipeline; each location where oil leaves the pipeline for delivery purposes or for transfer to another pipeline; each location where a Column Separation would be expected to occur based on Enbridge’s hydraulic studies of the pipeline; each segment of pipeline between adjacent flowmeters, and each segment of pipeline between two remotely-controlled valves where oil may be “shut in” during a shutdown of the pipeline (“Valve Segment”). Temperature transducer/transmitters: Enbridge shall install a skin-based temperature transducer/transmitter at all of the following locations: each location where Enbridge shall install a flowmeter in accordance with Paragraph 85, and each Valve Segment. Establishment of MBS Segments: For the purposes of this Consent Decree, the term “MBS Segment” shall refer to each segment of a pipeline between two adjacent flowmeters. Enbridge shall design and construct each New Lakehead Pipeline and Replacement Segment to ensure that the volume of oil within each MBS Segment created by, or included within, the New Lakehead Line or Replacement Segment shall not exceed 45,000 cubic meters (“m3”), except in 87 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1392 Page 92 of 225 those instances where Enbridge demonstrates compliance with the leak detection sensitivity requirements in Paragraph 89 below. Leak Detection Sensitivity Requirements New US Line 3: Enbridge shall design and construct the New Lakehead Pipeline that will replace Original US Line 3 (“New US Line 3”) to meet all of the leak detection sensitivity targets in the table below with respect to each MBS Segment created by, or included within, the New US Line 3. Such targets shall apply only during periods when the fluid in the MBS Segment is in a Steady State. Enbridge shall use the criteria set forth in API Publication 1149 (“Pipeline Variable Uncertainties and Their Effects on Leak Detectability”) to estimate the ability of the MBS Leak Detection System to achieve each of the targets set forth in the table below. Type of MBS Alarm 5-Minute Alarm 20-Minute Alarm 2-hour Alarm 24-hour Alarm Leak Detection Design and Construction Target for New US Line 3 MBS Leak Detection System shall detect and alarm if, within any rolling 5-minute period, it cannot account for 7-13% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 20-minute period, it cannot account for 3-4% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 2-hour period, it cannot account for 3% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 24-hour period, it cannot account for 2% of the volume of oil injected or pumped into the MBS Segment. Other Lakehead Projects: Enbridge shall design and construct any Replacement Segment or New Lakehead Pipeline other than New US Line 3 to meet all of the leak detection sensitivity targets in the table below with respect to each MBS Segment created by, or included within, the Replacement Segment or New Lakehead Pipeline. Such targets shall 88 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1393 Page 93 of 225 apply only during periods when the fluid in the MBS Segment is in a Steady State. Enbridge shall use the criteria set forth in API Publication 1149 to estimate the ability of the MBS Leak Detection System to achieve each of the targets set forth in the table below. Type of MBS Alarm 5-Minute Alarm 20-Minute Alarm 2-hour Alarm 24-hour Alarm Leak Detection Design and Construction Target for other Lakehead Projects MBS Leak Detection System shall detect and alarm if, within any rolling 5-minute period, it cannot account for 7-25% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 20-minute period, it cannot account for 3-10% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 2-hour period, it cannot account for 3-5% of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall detect and alarm if, within any rolling 24-hour period, it cannot account for 2-3% of the volume of oil injected or pumped into the MBS Segment. Demonstration of Compliance with Leak Detection Sensitivity Design and Construction Requirements: For each MBS Segment on a New Lakehead Pipeline or Replacement Segment with the capacity to hold more than 45,000 m3 of oil, Enbridge shall demonstrate compliance with the leak detection sensitivity design and construction requirements in Subparagraphs 89.a and 89.b. Specifically, with respect to New US Line 3, Enbridge shall demonstrate, in accordance with Subparagraphs 90.a and 90.b, that the MBS Leak Detection System is able to detect any and all leaks or ruptures within the MBS Segment that would meet, or exceed, one or more of the leak detection targets set forth in the table in Paragraph 89.a, above, for the design and construction of New US Line 3. Further, with respect to any Replacement Segments or New Lakehead Pipelines other than New US Line 3, Enbridge shall demonstrate, in accordance with Subparagraphs 90.a and 90.b, that the MBS Leak Detection System is able to detect any and all leaks or ruptures within the MBS Segment that would meet, or exceed, one or 89 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1394 Page 94 of 225 more of the leak detection targets established in accordance with Subparagraph 89.b above, for the design and construction of the Replacement Segment or New Lakehead Pipeline. If Enbridge is unable to make such a demonstration in accordance with Subparagraphs 90.a and 90.b, Enbridge shall comply with the requirements of Subparagraph 90.c, below. Within 90 Days of Initial Linefill of a New Lakehead Pipeline or Replacement Segment, Enbridge shall submit to EPA a plan to demonstrate the ability of the MBS Leak Detection System to detect leaks or ruptures within each MBS Segment that has a capacity to hold more than 45,000 m3 of oil. The plan shall require Enbridge to conduct testing using the fluid-withdraw method except where the use of that method is not feasible due to a lack of on-site piping and/or tanks necessary to complete such testing. Where the use of the fluid withdraw method is not feasible for these reasons, Enbridge shall make the required demonstration using a software-based simulated leak methodology of the type described in API Publication 1130. The plan shall include a schedule for completing all required testing, but in no event shall the schedule provide for the completion of testing later than 12 months after completion of Initial Linefill. The plan shall require Enbridge to collect data with respect to each type of MBS Alarm (i.e. the 5-minute alarm, the 20-minute alarm, the 2-hour alarm, and the 24hour alarm) demonstrating (1) the sensitivity of the MBS Leak Detection System in detecting leaks and ruptures and (2) the reliability of such system in terms of its false alarm rate. Further, Enbridge shall collect data demonstrating the relationship between these two variables, showing how the false alarm rate will rise (or fall) in response to adjustments made by Enbridge to the sensitivity of the MBS Leak Detection System in detecting leaks or ruptures (“S-R Performance”). 90 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1395 Page 95 of 225 Within 30 Days of submitting the plan to EPA, Enbridge shall commence testing in accordance with its plan and schedule. Within 30 Days after completion of the testing, Enbridge shall submit to EPA a report presenting the results of the testing. In its report, Enbridge shall present its data sets in graphical form (as illustrated in Appendix F) showing the S-R Performance curve for each of the four types of MBS alarm. With respect to New US Line 3, Enbridge shall have demonstrated compliance with the design and construction targets in Paragraph 89.a. if, based upon the S-R Performance curves, Enbridge proves its MBS Leak Detection System is able to detect any and all leaks that would meet, or exceed, the targets in Paragraph 89.a. without regard to the number of false alarms occurring at those target sensitivities. Likewise, with respect to any Replacement Segment or New Lakehead Pipeline other than New US Line 3, Enbridge shall have demonstrated compliance with the design and construction targets in Paragraph 89.b. if, based upon the S-R Performance curves, Enbridge proves its MBS Leak Detection System is able to detect any and all leaks that would meet, or exceed, the targets in Paragraph 89.b. without regard to the number of false alarms occurring at those target sensitivities. In the event that the testing demonstrates that one or more tested MBS segments does not meet the leak detection sensitivity design and construction requirements mandated under Paragraph 89, Enbridge shall, concurrently with submission of the report required in Paragraph 90.b, submit to EPA for approval a proposed plan and schedule for implementing corrective actions that will assure compliance with the MBS size limitation in Paragraph 88 or assure that MBS Leak Detection System is able to detect any all and all leaks or ruptures within the MBS Segment that would meet, or exceed, one or more of the leak detection sensitivity targets in Paragraph 89, based upon the S-R Performance curves described in the 91 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1396 Page 96 of 225 preceding paragraph. Upon approval by EPA, Enbridge shall implement the approved plan and schedule. Establishment and Optimization of Alarm Thresholds: Except as otherwise provided in Paragraph 103 (“24-Hour Alarm”), Enbridge shall, in the interest of reducing false alarms and improving the reliability of the MBS Leak Detection System, set alarm thresholds for the MBS Leak Detection System at any level that Enbridge deems appropriate, subject to the limitations and requirements set forth in Subparagraphs 91.a - c, below. No later than Initial Linefill of New US Line 3 or any other New Lakehead Pipeline or Replacement Segment, Enbridge shall ensure that each MBS Segment of such pipeline or segment be subject to an alarm threshold for each of the four types of MBS Alarms (i.e. the 5minute alarm, the 20-minute alarm, the 2-hour alarm, and the 24-hour alarm). In no event shall an alarm threshold applicable to Steady State operations be, at any time, less stringent than the minimum alarm thresholds set forth in the table below, Type of MBS Alarm 5-Minute Alarm 20-Minute Alarm 2-hour Alarm 24-hour Alarm MBS Alarm Threshold Requirements During All Periods of Steady State Operations MBS Leak Detection System shall alarm if, within any rolling 5-minute period, it cannot account for 30% or more of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall alarm if, within any rolling 20-minute period, it cannot account for 15% or more of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall alarm if, within any rolling 2-hour period, it cannot account for 5% or more of the volume of oil injected or pumped into the MBS Segment. MBS Leak Detection System shall alarm if, within any rolling 24-hour period, it cannot account for 3% or more of the volume of oil injected or pumped into the MBS Segment. Within one year of Initial Linefill of New US Line 3 or any other New Lakehead Pipeline or Replacement Segment, Enbridge shall conduct and complete a study to 92 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1397 Page 97 of 225 optimize the alarm thresholds established in accordance with the preceding Subparagraph. Based upon the results of the study, Enbridge shall set an alarm threshold that optimizes the trade-off between the competing goals of reducing the number of false alarms and improving the sensitivity of the MBS Leak Detection System in detecting leaks and ruptures. In no event shall Enbridge adjust an alarm threshold so that it is less sensitive to leaks and ruptures that the minimum alarm thresholds set forth in the table in the preceding Subparagraph. Within 60 Days of completing the optimization study, Enbridge shall submit a report to EPA that presents the results of the optimization study, identifies the optimized alarm thresholds established by Enbridge, and explains the basis for such thresholds. To the extent that the optimized alarm thresholds are more sensitive to leaks and ruptures than the minimum alarm thresholds set forth in Subparagraph 91.a, above, Enbridge is not required to implement the optimized thresholds under this Consent Decree, except for the optimized threshold applicable to the 24-hour MBS Alarm, as provided in Paragraph 103. (IV) Leak Detection Requirements for Pipelines within the Lakehead System Operation of MBS Leak Detection System: Enbridge shall continue to operate the MBS Leak Detection System to perform computational modelling for each MBS Segment of each Lakehead System Pipeline. For each MBS Segment, Enbridge shall maintain continuous and uninterrupted leak detection capability at all times, including during periods of Startup and Shutdown, except as set forth in Paragraph 93 below. In no event shall the alarm threshold for Steady State operations be, at any time, less stringent than the minimum alarm thresholds set forth in the table at Subparagraph 91.a. 93 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1398 Page 98 of 225 Enbridge may temporarily suspend MBS leak detection operations within any MBS Segment as the result of: Instrumentation in the MBS Segment unexpectedly failing for reasons beyond Enbridge’s control; Enbridge taking instrumentation out of service to conduct scheduled maintenance or repairs, or Enbridge taking a flowmeter out of service to move an in-line tool (e.g. ILI tool or In-Line Batch Interface Tool) past the location of the flowmeter, provided that the pipeline is not one that was designed and constructed to allow in-line tools to bypass flowmeters with no disruption in service of the flowmeter. In the event that Enbridge loses or suspends MBS leak detection capability within one or more MBS Segments then, except as provided in Paragraph 95, below, Enbridge shall automatically establish and maintain leak detection capability in an Overlapping MBS Segment as a temporary measure until the leak detection capability is restored in all MBS Segments. The Overlapping MBS Segment shall integrate no more than the minimum number of MBS Segments necessary to achieve and maintain temporary leak detection capability within all MBS Segments impacted by the outage. If Enbridge loses or suspends MBS leak detection capability in (a) the first MBS Segment at the beginning of a Lakehead System Pipeline due to an instrumentation outage at the upstream end of such segment or (b) the last MBS Segment at the end of a Lakehead System Pipeline due to an instrumentation outage at the downstream end of the MBS Segment, Enbridge shall maintain leak detection capability with respect to the non-functioning MBS Segments by means of an alternative leak detection system, which shall be based upon one of the methods 94 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1399 Page 99 of 225 identified in Annex B to API Publication 1130 (“Computational Pipeline Monitoring for Liquid Pipelines”). Enbridge shall continuously operate the alternative leak detection system until the flowmeter outage is resolved and the MBS Segments are restored to operation. Whenever Enbridge loses or suspends leak detection capability within an MBS Segment, Enbridge shall restore the leak detection capability of the MBS Segment as soon as practicable. Enbridge shall report all such outages in the Semi-Annual Report submitted in accordance with Paragraph 143 of this Decree. In the report, Enbridge shall identify (1) the day and hour when the instrumentation outage began, (2) the day and hour when the outage was resolved, (3) the reason for the outage, and (4) the actions taken to resolve the outage. The reporting requirement in Paragraph 96 shall not apply if (a) Enbridge temporarily loses or suspends the leak detection capability for one of the reasons set forth in Paragraph 93 and (b) Enbridge restores the leak detection capability of the MBS Segment within the target periods set forth in the table below. Time Period to Restore MBS Segment to Operation 10 Days 4 hours 4 Days Reason for Instrumentation Outage Instrumentation Failure Bypass of ILI Tool Schedule Maintenance or repairs In the table above, the 4-hour time period for restoring the MBS segment to operation shall be tolled in the event of an unplanned shutdown of the pipeline during the period when a flowmeter is out of service due to an in-line tool moving past the location of the flowmeter. The tolling period shall begin when the pipeline is shut down, and it shall end when Enbridge resumes pumping operations in the pipeline. 95 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1400 Page 100 of 225 Installation of New Equipment at Remotely-Controlled Valves. In the event that Enbridge excavates a Remotely-Controlled Valve or converts a manual valve to a RemotelyControlled Valve on a pipeline within the Lakehead System, Enbridge shall install (i) a pressure transducer/transmitter on the upstream side of the valve as well as on the downstream side of the valve at the time of the excavation and (ii) install a skin-based temperature transducer/transmitter at the valve. Enbridge shall install and operate such equipment in a manner as to provide continuous real-time data to Enbridge’s SCADA and MBS Leak Detection System at all times, including during periods when the pipeline is sectionalized. The requirements in Paragraph 99 shall not apply if (1) the remotely-controlled valve is excavated on an emergency basis and not in conjunction with a planned excavation to repair, maintain, or inspect the valve or pipeline or (2) the new equipment would be duplicative of functionally identical equipment in the same Valve Segment. Transient-State Sensitivity Analysis. Within 180 Days of the Effective Date, Enbridge shall perform an analysis of all pipelines within the Lakehead System to determine leak sensitivity during Startup and Shutdown conditions and for the purpose of establishing transientstate performance targets. Rupture Detection System Alarm. Enbridge shall continuously operate a new Rupture Detection System alarm system, which is integrated with Enbridge’s SCADA system and MBS Leak Detection System. The Rupture Detection System Alarm shall apply to all pipelines that are part of the Lakehead System and shall be active at all times, including during periods when the pipeline is in Steady State and Transient State. The Rupture Detection Alarm System shall include a computer-based system that continuously monitors real-time data from the SCADA system for the purpose of 96 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1401 Page 101 of 225 detecting (a) an abnormally low pressure, (b) an abnormal pressure drop, or (c) an abnormal increase in the flow rate. Upon detecting one or more of these abnormal conditions, the computerbased system shall generate an alarm, alerting each member of the Alarm Response Team in accordance with Paragraphs 106 and 107, below. Within 90 Days of the Effective Date, Enbridge shall submit to EPA the results of testing of the Rupture Detection Alarm System for at least two separate MBS Segments. Such testing shall document compliance with this Paragraph and explain why the Rupture Detection Alarm System would alarm in the event of a sudden pressure drop on both sides of a pump station. In the event that such testing does not demonstrate compliance with the requirements of this Paragraph, Enbridge shall, concurrently with submission of the report required under the preceding Subparagraph, submit to EPA for approval a proposed plan and schedule for corrective action. Enbridge shall implement the corrective action in accordance with the approved schedule and conduct re-testing of the alarm system no later than 30 Days after the corrective action is completed. Upon completion of successful testing of the Rupture Detection System, Enbridge shall continuously operate the alarm system at all times, including during periods when the pipeline is in Steady State and Transient State. “24-hour” Alarm. Within 270 Days of the Effective Date, Enbridge shall modify the MBS Leak Detection System to include a new “24-hour” alarm, which shall be integrated with Enbridge’s SCADA system. The 24-hour Alarm shall apply to all pipelines that are part of the Lakehead System and shall be active at all times, including during periods when the pipeline 97 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1402 Page 102 of 225 is in Steady State and Transient State. To establish such an alarm, Enbridge shall take the following steps: Enbridge shall continuously monitor, track, and model the mass balance of oil for each MBS Segment over any rolling 24-hour period. For all pipelines that are part of the Lakehead System, Enbridge shall ensure that the MBS Leak Detection System, at a minimum, shall alarm if it cannot detect, or otherwise account for, 3 percent (or more) of oil pumped or injected into the MBS Segment over any rolling 24-hour period. The alarm system shall alert each member of the Alarm Response Team of such a condition in accordance with Paragraphs 106 and 107, below. Within one year of establishing the new 24-hour Alarm, Enbridge shall conduct and complete a study to optimize the alarm thresholds for each pipeline that is part of the Lakehead System as of the Effective Date. Within 60 Days of completion of the optimization study, Enbridge shall submit to EPA for review and approval a report setting forth the results of the study and proposing an alarm threshold for each pipeline that optimizes the tradeoff between the competing goals of reducing false alarms and improving the sensitivity of the MBS Leak Detection System in detecting ruptures and leaks. In no event shall Enbridge propose an alarm threshold that would reduce the leak sensitivity of the 24-hour alarm by increasing the alarm threshold above the 3-percent minimum alarm threshold. Upon submission of its proposal, Enbridge shall immediately implement and continuously maintain each proposed alarm threshold as an enforceable requirement of this Consent Decree. In the event that EPA subsequently disapproves one or more of the proposed alarm thresholds, Enbridge shall, within 30 Days of receipt of EPA’s disapproval, propose an alternative alarm threshold for each threshold rejected by EPA or invoke dispute resolution under Section XIII of this Consent Decree. In either event, 98 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1403 Page 103 of 225 Enbridge shall continue to maintain the alarm threshold that it initially proposed based upon the optimization study unless and until an alternative alarm threshold is proposed by Enbridge or an alternative alarm is established through dispute resolution. Within one year of Initial Linefill of New US Line 3 or any other New Lakehead Pipeline or Replacement Segment, Enbridge shall conduct and complete an optimization study in accordance with Paragraph 91.b, which shall include optimization of the 24hour MBS Alarm. Upon submission of the optimization report in accordance with Paragraph 91.c, Enbridge shall immediately implement and continuously maintain the alarm threshold set forth in the report for the 24-hour alarm. In the event that EPA subsequently disapproves the proposed alarm threshold, Enbridge shall, within 30 Days of receipt of EPA’s disapproval, propose an alternative alarm threshold or invoke dispute resolution under Section XIII of this Consent Decree. In either event, Enbridge shall continue to maintain the alarm threshold that it initially proposed based upon the optimization study unless and until an alternative alarm threshold is proposed by Enbridge or an alternative alarm is established through dispute resolution. Within 90 Days of optimizing the “24-Hour” alarm for any pipeline that is part of the Lakehead System, Enbridge shall conduct testing of the alarm by conducting simulations of a leak in two separate MBS Segments. Within 60 Days after completing such testing, Enbridge shall report on the results of such testing in a report that is submitted to EPA. In the event that such testing is unsuccessful, Enbridge shall, concurrently with submission of the report referred to in the preceding Subparagraph, submit to EPA for approval a proposed plan and schedule, for corrective action. Upon receipt of an approved plan 99 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1404 Page 104 of 225 for corrective action, Enbridge shall implement the plan in accordance with the approved schedule and conduct re-testing of the alarm. Upon establishment of the optimized threshold for a Lakehead System Pipeline in accordance with Subparagraphs c or d, Enbridge shall continuously comply with the optimized alarm threshold for that pipeline, except as provided below. Enbridge may relax the optimized alarm threshold for a Lakehead System Pipeline if it experiences false alarms for that pipeline at a rate higher than the rate provided for in the optimization study conducted in accordance with Paragraph 103.c or d. If the increase in the false alarm rate is due is an equipment failure or a comparable problem that can be corrected through repairs or replacement, Enbridge shall implement such repairs or replacement and restore the optimized alarm threshold as expeditiously as practicable. In the event that the optimized alarm threshold is not restored within 60 Days, Enbridge shall provide a notification to EPA, explaining the actions taken to date and setting forth the plan and the schedule for completing the restoration of the optimized alarm threshold. If the increase in the false alarm rate is not due to an equipment failure or a comparable problem that can be corrected through repairs or replacement, Enbridge shall undertake a new optimization study. Enbridge shall conduct the new optimization study in accordance with Subparagraph c and d of this Paragraph, except Enbridge shall complete the optimization study and propose a new optimized alarm threshold within six months of the relaxation of the original optimized alarm threshold. Nothing in this Subpararaph shall authorize Enbridge to establish a temporary alarm threshold or a new optimized alarm threshold that is less sensitive to 100 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1405 Page 105 of 225 leaks and ruptures than the 3% minimum threshold set forth in Subparagraph b of this Paragraph. In each Semi-Annual Report submitted by Enbridge in accordance with Section IX (Reporting Requirements), Enbridge shall identify each instance when a temporary alarm threshold or new optimized alarm threshold was established and, for each instance, provide (a) the date when the temporary alarm threshold was established, (b) the date when the optimized alarm threshold was restored or replaced with a new optimized alarm threshold, and (c) the reasons why Enbridge concluded that its action were compliant with the requirements of this Subparagraph g. (V) Leak Detection Requirements for Control Room Applicability: For the purposes of this subsection, the term “Alarm” or “Alarms” shall include any and all alarms generated by the MBS Leak Detection System and by the Rupture Detection System. Alarm Response Team: Beginning no later than 180 Days after the Effective Date, all Alarms shall be addressed by an Alarm Response Team, which shall be composed of the following individuals in the Control Room at the time that the Alarm occurs: (1) the Control Room operator (“CRO”) who is responsible for the pipeline that generates the alarm, (2) the leak detection analyst (“LD Analyst”), and (3) the senior technical advisor for that pipeline. Remote Notification of Alarm Response Team. Beginning no later than 180 Days after the Effective Date, Enbridge shall assure that each Alarm triggers a remote notification of each member of the Alarm Response Team who has not electronically acknowledged the Alarm within two minutes after the onset of the Alarm. Such remote notification shall be sent automatically via e-mail, text message or pager. Such notification shall identify the type of alarm 101 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1406 Page 106 of 225 (e.g. 5-minute MBS alarm), the time of its occurrence, and the MBS Segment that precipitated the alarm. Audible and Visual Alarms: Beginning no later than 180 Days after the Effective Date, each Alarm shall result in an audible alarm, which shall instantaneously and automatically sound at the desk or workstation (“Pod”) of each member of the Alarm Response Team (collectively “Alarm Recipients”). Each audible alarm shall be accompanied by an alarm window, which shall open instantaneously and automatically on the computer displays of the Alarm Recipients. While an Alarm Recipient may elect to mute the audible alarm, Enbridge shall design and implement the alarm systems to ensure that the Alarm Recipient will be unable to turn off, or otherwise hide from view, the alarm window. Enbridge must ensure that the alarm window remains present and visible on the computer display of each Alarm Recipient until the Alarm is cleared in accordance with the “Alarm Clearance Procedure” required below in Paragraph 108. In the event that the Alarm is not cleared within ten minutes of its initiation, Enbridge shall ensure that the audible alarm shall sound again and the alarm window shall change color or provide another visual cue for the purpose of alerting Alarm Recipients that the tenminute time period for evaluating the Alarm has lapsed. Alarm Clearance Procedures: Beginning no later than 180 Days after the Effective Date, Enbridge shall employ the following procedures to clear all Alarms: Each and every Alarm shall remain active until either (1) the pipeline is shut down for the purpose of investigating a potential leak or rupture or (2) the Alarm Response Team completes its investigation of the Alarm and (a) accounts for any cumulative imbalance indicated by the Alarm or series of Alarms, (b) confirms the cause (or causes) of the Alarm and (c) rules out the possibility of a rupture or leak. Under the latter scenario, the Alarm shall 102 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1407 Page 107 of 225 automatically terminate after all members of the Alarm Response Team have manually verified their completion of the steps necessary to investigate and clear the Alarm. No member of the Alarm Response Team shall resolve or clear the Alarm through a manual, one-time adjustment to any alarm system or the inputs into such alarm systems. Such adjustments may be made only after the Alarm Response Team completes its investigation and the Alarm is terminated in accordance with Subparagraph 108.a. In investigating an Alarm, the LD Analyst shall analyze and determine whether the leak detection system that generated the Alarm (i.e. the MBS Leak Detection System or the Rupture Detection System) is functioning properly. Specifically, the LD Analyst shall determine if the Alarm was result of (1) an error in the real-time data from the SCADA system (e.g. data generated by a malfunctioning instrument) or (2) a malfunction of the MBS Leak Detection System or the Rupture Detection System. Irrespective of the determination made by the LD Analyst, the CRO, in conjunction with the senior technical advisor, shall conduct an independent investigation of the Alarm. The final decision to clear the Alarm before 10 minutes have expired, if made, shall be made by the CRO. The CRO shall confer with, and obtain the concurrence of, the senior technical advisor before taking the final action to clear the Alarm in accordance with Subparagraph 108.a. A determination that an Alarm was caused by a Column Separation shall not be a permissible basis for clearing an Alarm unless the Alarm Response Team follows the procedures set forth in Subparagraphs 109.b and 109.c below. Upon clearance of an Alarm and before the end of his or her shift, each member of the Alarm Response Team shall create an electronic record of his or her actions in 103 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1408 Page 108 of 225 response to each Alarm. Each member of the Alarm Response Team shall create such a record by reviewing and selecting categories from an electronic menu on their computer screens, provided that, in any event, the record shall identify (1) the type of alarm, (2) the reasons for clearing the alarm, and (3) the procedures followed by the team member. Each member of the Alarm Response Team shall be responsible for providing the electronic record to his or her counterpart on the subsequent shift. All such electronic records shall be stored and maintained by Enbridge for at least five years, in accordance with Paragraph 157 (record retention). Unscheduled Shutdown Procedures in Response to an Alarm: By no later than 50 Days after the Effective Date, Enbridge shall employ the following procedures in shutting down a pipeline in response to an Alarm: Ten-Minute Rule: In the event that the Alarm Response Team is unable to rule out the possibility of a leak or rupture within ten minutes of the start of an Alarm, the CRO shall immediately, and without further consultation or notification, shut down and sectionalize the pipeline. Column Separation - Running Pipeline: When an Alarm is caused by a Column Separation that forms in a running pipeline, the CRO shall immediately, and without further consultation or notification, shut down and sectionalize the pipeline if, within ten minutes from the start of the Alarm, the Column Separation continues to exist or the Alarm Response Team has not (1) determined the cause of the Column Separation, (2) accounted for cumulative imbalance that triggered the Alarm, and (3) ruled out the possibility of a leak or rupture. The rules stated in this Subparagraph shall not apply when the Alarm is caused by a Column Separation that occurred during or after the shutdown of the pipeline. 104 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1409 Page 109 of 225 Column Separation – Pipeline Shutdown. When an Alarm is caused by a Column Separation that forms in a pipeline after the commencement of a shutdown, the CRO shall complete the shutdown as expeditiously as possible and sectionalize the pipeline to isolate the Column Separation. In addition, when an Alarm is caused by a Column Separation that formed in a pipeline after the completion of a shutdown, the CRO shall immediately sectionalize the pipeline to isolate the Column Separation. In either event, after sectionalizing the pipeline, the Alarm Response Team shall immediately investigate the Alarm to (1) determine the cause of the Column Selection, (2) account for cumulative imbalance that triggered the Alarm, and (3) attempt to rule out the possibility of a leak or rupture. Such investigation shall be completed as expeditiously as possible. If the Alarm Response Team completes its investigation and clears the Alarm in accordance with Paragraph 108 above, the CRO (or his or her replacement on a subsequent shift) may reopen sectionalizing valves and restart the pipeline, but only after the CRO, in consultation with the senior technical advisor, employs best engineering practices to calculate the amount of time that will be needed to fill the Column Separation and such calculation is reviewed and approved by a manager, as specified in the table below. After the restart of the pipeline, the CRO shall in no event continue pumping operations if the Column Separation is not filled within the time period approved by the manager for restoring the column. If the time period approved by the manager to fill the Column Separation has run and the Column Separation continues to exist, the CRO shall immediately, and without further consultation or notification, shut down and sectionalize the pipe for the purpose of investigating a possible leak or rupture. Such an investigation shall include, among other things, deploying personnel to conduct a visual inspection of the pipeline, contacting local officials to ascertain whether there 105 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1410 Page 110 of 225 have been reports consistent with a leak or rupture, or taking other comparable steps to collect information about the condition of the pipeline. Estimated Time to Fill Column Separation 10 minutes or less 11 minutes to 30 minutes More than 30 minutes Management Approval Shift Supervisor On-Call Manager Control Center Operations VP Pipeline Control or the VP’s delegate Confirmed Leak rule: In the event that any member of the Alarm Response Team determines that an Alarm is a Confirmed Leak or Rupture, the CRO shall immediately, and without further consultation or notification, shut down and sectionalize the pipeline. A “Confirmed Leak or Rupture” shall mean (a) an Alarm generated by the Rupture Detection System or (b) an Alarm generated by the MBS Leak Detection System combined with two (or more) other operating conditions or events that may indicate a leak or rupture. Such operating conditions or events shall include, but are not limited to, the following examples, unless the Alarm Response Team affirmatively determines the cause of the operating condition or event and such cause is not consistent with a leak or rupture: Data from the SCADA system shows any of the following conditions or event at a location upstream of the suspected leak or rupture: • Sudden drop in discharge pressure; • Sudden change in control valve throttling or pump speed; • Sudden increase in flow rate; or • Shut down (or lock out) of one or more pumps in combination with one (or more) of the following conditions or events: a sudden drop in upstream discharge pressure, a sudden change in upstream control valve throttling, or a sudden change in the variable frequency drive (“VFD”) control. 106 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1411 Page 111 of 225 Data from the SCADA System shows any of the following conditions or events at a location downstream of the suspected leak or rupture: • Sudden drop in suction pressure; • Sudden change in control valve throttling or pump speed; • Sudden drop in holding pressure at a delivery location; • Sudden decrease in flow rate; or • Shut down (or lock out) of Shut down (or lock out) of one or more pumps in combination with one (or more) of the following conditions or events at a location upstream of the suspected leak or rupture: a sudden drop in discharge pressure, a sudden change in control valve throttling, or a sudden change in VFD control. Data from the SCADA System shows any of the following conditions or events at a terminal where oil is injected into the pipeline with the suspected leak or rupture: • Sudden increase or decrease in flow rate; • Sudden decrease in pressure; or • Shut down (or lock out) of one (or more) booster pumps in combination with a sudden decrease in pressure. Data from the SCADA System shows any of the following conditions or events at a terminal or landing where oil is delivered from the pipeline with the suspected leak or rupture. • Sudden increase or decrease in flow rate; • Sudden decrease in pressure; or • Closing of a pressure control valve. 107 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1412 Page 112 of 225 Once the CRO initiates the Shutdown of a pipeline, Enbridge shall not resume pumping operations until: (i) the cause of the Alarm is determined or the integrity of the pipeline is verified; (ii) the applicable emergency procedures are completed and electronically validated by the appropriate accountable parties; and (iii) a record is generated that details the nature of the Alarm, describes how the cause of the Alarm was determined and/or how the integrity of the line was verified, and records the critical information considered during the decision-making process. After December 31, 2016, Enbridge shall comply with the requirement set forth in this Subparagraph 109.e.(iii) by making an electronic record. Certification of Compliance with 10-Minute Rule and Other Requirements of this Subsection: Enbridge shall certify compliance with the 10-Minute Rule and other requirements relating to Alarms under this Subsection VII.G.(V) as follows: Enbridge shall prepare, electronically, a weekly list of alarms (“WLOA”) that breaks down, by pipeline and type of Alarm, the total number of Alarms for the week. For each Alarm, the WLOA shall identify the date of the Alarm, the time at which it began, the time when the Alarm was cleared. For each Alarm that met the criteria for an Unscheduled Shutdown set forth in Paragraph 109, Enbridge shall prepare, electronically, a record of alarm (“ROA”), which documents the critical facts relating to the Alarm, including the positions of the Alarm Recipients, the time that the Alarm was received, and the actions (or inactions) of the Alarm Response Team. In each case where the 10-Minute Rule or other requirements in this Subsection VII.G.(V) required shutdown but shutdown did not occur, Enbridge shall conduct an investigation within 90 Days of the incident and prepare, electronically, a written report (“Post-Incident Report”) documenting the pertinent facts and describing the 108 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1413 Page 113 of 225 corrective actions taken as result of the post-incident review. All Post-Incident Reports shall be incorporated by reference, and attached, to the ROA. In each case where the Alarm Response Team initiated an unscheduled shutdown, as required in Subsection VII.G.(V), the ROA shall state when the Unscheduled Shutdown was commenced, when it was completed, the cause and classification of the Alarm, each fact considered in determining the cause of the Alarm, the justification for resumption of pumping operations, and the time that pumping operations resumed. Enbridge shall provide all WLOAs and ROAs occurring during the reporting time period for all pipelines in the Lakehead System to EPA as an attachment to the Semi-Annual Report in electronic format. In addition, in the body of the Semi-Annual Report, Enbridge shall provide a summary of alarms (“SOA”) that sets forth, by pipeline, the total number of alarms and states whether or not Enbridge complied with the 10-Minute Rule and other requirements set forth in Subsection VII.G.(V) in responding to Alarms. With respect to each non-compliance, Enbridge shall explain the reason for the non-compliance and identify the corrective action, if any, taken to prevent a reoccurrence of the non-compliance in its SemiAnnual Report pursuant to Paragraph 143 of the Decree. The Vice-President, Pipeline Control for Enbridge, must sign the SOA and certify that for the relevant reporting period: (1) the information contained in the SOA, as well as in the WLOAs and ROAs, is true and accurate, and (2) Enbridge has complied with the 10Minute Rule and other requirements of this Subsection VII.G.(V), except for those noncompliances specifically listed in the SOA. 109 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1414 Page 114 of 225 Unscheduled Shutdown Procedures in Response to Other Events: In the event that Enbridge receives information of a potential leak or rupture from a source other than an Alarm (e.g. police or fire department officials call to report a leak), personnel in the Control Room shall conduct an immediate investigation to determine whether any Lakehead System Pipeline may have failed, resulting in a leak or rupture. Such an investigation shall be completed as expeditiously as possible, but in no event shall the investigation take more than 10 minutes from the moment that Enbridge received information concerning a potential leak or rupture and the approximate location of the potential leak, rupture or discharged oil. In the event that the investigation uncovers evidence consistent with a leak or rupture by a Lakehead System Pipeline, the CRO for the pipeline shall immediately, and without further consultation or notification, shut down and sectionalize the pipeline. In the Semi-Annual Report submitted in accordance with Paragraph 143, Enbridge shall report all incidents during the reporting period when Enbridge received information of a potential leak or rupture from a Lakehead System Pipeline. With respect to each incident, Enbridge shall describe the investigation conducted in response to this information, including (i) the time when Enbridge received notice of a potential leak or rupture, (ii) the information provided with the notice, (iii) the time when Enbridge began its investigation, (iv) the time when Enbridge ended its investigation, and (v) the conclusion and findings of the investigation. H. SPILL RESPONSE AND PREPAREDNESS Upon confirmation of a pipeline rupture or leak, Enbridge shall immediately proceed, without delay, to take necessary and appropriate actions to minimize and prevent the discharge of oil into, and upon, the waters of the United States or adjoining shorelines. Such 110 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1415 Page 115 of 225 actions shall include, but are not limited, to the immediate dispatch of trained personnel to the location of the rupture or leak. To enhance its ability to respond to any spills that may occur along the Lakehead System, Enbridge shall undertake the actions set forth below in Paragraphs 115 to 119. Agreed Exercises Before Termination of the Consent Decree, Enbridge shall complete four training exercises, in accordance with this Paragraph, to test and practice its response to a major inland oil spill from a Lakehead System Pipeline that impacts a water body (“Agreed Exercises”). Each such Agreed Exercise shall include the mobilization and deployment of Enbridge’s local Incident Management Team within a functioning command post. Each Agreed Exercise shall also include deployment of personnel and equipment provided by Enbridge, and one or more of its contractors and oil spill removal organizations (“OSROs”), to a minimum of two identified downstream Control Points. Each Agreed Exercise shall test tactical deployment of personnel and equipment for containment/recovery and techniques for responding to overland flow and impacted banks and vegetation. The activities conducted as part of the Agreed Exercises shall include, but are not limited to: (i) implementation of the Incident Command System (“ICS”), including operation of the unified command structure and (ii) the deployment of equipment, which may include sorbent booms, skimmers, vacuum trucks, and other related equipment applicable to the Control Points, in and along the waterbody that is the focus of the Agreed Exercise. The Agreed Exercises shall occur in the following inland zone locations and times: Cass, Minnesota (2017) 111 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1416 Page 116 of 225 Des Plaines, Illinois (2018) Wisconsin River, Wisconsin (2019) Stockbridge, Michigan, (2020) EPA and Enbridge may modify the location or time by joint written agreement and notice to the Court. Such modifications will not require Court approval. No later than 10 months before each of the four Agreed Exercises, Enbridge shall invite EPA, PHMSA, and the appropriate area committee, Sub-Area committee, tribal representative, state and local authorities to participate in the planning of the Agreed Exercises (“Planning Participants”). For each of the four Agreed Exercises Enbridge shall: Conduct at least three planning meetings, the first of which will take place no later than 10 months before each exercise; Invite all Planning Participants to each planning meeting; Coordinate with the Planning Participants during the initial planning meeting to develop the objectives, scenario, and participant list for the Agreed Exercise; and No later than 9 months before each exercise, submit a draft plan, including the scope, objectives, scenario and participant list for the exercise (“Agreed Exercise Plan”) to EPA for review and approval. EPA will review each Agreed Exercise Plan to ensure that specific components – namely, the objectives, scope, impact zone, scenario and invitation list for the exercise – are consistent with the consensus of the participants in the planning process, as well as consistent with (i) the location, schedule, scope and impact zone identified by EPA pursuant to 112 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1417 Page 117 of 225 Subparagraphs 115.a and 115.b of this Consent Decree and (ii) the “National Preparedness for Response Exercise Program (PREP) Guidelines,” which are published by the U.S. National Response Team. In accordance with Paragraph 137 of the Consent Decree, EPA will review and approve, approve with modifications, or disapprove with comments the Agreed Exercise Plan within 7 business Days of receipt. In the event that EPA approves the Agreed Exercise Plan but also provides comments, Enbridge shall incorporate those comments into the final Agreed Exercise Plan no later than 60 Days before the Agreed Exercise. Upon receipt of an approved final Agreed Exercise Plan, Enbridge shall conduct the Agreed Exercise in accordance with the approved Agreed Exercise Plan. No later than 30 Days after the completion of each Agreed Exercise, Enbridge shall organize and conduct a meeting to review the Agreed Exercise for the purpose of identifying “lessons learned” and making recommendations to improve future Agreed Exercises and response actions. In planning such a meeting, known for the purposes of this Section as an “After-Action Review,” Enbridge shall invite representatives from each Planning Participant. No later than 60 Days after the Agreed Exercise After-Action Review, Enbridge shall submit to EPA for review and comment a report (“After Action Report”) that sets forth findings and conclusions regarding the Agreed Exercise. In the event EPA provides comments that are not incorporated into the draft After Action Report to EPA’s satisfaction, Enbridge shall include the comment(s) as an appendix to the report. No later than 90 Days after receiving EPA comments, Enbridge shall provide the final report to all Planning Participants electronically. Field Exercises, Table Top Exercises, and Community Outreach 113 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1418 Page 118 of 225 Enbridge shall conduct, on an annual basis, until the Consent Decree is terminated, at least six Field Exercises and ten Table-Top Exercises, as described more fully in Subparagraphs 116.b-d below. Enbridge shall conduct such exercises in cities and towns shown on Appendix C. For the purposes of this Paragraph of the Consent Decree, a “Field Exercise” shall mean a training exercise conducted in the field to test and practice specific oil spill emergency response tactics used in the initial hours of an oil spill of at least 1,000 gallons into water. Each Field Exercise shall include (i) a deployment of select equipment and personnel to water, (ii) a review of locations downstream of a spill where containment and recovery operations can occur, (iii) implementation of one or more containment measures set forth in Enbridge’s “Inland Spill Response Guide,” (iv) implementation of one or more collection measures set forth in the same document, and (v) an After-Action Review conducted at the conclusion of the Field Exercise. For the purpose of this Consent Decree, a “Table-Top Exercise” shall mean an exercise – one that is not conducted in the field – to test and practice oil spill emergency response processes and procedures by using a hypothetical oil spill scenario. Each Table-Top exercise shall include (i) a spill scenario of at least 1,000 gallons from a pipeline in the Lakehead System located in close proximity to water, (ii) notifications of such spill to all of the government entities, including tribal authorities, that are identified in the ICPs, (iii) actions to be taken in the near-term and long-term to address the spill, (iv) the anticipated time periods for personnel and equipment to arrive at the spill site, (v) the risks that such a spill would pose to public health and the environment, and (vi) protective measures to prevent damages or injury to the local community, including evacuation procedures, as identified in the ICPs. 114 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1419 Page 119 of 225 For each Field Exercise and Table-Top Exercise, Enbridge shall send invitations to community, state, and local first responders listed in Appendix C, as well as any first responder located within 5 miles of the exercise scenario. In sending such invitations, Enbridge shall (i) provide invitees with notice at least four weeks prior to the exercise, (ii) offer to provide meals to persons who attend each exercise, and (iii) state that training will be provided at no cost to invitees, excluding travel costs. Enbridge shall provide EPA with four weeks’ notice of each Field Exercise and Table Top Exercise. EPA may observe or participate in any of the Field or Table Top Exercises. In addition to the above exercises, Enbridge shall conduct or hire a contractor to conduct Community Outreach sessions regarding the hazards of the different oils in the Lakehead System and the location of Enbridge pipelines in the community and how such pipelines are marked. Specifically, within one year of the Effective Date, and for each year thereafter until the Decree is terminated, Enbridge shall hold at least 15 Community Outreach Sessions in 15 different communities where the Lakehead System is located. Enbridge shall also provide information at the Community Outreach sessions regarding: (i) how the community should respond in the event of a spill, (ii) how the community can obtain information in the event of a spill from Enbridge and government agencies, and (iii) how the community can report spills to Enbridge, EPA, and the National Response Center. Control Point Plans Within three years after entry of the Consent Decree, except as provided in Subparagraphs 117.c and 117.d below, Enbridge shall update and maintain information for the Control Point locations set forth in Appendix D that identify containment and recovery points, as well as identify staging locations and other response-related locations, along the waters that could 115 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1420 Page 120 of 225 be impacted by a spill from a pipeline in the Lakehead System. The information for each control point shall include the information in Subparagraph 117.b below, and such information shall be organized in a format that is consistent with the example attached as Appendix E. Enbridge shall use such information to guide initial response actions and to plan and implement the Agreed Exercises and the Field Exercises required under Paragraphs 115 and 116 above. Enbridge shall provide the following for each of its Control Points identified in Appendix D: (1) Control Point information that identifies (a) the name of the water where the Control Point is located, (b) the identification of the pipeline crossing milepost closest to the Control Point, (c) the GPS coordinates of the Control Point, (d) the entry points for vehicles to gain access to the Control Point, (e) the location of the anchor points for boom deployment, (f) the location of boat launches, and (g) any other geographical information pertinent to the preplanned response action; (2) A Written Description of the Control Point that discusses (a) the width of the water during normal and high water conditions, (b) the ability of boats or vessels to operate on the water, including the type and size of boat or vessel, taking into account depth of the water column, bridge clearance, and other obstructions, (c) the velocity of the flow in the water taking into account weather and seasonal changes, and (d) other relevant characteristics of the water. In addition, Enbridge shall maintain and make available for EPA review the name and contact information of each commercial property owner or operator of each land and building where the Control Point is located; (3) A Strategic Plan that describes (a) the strategy that Enbridge plans to use at the Control Point (e.g. containment vs. exclusion booming), (b) the type and 116 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1421 Page 121 of 225 quantity of boom and other equipment needed to implement the strategy, (c) the estimated travel time for personnel and equipment to arrive at the Control Point, and (d) other issues that may impact access to, and use of, the Control Point; and (4) Photos that illustrate the information described above. With regard to the Straits of Mackinac area Control Points, no later than one year after the date of entry of this Consent Decree, Enbridge shall revise such Control Point information for the Straits of Mackinac and provide EPA with the updated information identified in Subparagraph 117.b above. Enbridge shall provide the Control Point information required in this Section for each Control Point location that is associated with an Agreed Exercise described above no later than six months prior to the initial planning meeting for the Agreed Exercise, except that Enbridge will not be required to provide this information six months in advance of the first Agreed Exercise described above, but will provide such information no later than 60 Days before the first Agreed Exercise is scheduled to occur.. Enbridge shall submit all Control Point information required in this Section to EPA in one of the following electronic formats: (i) .csv with individual IDs for each record and associated photos with linkages to that record, (ii) shape files with individual IDs for each record and associated photos with linkages to that record, (iii) .dbf with individual IDs and latitude and longitude locations for each record and associated photos with linkages to that record, (iv) or other format agreed to, in writing, by EPA and Enbridge. Once EPA has received the updated and revised Control Point Information, EPA may provide this information to the public. Enbridge may submit a notification to EPA that it plans to amend the Control Point locations identified in Appendix D. Enbridge’s notification shall identify and 117 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1422 Page 122 of 225 explain the reasons for its change. Enbridge shall include in its Semi-Annual Report: (1) a complete description of any changes to the control point location, (2) the reasons for those changes, and (3) the information required in Subparagraph 117.b for each amended control point in a format that is consistent with Appendix E. If EPA disagrees with any of Enbridge’s changes to the control point locations, EPA will notify Enbridge of its disapproval of the changed location. Within 30 Days after any EPA disapproval, Enbridge shall reinstate the original control point location that is identified in Appendix D. In addition to providing EPA with its updated Control Point information, Enbridge will provide the same documents, upon request, to USCG, PHMSA, Sub-Area Committees, state and local responders, and tribal authorities. Review of Response Times for Transport of Personnel and Equipment to Control Points and Other Locations Within three years after the Effective Date, Enbridge shall complete a review, in accordance with this Section, of Enbridge and OSRO personnel and equipment available to respond to an oil spill from the Lakehead System. The scope of Enbridge’s review shall, at a minimum, assess whether it and its OSROs can respond and meet all personnel and equipment needs within the timeframes allotted in the maps contained in the Lakehead ICPs. As part of the review required by this Section, Enbridge shall explain the methodology that it has used to estimate driving times set forth in its ICPs. Enbridge shall determine whether any other methodology might yield more accurate information and whether an appropriate additional time cushion is needed for Enbridge and OSRO personnel to reach the response location after accounting for variations in road conditions, weather, and traffic. In assessing response times for OSRO personnel, Enbridge shall review the available methodologies, 118 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1423 Page 123 of 225 including the methodology used to estimate the driving times set forth in its ICP to estimate the amount of time for OSRO personnel to drive from their homes or workplaces and arrive at an OSRO emergency response trailer (“OER Trailer”) and then travel from the OER Trailer to the response location, taking into account variations in road conditions, weather, and traffic. The result of any such review shall be revisions, to the extent needed, to ICP response time maps. Within 180 Days after completing each review of the response times contained in the ICP maps, Enbridge shall submit, electronically, to EPA for comment a draft report that discusses Enbridge’s findings, and what, if any, actions Enbridge will take based on its findings. Such draft report shall explain the methodologies used by Enbridge in conducting the review, including the methodology it used to estimate the time frames in the ICP maps. Within 90 Days after Enbridge submits the draft report to EPA, in accordance with Subparagraph 118.c, above, EPA may comment on the draft report. In the event that EPA provides comments on the draft report, Enbridge shall consider those comments in finalizing the report. In the event EPA provides comments that are not incorporated into the final report to EPA’s satisfaction, Enbridge shall include the comment(s) as an appendix to the final report. Enbridge shall complete the final report within 90 Days of receiving EPA’s comments on the draft report or, if Enbridge does not receive any comments from EPA, then no earlier than 180 Days from providing EPA with the draft report, but no later than 240 Days after providing EPA with the draft report. Upon completion of the final report, Enbridge shall provide electronic copies of the report to EPA, as well as to the Sub-Area committees, USCG, PHMSA, and Enbridge’s OSROs. 119 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1424 Page 124 of 225 Coordination with Governmental Planners After the Effective Date, Enbridge shall attend and participate in all planning meetings that are held by the Buffalo, NY Area Committee and the following Sub-Area Committees: Chicago, Detroit, Duluth/Houghton, NW Indiana, Red River, Sault Ste. Marie, and W. Michigan, provided that Enbridge receives an invitation to the planning meeting at least four weeks in advance of the meeting date. Enbridge may attend and participate in such meetings by teleconference, if available, otherwise Enbridge shall participate in person. Enbridge shall become an active member of at least one sub-committee if it is invited by a Sub-area Committee or the Area Committee identified above. Within one year after the Effective Date, and for each year thereafter, Enbridge shall participate in the following activities organized by each Sub-Area. (1) Field Exercise: Enbridge shall participate in at least one Field Exercise if it is invited by a Sub-Area Committee but has no obligation to attend more than one Field Exercise in each Sub-Area, even if it receives multiple invitations. For the purposes of this provision, the term “Field Exercise” shall have the same meaning that it does in Paragraph 116.b. The Field Exercises required by this Subparagraph are in addition to the Field Exercises that Enbridge must implement pursuant to Paragraph 116 of this Consent Decree. (2) Other Training Events: Enbridge shall participate in at least two other training events if it is invited by a Sub-Area Committee, but has no obligation to attend more than two other training events even if it receives multiple invitations. The training events required by this Subparagraph are in addition to the trainings, exercises and activities required elsewhere in this Consent Decree. 120 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1425 Page 125 of 225 In the event that a Sub-Area Committee or Area Committee for the Lakehead System makes written recommendations to Enbridge regarding its emergency preparedness plans and implementation, Enbridge shall respond in writing within 90 Days of receipt of such recommendations and submit an electronic copy of the response to EPA. In the event that Enbridge receives a request to meet and discuss response planning strategies to ensure consistency with the Area Plan, Enbridge shall agree to such a meeting at a mutually convenient time, provided that the request is made by EPA, PHMSA, USCG, tribal representatives, or state or local authorities. Within 2 months after the Effective Date, Enbridge shall provide a redacted electronic copy of the ICPs for the Lakehead System together with a redacted electronic copy of the “Straits of Mackinac Tactical Response Plan,” to the Area Committees and the Sub-Area Committees identified in Subparagraph 119.a. Upon request, Enbridge shall provide an unredacted electronic copy of the ICPs for the Lakehead System and/or an unredacted electronic copy of the “Straits of Mackinac Tactical Response Plan,” to EPA. Within 30 Days after the Effective Date, Enbridge shall submit to EPA and each of the Sub-Area Committees and the Area Committee identified in Subparagraph 119.a, electronically, for the Lakehead System a map showing the locations of Enbridge’s prepositioned emergency response equipment and materials for the Lakehead System. For each location, Enbridge shall also provide the complete inventory of all prepositioned emergency response equipment and materials. As of the Effective Date, Enbridge will coordinate with EPA, and the Area Committee and the Sub-Area Committees identified in Subparagraph 119.a, to identify potential 121 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1426 Page 126 of 225 measures to improve response times in the Lakehead System. Enbridge shall maintain, in good working order, any prepositioned emergency response equipment and materials, and shall replace any such prepositioned emergency response equipment and materials that are expired or used and cannot be reused within 30 calendar days after its expiration or use. In the event that Enbridge makes a modification to the inventory at a prepositioned location by adding or subtracting prepositioned emergency response equipment or materials, or by changing the type of such equipment or materials, Enbridge shall provide electronic written notice of the changes, on an annual basis, to EPA and to each of the Sub-Area Committees and the Area Committee. As of the Effective Date, Enbridge shall maintain on its website, publicly available, copies of its “Inland Spill Response Guide.” Upon request, Enbridge shall provide a copy of the “Inland Spill Response Guide” to EPA. All documents that Enbridge is required to provide under this Paragraph 119 must be provided electronically. Enbridge shall provide documents electronically within fourteen business days of any request, unless otherwise stated in the request or as otherwise required by law or regulation. With respect to the map that Enbridge shall provide under this Subparagraph 119.g, Enbridge shall provide the map in one of the following electronic formats: (a) .csv with individual IDs for each record and associated photos with linkages to that record, (b) shape files with individual IDs for each record and associated photos with linkages to that record, (c) .dbf with individual IDs, latitude and longitude for each record and associated photos with linkages to that record, or (d) other format agreed to, in writing, by EPA and Enbridge. Incident Command System Training 122 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1427 Page 127 of 225 Prior to being listed as an Incident Commander, Deputy Incident Commander or Alternate Incident Commander of any Enbridge Regional Incident Management Team (“RIMT”) in any Lakehead ICP, and before participating in any spill response or exercise as a member of the RIMT, all such personnel shall have completed Incident Command System (“ICS”) Level 100B through Level 400 and position-specific training for the position in which they will serve. All other personnel listed as a member of any Enbridge RIMT in any Lakehead ICP shall have completed ICS Level 100B through Level 300 and position-specific training for the position in which they will serve prior to being listed as a member of any Enbridge RIMT in any Lakehead ICP and prior to participating in any spill response or exercise. Prior to being designated as a Regional Emergency Response Coordinator, all such personnel shall have completed ICS Level 100B through 400 training. All emergency management departmental staff shall have completed ICS Level 100B through 300 training within 90 Days after being assigned as emergency management departmental staff. Any person who is designated as Enbridge’s Vice President of U.S. Operations, or in an equivalent capacity, shall have completed ICS Level 402 training within 90 Days after such designation. Any other manager or executive who gives direction to field personnel, or is responsible for making funding, personnel, or resource decisions during a spill response, and has not taken ICS Level 100B through 400 training, shall have completed ICS Level 402 training prior to being assigned such responsibilities. All such training must be in accordance with the FEMA recommendations and all training shall be conducted by National Incident Management System (“NIMS”) certified instructors. After the Effective Date, Enbridge shall ensure that each ICS role for all four Lakehead Regional Response Zones is filled with a person who has met these training requirements. 123 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1428 Page 128 of 225 After the Effective Date, each person assigned to takeover an ICS role , or takeover as an alternate for such a role, shall complete this training prior to beginning such duties. Within 365 Days after the Effective Date, Enbridge shall train at least one Enbridge employee for each Incident Management Team position. The requirements in this Paragraph 120 shall apply to all RIMT personnel, irrespective of whether such personnel are employed directly by Enbridge, by a related entity, or by a third-party contractor and to the managers and executives identified in Subparagraph 120.a, and to at least one group of personnel employed directly by Enbridge who must be trained to serve as a RIMT member. Enbridge shall maintain electronic certification documents to confirm personnel training and make these documents available to EPA upon request. Training records shall include the name, title, RIMT assigned role, and date of each ICS training level for each employee. I. NEW REMOTELY CONTROLLED VALVES Within the period of the Consent Decree, Enbridge shall install 14 new Remotely Controlled Valves on the Lakehead System for the purpose of minimizing the volume of oil that can be released into the environment in the event of a rupture or leak. Enbridge shall install the 14 new Remotely Controlled Valves on three Lakehead System Pipelines – namely, Line 5, Line 6A, and Line 14. For each pipeline, Enbridge shall install a new valve between each pair of valves shown in the chart below. Line 5 New Valve Reference # 1 2 New Valve to be Installed Between Valve at Milepost Valve at Milepost 1406.45 1422.97 124 1422.97 1439.71 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1429 Page 129 of 225 Line New Valve Reference # 6A 14 3 4 5 6 7 8 9 10 11 12 13 14 New Valve to be Installed Between Valve at Milepost Valve at Milepost 1465.50 1479.75 1515.11 1592.12 1613.93 1704.74 70.09 190.63 425.95 456.03 419.67 403.50 1475.63 1496.64 1532.11 1613.93 1636.71 1721.43 88.18 201.24 437.52 465.39 437.76 417.92 In selecting the exact location of each valve, Enbridge shall use computer modeling to assess different locations and estimate the volume of oil that will likely be released from each location in the event of rupture, taking into account elevation, line pressure, and other pertinent factors. In addition, Enbridge should apply dispersion modeling to estimate where oil will likely travel in the event of a rupture. Based upon these analyses, Enbridge shall install each Remotely Controlled Valve at the location that best advances the goals of (1) reducing the volume of oil released from the pipeline in the event of a discharge, (2) protecting waterbodies, wetlands, and other sensitive habitat from oil, and (3) minimizing the impact to environmental resources caused by construction activities to install the Sectionalizing Valve. Enbridge shall design, install, and operate each Remotely Controlled Valve so that valve can be opened or closed remotely by an operator in Enbridge’s Control Room. Each valve shall fully close and seal within three minutes of the operator engaging the valve-closure control on his or her control panel. 125 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1430 Page 130 of 225 J. INDEPENDENT THIRD PARTY CONSENT DECREE COMPLIANCE VERIFICATION Enbridge will retain, at its expense, an Independent Third Party to conduct a comprehensive verification of Enbridge’s compliance with the requirements set forth in this Section VII (Injunctive Measures) of the Consent Decree, except the Independent Third Party shall not be responsible for assessing Enbridge’s compliance with requirements in Subsection VII.H (Spill Response and Preparedness). In addition, the Independent Third Party shall, at Enbridge’s expense, perform the tasks set forth in this Section VII.J. The Independent Third Party shall act independently and objectively when performing third-party services set forth in Paragraph 125. Enbridge will provide the Independent Third Party with full access to all facilities that are part of Enbridge’s Lakehead System, and provide or otherwise make available any necessary personnel, documents, and databases to fully perform all activities and services required under Paragraph 125. Within 15 Days of the Effective Date, Enbridge shall submit to the United States a list of candidates to serve as Independent Third Party. If practicable, the list shall include at least three candidates, but in no event shall Enbridge propose less than two candidates. Except as set forth in Paragraph 128, Enbridge shall certify that each candidate meets the conditions set forth in Subparagraphs 127.a - e below. If requested, Enbridge shall provide resumes, biographical information, and other relevant material concerning the candidates, including information on the relationship between Enbridge and the candidates. The Independent Third Party and its personnel have demonstrated experience in pipeline integrity and operations, and have the appropriate education to provide the third-party services identified in Paragraph 125; 126 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1431 Page 131 of 225 The Independent Third Party and its personnel have not conducted research, development, design, construction, financial, engineering, legal, consulting or any other advisory services for Enbridge within the last three years; The Independent Third Party has not been involved in the development of Enbridge’s control room, leak detection or pipeline integrity procedures that are the subject of this Consent Decree; The Independent Third Party will not provide commercial, business or voluntary services to the Enbridge, excluding services provided in its capacity as Independent Third Party, for the life of the Consent Decree and for a period of at least three years following termination of the Consent Decree; and Enbridge will not provide future employment to any of the Independent Third Party’s personnel who conducted or otherwise participated in verification services under this Consent Decree for a period of at least three (3) years following termination of the Consent Decree. In the event that Enbridge is not able to certify that a candidate meets all the conditions in Subparagraphs 127.a- e and if Enbridge is unable, after extensive efforts, to identify an alternative candidate that would satisfy such conditions, Enbridge shall submit to the United States: (a) an explanation of its efforts to find an alternative candidate, (b) the name of an alternative candidate that does not completely meet all the independence requirements in Subparagraphs 127.a - e with an explanation of specifically which conditions are not being met and the reasons why they are not being met, and (c) a Conflict of Interest Mitigation Plan for how Enbridge will ensure that such candidate, if selected as the Independent Third Party, would still have sufficient independence to objectively and competently perform the obligations set forth in 127 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1432 Page 132 of 225 this Consent Decree. Cost alone is not a reason to allow a deviation from the conditions in Paragraph 127. The United States will review each alternative candidate proposed by Enbridge to determine whether such candidate is acceptable. If the United States determines the party is not acceptable, the United States may demand that Enbridge identify another candidate, in which event Enbridge shall, within 60 Days of receipt of such demand, either comply with the demand or pursue Dispute Resolution under the terms of this decree. The United States will notify Enbridge in writing whether it approves one or more of the proposed candidates to serve as the Independent Third Party. Within 30 Days of the United States’ approval, Enbridge shall retain one of the approved candidates to serve as the Independent Third Party. If the United States rejects all of the candidates proposed by Enbridge to serve as the Independent Third Party, within 60 Days of receipt of the United States’ notification, Enbridge shall submit to the United States for approval another list of candidates to serve as the Independent Third Party. In submitting the new list of candidates, Enbridge shall comply with the requirements set forth in Paragraphs 127 and 128. The United States shall review the proposed replacement in accordance with Paragraph 129 and this Paragraph 130. Enbridge shall provide EPA with a copy of Enbridge’s agreement with the Independent Third Party within 5 Days of the execution of the agreement. In the agreement, Enbridge shall require the Independent Third Party to perform the tasks set forth in Paragraphs 132 and 133 below. The retention agreement shall also include the requirements set forth in Paragraph 134 below. 128 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1433 Page 133 of 225 Enbridge’s written agreement with the Independent Third Party shall explicitly require the Independent Third Party to perform all of the tasks assigned to the Independent Third Party in this Consent Decree, including: Task 1 -- Initial Project Planning Meeting with Region 5 in Chicago. Within 60 Days of the entry of this Consent Decree by the court, the Independent Third Party shall meet with EPA to provide an overview and detailed project plan of how it plans to perform all of its obligations in this Consent Decree. The Independent Third Party shall bring its key personnel to such meeting, including the lead manager and senior staff involved in implementing its obligations. A representative of Enbridge may attend this meeting. Task 2 – Review of Plans, Reports, and Other Deliverables: The Independent Third Party shall review and evaluate all proposed plans, reports, and other deliverables that Enbridge is required to submit under this Consent Decree, except the Independent Third Party shall not review submittals (or portions of submittals) relating to spill response and preparedness. With respect to each submittal that the Independent Third Party is required to review, the Independent Third Party shall evaluate the completeness of the submittal and its compliance with the requirements of the Consent Decree. If requested by EPA, the Third Party shall also prepare and provide EPA with a written report of its evaluation. In the event that the submittal requires action by EPA under Paragraph 137 (Approval of Deliverables), the Independent Third Party shall make a recommendation to EPA as to the action it should take, as well as prepare documentation in support of such recommendation. The Independent Third Party shall complete all of the requirements of this Task within 45 Days of receipt of a request from EPA. 129 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1434 Page 134 of 225 Task 3 – Review of Implementation of Compliance Measures. The Independent Third Party shall review and evaluate Enbridge’s compliance with all requirements set forth in this Section VII of the Consent Decree, except those requirements listed in Subsection VII.H (Spill Response and Preparedness). The Independent Third Party shall complete its initial review within 16 months after the Effective Date of the Consent Decree. Upon request by EPA, it shall conduct further reviews periodically until the Consent Decree is terminated under Section XX (Termination). In conjunction with each review, the Independent Third Party shall prepare a verification report in accordance with Paragraph 133 below. In the event that EPA is unable to determine Enbridge’s compliance with the Consent Decree based upon the information that is available to EPA, EPA may request that the Independent Third Party collect and provide additional information for the purpose of enabling EPA to confirm Enbridge’s compliance. Task 4 – Review of Claims of Force Majeure and Other Requests for Extension of Time: The Independent Third Party shall review all requests or demands by Enbridge for additional time to complete the requirements under Section VII of the Consent Decree, upon request from EPA, although the Independent Third Party shall not review such requests with respect to requirements listed in Subsection VII.H (Spill Response and Preparedness). In the event that Enbridge claims that it is entitled to additional time under Section XII (“Force Majeure”), the Independent Third Party shall, upon request from EPA, review all information provided by Enbridge and make a recommendation to EPA within 72 hours as to whether Enbridge’s claim is supported by the underlying facts, technology, business needs, and any constraints beyond the control of Enbridge. Otherwise, the Independent Third Party shall provide a recommendation to EPA, upon request from EPA within ten Days of receipt 130 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1435 Page 135 of 225 of Enbridge’s request for additional time. The Independent Third Party shall prepare written documentation in support of its recommendations to EPA within the time frames set forth above in this Task and make such documentation available to EPA upon request. Task 5 – Requests for Modification of the Consent Decree: The Independent Third Party shall, upon request from EPA, review all requests by Enbridge for changes to requirements under Section VII of the Consent Decree, unless the proposed changes relate to requirements listed in Subsection VII.H (Spill Response and Preparedness). The Independent Third Party shall provide a recommendation to EPA within 21 Days of receipt of the request of EPA’s request for review. The Independent Third Party shall prepare within the same 21-Day period written documentation in support of its recommendations to EPA and make such documentation available to EPA upon request. Verification Report: In accordance with the schedule set forth under Subparagraph 132.c, above, the Independent Third Party shall prepare a written report, entitled “Verification Report,” that sets forth findings, conclusions and recommendations, if any, as to each of the requirements in this Section VII of the Consent Decree, excluding requirements listed in Subsection VII.H (Spill Response and Preparedness). In preparing the report, the Independent Third Party shall consider the Semi-Annual Reports submitted by Enbridge under Section IX (Reporting Requirements) of the Consent Decree, but the Independent Third Party may consider additional information collected from information requests or visits to Enbridge’s facilities. The Verification Report shall list all information considered by the Independent Third Party, all persons interviewed by the Independent Third Party, and summarize any relevant oral communications which occurred 131 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1436 Page 136 of 225 between the Independent Third Party and Enbridge. Upon completion of each Verification Report, the Independent Third Party shall submit the report concurrently to EPA and Enbridge. Within 90 Days of receiving a Verification Report, Enbridge shall submit to EPA a response to all findings, conclusions and recommendations set forth in the Verification Report. To the extent that Enbridge concurs with a finding or conclusion that Enbridge is in noncompliance with the Consent Decree or that it has yet to complete a requirement, Enbridge shall state whether it agrees with the recommended actions for achieving compliance, as well as whether it agrees with the recommended schedule for completing those actions. Alternatively, in the event Enbridge disagrees with any of the Independent Third Party’s findings or conclusions, Enbridge shall explain the basis for the disagreement and propose changes to the Verification Report that would address its concern. In either event, to the extent that Enbridge disagrees with any aspect of the Independent Third Party’s recommendations for corrective action, Enbridge shall propose its own corrective actions, as well as its own schedule for completing those actions. Within 30 Days of receipt of Enbridge’s response, the Independent Third Party shall submit a reply to Enbridge and EPA that addresses each of the issues raised by Enbridge. To the extent that the Independent Third Party concurs with Enbridge’s response, the Independent Third Party shall provide EPA and Enbridge with a revised and corrected Verification Report. EPA shall not be bound by the Verification Report as revised and corrected by the Independent Third Party. EPA may accept or reject, in whole or in part, the Independent Third Party’s findings, conclusions, and recommendations. If EPA determines that Enbridge is in violation of any requirement subject to stipulated penalties under Section XI (Stipulated Penalties), Enbridge shall be liable for such penalties, regardless of the Verification Report, 132 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1437 Page 137 of 225 unless Enbridge successfully challenges the assessment of stipulated penalties under Section XIII (Dispute Resolution). Likewise, if EPA determines that Enbridge must take certain actions to achieve compliance with the Consent Decree, Enbridge shall perform all such actions, and it shall do so in accordance with the schedule set by EPA, regardless of the Verification Report, unless Enbridge successfully challenges the actions or the schedule under Section XIII (Dispute Resolution). General Requirements: In addition to the tasks set forth in Paragraphs 132 and 133 above, Enbridge’s written agreement with the Independent Third Party shall explicitly require the following: The Independent Third Party owes a duty to the United States to provide objective and fair assessment of Enbridge’s compliance with the Consent Decree. The Independent Third Party shall provide notice within two Days to Enbridge and the United States in the event that the Independent Third Party is unable to continue to serve as the Independent Third Party under this Consent Decree. Enbridge may terminate the agreement only for good cause shown and with consent of the United States. The Independent Third Party shall provide EPA with an advance schedule of any on-site visits, telephone calls, or other meetings with Enbridge or its agents or contractors and shall invite EPA to participate in person or by teleconference. The Independent Third Party shall simultaneously provide Enbridge with a copy of any such advance schedule. The Independent Third Party must assess whether Enbridge’s Semi-Annual Reports and other submittals pursuant to the Consent Decree are supported by the facts and best engineering judgment. 133 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1438 Page 138 of 225 The Independent Third Party shall concurrently share any draft or preliminary findings or reports in any format (electronic or paper) with all of the Parties. Prior to hiring a subcontractor to perform any of the tasks identified in Paragraph 132 and 133 above, the Independent Third Party shall: (i) ensure that the subcontractor meets all the conditions and requirements set forth in Paragraph 127, except as provided in Subparagraph 134.h below, (ii) comply with all requests by Enbridge or the United States for resumes, biographical information, and other relevant material concerning the subcontractor, and (iii) seek and obtain approval of the subcontractor by the United States. To the extent the Independent Third Party is unable to identify a subcontractor that meets all the conditions and requirement set forth in Paragraph 127, after extensive efforts to identify such a party, the Independent Third Party shall submit to the United States: (i) an explanation of its efforts to find such a subcontractor, (ii) a proposal for an alternative subcontractor that does not completely meet all the independence requirements in Paragraph 127 with an explanation of specifically which conditions are not being met, and (iii) a Conflict of Interest Mitigation Plan for how the Independent Third Party will ensure that such a subcontractor will still have sufficient independence to objectively and competently perform the obligations set forth in this Consent Decree. Cost alone is not a reason to allow a deviation from the conditions in Paragraph 127. The United States will review the Independent Third Party’s proposed alternative subcontractor and will determine whether the proposed subcontractor is acceptable. If the United States determines the proposed subcontractor is not acceptable, then the Independent Third Party shall submit a different party for review and acceptance. The Independent Third Party shall ensure that no personnel and/or subcontractors assigned to provide verification services in connection with the Consent Decree 134 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1439 Page 139 of 225 will seek or obtain employment by Enbridge for the life of the Consent Decree and for at least three years following termination of the Consent Decree. The Independent Third Party and/or its subcontractors shall not provide commercial, business or voluntary services to Enbridge, excluding services provided in its capacity as the Independent Third Party, for a period of at least three years following termination of the Consent Decree. The Independent Third Party shall disclose to the United States any conflicts of interests for it or its subcontractors that may arise with respect to its review and verification of Enbridge’s compliance with the Consent Decree. In the event of a conflict, the Independent Third Party shall take any and all action to resolve such conflict. The Independent Third Party and its subcontractors shall annually certify to the United States its compliance with Subparagraphs 134,g - k. The Verification Report, or any information developed or findings or recommendations of the Independent Third Party, shall not be subject to any privilege or protection. Enbridge shall enforce the terms of its written agreement with the Independent Third Party to ensure compliance with this Section VII.J. Independent Third Party Replacement: Within 30 Days of receipt of notice that the Independent Third Party is no longer able to perform the duties set forth in this Subsection VII.J, Enbridge shall propose a replacement Independent Third Party and the United States shall approve or reject the proposed Independent Third Party replacement in accordance with the procedures and requirements set forth in Paragraphs 127 to 130, above. Within 30 Days of the United States’ approval of a replacement, Enbridge shall retain the Independent Third Party to 135 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1440 Page 140 of 225 perform the remaining tasks set forth in Paragraphs 132 and 133, above. Enbridge’s retention agreement with the Independent Third Party shall also include the requirements set forth in Paragraph 134 and shall comply with this Section VII.J, generally. Within 5 Days of its execution, Enbridge shall provide to EPA a copy of Enbridge’s agreement with the replacement Independent Third Party. REVIEW AND APPROVAL OF DOCUMENTS Approval of Deliverables. After review of any plan, report, or other item that is required to be submitted for approval pursuant to this Consent Decree, EPA shall in writing: (a) approve the submission, (b) approve the submission upon specified conditions, (c) approve part of the submission and disapprove the remainder, or (d) disapprove the submission. If the submission is approved pursuant to Paragraph 137.(a), Enbridge shall take all actions required by the plan, report, or other document, in accordance with the schedules and requirements of the plan, report, or other document, as approved. If the submission is conditionally approved or approved only in part pursuant to Paragraph 137.(b) or 137.(c), Enbridge shall, upon written direction from EPA, take all actions required by the approved plan, report, or other item that EPA determines are technically severable from any disapproved portions, subject to Enbridge’s right to dispute only the specified conditions or the disapproved portions, under Section XIII (Dispute Resolution). If the submission is disapproved in whole or in part pursuant to Paragraph 137.(c) or 137.(d), Enbridge shall, within 45 Days or such other time as the Parties agree to in writing, correct all deficiencies and resubmit the plan, report, or other item, or disapproved portion thereof, for approval, in accordance with the preceding Paragraphs. If the resubmission is approved in whole or in part, Enbridge shall proceed in accordance with the preceding Paragraph. 136 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1441 Page 141 of 225 Any stipulated penalties and Interest applicable to the original submission, as provided in Section XI, shall continue to accrue during the forty-five Day period or other specified period, but shall not be payable unless the resubmission is untimely or is disapproved in whole or in part; provided that, if the original submission was so deficient as to constitute a material breach of Enbridge’s obligations under this Decree, the stipulated penalties applicable to the original submission shall be due and payable notwithstanding any subsequent resubmission. If a resubmitted plan, report, or other item, or portion thereof, is disapproved in whole or in part, EPA may again require Enbridge to correct any deficiencies, in accordance with the preceding Paragraphs, subject to Enbridge’s right to invoke Dispute Resolution and the right of EPA to seek stipulated penalties as provided in the preceding Paragraphs. Permits. Where any compliance obligation under this Consent Decree requires Enbridge to obtain a federal, state, or local permit or approval, Enbridge shall submit timely and complete applications and take all other actions necessary to obtain all such permits or approvals. Enbridge may seek relief under the provisions of Section XII (Force Majeure) for any delay in the performance of any such obligation resulting from a failure to obtain, or a delay in obtaining, any permit or approval required to fulfill such obligation, if Enbridge has submitted timely and complete applications and has taken all other actions necessary to obtain all such permits or approvals. REPORTING REQUIREMENTS Defendants shall prepare and submit to EPA, electronically and in writing, on a semi-annual basis, a report documenting Enbridge’s compliance with the Consent Decree (“SemiAnnual Report”). The first Semi-Annual Report, which shall be submitted by Enbridge not later than 240 Days after the Effective Date, shall document activities over the first six months after the 137 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1442 Page 142 of 225 Effective Date. Enbridge shall submit the second report, documenting compliance over the next six months, no later than six months after its first report is due. Enbridge shall thereafter continue to submit the Semi-Annual Reports on a rolling six-month basis until termination of the Consent Decree under Section XX (Termination). Enbridge shall include in the Semi-Annual Report all information that is expressly required under Paragraphs 29, 31, 49, 96, and 110.c of the Consent Decree. In addition, Enbridge shall summarize and discuss the status of compliance with respect to all other requirements in Subsections VII.A-J (Injunctive Measures). Specifically, with respect to each requirement, Enbridge shall discuss such matters as completion of milestones, problems encountered or anticipated in implementing the requirement (together with implemented or proposed solutions), status of permit applications, operation and maintenance issues, reports to state agencies, number, by types, of features repaired or mitigated during the reporting period and the number, by type, planned for future repair or mitigation, and any significant changes or issues since the previous Semi-Annual Report. In the event that Enbridge failed to comply with any requirement or deadline under this Consent Decree during the reporting period for the Semi-Annual Report, or if Enbridge anticipates that it will violate a requirement at any time in the future, Enbridge shall identify the likely cause (or causes) of the non-compliance, the facts and circumstance that led (or will lead) to such an event, the remedial steps taken (or to be taken) to rectify the non-compliance, the dates that such steps were taken (or will be taken), the date they complied or will comply with the requirement, and the plan for ensuring that non-compliance is not repeated elsewhere in the future. 138 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1443 Page 143 of 225 Each Semi-Annual Report shall identify each discharge from a Lakehead System Pipeline of one or more barrels of oil, as well as any discharge of oil that reaches any waterbody or waters of the United States or adjoining shorelines in a quantity as may be harmful. This portion of the report shall list: Spill date; National Response Center identification number (if applicable); Narrative description of spill location, cause of the spill; spill material, and quantity of spill; Distance spill traveled; Sheen, sludge or emulsion observed; Name of water that spill entered (if applicable); Identification of any water quality standard that was exceeded/violated; Descriptions of actions taken or planned to address spill and prevent future spills and schedule for future actions; Description of any environmental impacts from spill; and The root cause of the spill, provided, however, that if the root cause of the spill is not known at the time a Semi-Annual Report is due, Enbridge shall report the root cause of the spill in the next Semi-Annual Report. Each Semi-Annual Report shall include an update on oil spills reported in previous Semi-Annual Reports, including revisions to volume spills and status of actions taken to address the spill, including actions taken to prevent future spills from similar causes and costs. Each Semi-Annual Report shall include copies of all Post Incident Reports generated during the semi-annual period if not previously provided upon request. 139 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1444 Page 144 of 225 Emergency Report: Enbridge shall notify EPA as soon as possible, but no later than 24 hours after Enbridge first knows of any circumstance relating to its performance under the Decree that may pose an immediate threat to public health or welfare or the environment. This procedure is in addition to the other reporting requirements set forth in this Section IX. Enbridge shall submit all reports under this Section IX in accordance with Section XVI (Notices). Whenever Enbridge is required to submit information to EPA pursuant to any section of this Consent Decree except Section VII.H (Spill Response and Preparedness), Enbridge must simultaneously submit the same information to the Independent Third Party. The reporting requirements of this Consent Decree do not relieve Enbridge of any reporting obligations required by the Clean Water Act, the Pipeline Safety Act, the Oil Pollution Act, or their implementing regulations, or by any other federal, state, or local law, regulation, permit, or other requirement. Any information provided pursuant to this Consent Decree may be used by the United States in any proceeding to enforce the provisions of this Consent Decree and as otherwise permitted by law. Each report or written notice submitted by Enbridge under this Section (not including an emergency report under Paragraph 149) shall be signed by a corporate official and include the following certification: I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on any personal knowledge I may have and my inquiry of the person or persons who manage the system or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that 140 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1445 Page 145 of 225 there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations. Claims of Confidentiality In making any submittal under this Consent Decree, Enbridge may claim that submittal, in whole or in part, contains confidential business information (“CBI”) or other information protected by statute. If Enbridge makes such a claim, Enbridge shall: (i) include with the submittal a redacted (or revised) version of the submittal (“Redacted Submittal”) that EPA may publicly release, and (ii) provide an explanation of each basis for its assertion that the submittal contains CBI or other protected information. EPA may accept or reject, in whole or in part, Enbridge’s claim that a submittal contains CBI or other information protected by statute. To the extent that EPA does not accept Enbridge’s claim, EPA may decide that the Redacted Submittal is adequate for public disclosure purposes or, alternatively, may ask Enbridge to consent to certain changes to the Redacted Submittal. In either event, EPA shall not publicly release any portion of the submittal subject to Enbridge’s claim of confidentiality unless and until EPA rejects such a claim in accordance with the procedures set forth in its regulations at 40 C.F.R. Part 2. In the event that EPA finds that the report does not contain CBI or other protected information, Enbridge shall have the opportunity to challenge that determination in accordance with EPA’s regulations. INFORMATION COLLECTION AND RETENTION The United States and its representatives, including attorneys, contractors, and consultants, shall have the right of entry, upon presentation of credentials, to any part of the Lakehead System for the purpose of: a. monitoring the progress of activities required under this Consent Decree; 141 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1446 Page 146 of 225 b. verifying any data or information submitted to the United States in accordance with the terms of this Consent Decree; c. obtaining documentary evidence, including photographs and similar data; d. assessing Enbridge’ compliance with this Consent Decree. and/or Until five years after the termination of this Consent Decree, Enbridge shall retain, and shall instruct its contractors and agents to preserve, all non-identical copies of all documents, records, or other information (including documents, records, or other information in electronic form) in its or its contractors’ or agents’ possession or control, or that come into its or its contractors’ or agents’ possession or control, and that relate in any manner to Enbridge’s performance or implementation of their obligations under this Consent Decree, including all underlying documents and records from which it has compiled any documents, reports, notices or submissions required by this Consent Decree. This information-retention requirement shall apply regardless of any contrary corporate or institutional policies or procedures. At any time during this information-retention period, upon request by the United States, Enbridge shall provide copies of any documents, records, or other information required to be maintained under this Paragraph. At the conclusion of the information-retention period provided in the preceding Paragraph, Enbridge shall notify the United States, pursuant to Section XVI (Notices) at least 90 Days prior to the destruction of any documents, records, or other information subject to the requirements of the preceding Paragraph and, upon request by the United States, Enbridge shall deliver any such documents, records, or other information to the United States. Enbridge may assert that certain documents, records, or other information is privileged under the attorney-client 142 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1447 Page 147 of 225 privilege or any other privilege recognized by federal law. If Enbridge asserts such a privilege, they shall provide the following: (a) the title of the document, record, or information; (b) the date of the document, record, or information; (c) the name and title of each author of the document, record, or information; (d) the name and title of each addressee and recipient; (e) a description of the subject of the document, record, or information; and (f) the privilege asserted by Enbridge. However, no documents, records, or other information created or generated pursuant to the requirements of this Consent Decree shall be withheld on grounds of privilege. Enbridge may also assert that information required to be provided under this Section is protected as Confidential Business Information (“CBI”) under 40 C.F.R. Part 2. As to any information that Enbridge seeks to protect as CBI, Enbridge shall follow the procedures set forth in 40 C.F.R. Part 2 and Paragraph 155. This Consent Decree in no way limits or affects any right of entry and inspection, or any right to obtain information, held by the United States pursuant to applicable federal laws, regulations, or permits, nor does it limit or affect any duty or obligation of Enbridge to maintain documents, records, or other information imposed by applicable federal or state laws, regulations, or permits. STIPULATED PENALTIES Enbridge shall be liable for stipulated penalties to the United States for violations of this Consent Decree as specified below, unless excused under Section XII (Force Majeure). A violation includes failing to perform any obligation required by the terms of this Decree, including any plan or schedule approved under this Decree, according to all applicable requirements of this Decree and within the specified time schedules established by or approved under this Decree. 143 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1448 Page 148 of 225 Late Payment of Civil Penalty: If Enbridge fails to pay the civil penalty and Interest required to be paid under Section V (Civil Penalty) when due, Enbridge shall pay a stipulated penalty of $7,500 per Day for each Day that the payment is late. Late Reimbursement of Removal Costs: If Enbridge fails to reimburse the Fund for Past Removal Costs or Future Removal Costs to be reimbursed under Section VI (Payment of Removal Costs) when due, Enbridge shall pay a stipulated penalty of $7,500 per Day for each Day that the reimbursement is late. Violation of Requirements Regarding Injunctive Relief: Enbridge shall pay a stipulated penalty of $10,000 per Day for each Day that Enbridge (1) violates the injunction prohibiting use of Former Line 6B under Subsection VII of the Consent Decree or (2) violates the injunction regarding the use of the Original US Line 3 under Paragraph 22 of the Consent Decree. Enbridge shall pay a stipulated penalty of $20,000 for each incident in which Enbridge (1) violates an unscheduled shutdown procedure set forth in Paragraph 109 of the Consent Decree or (2) fails to report such violations in accordance with Paragraph 110 of the Consent Decree. Enbridge shall pay a stipulated penalty of $15,000 for each incident in which Enbridge violates the requirement in Paragraph 113 for immediate response to a confirmed leak or rupture. For any instance in which Enbridge adopted an Alternate Plan or an alternate interim pressure restriction in violation of Subparagraph 46.e or 46.f, Enbridge shall be subject to daily stipulated penalties under Subparagraph 164.e for each failure to meet applicable requirements or deadlines established in Subsection VII.D.(V). 144 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1449 Page 149 of 225 The follow stipulated penalties shall accrue per Day for each violation for failure to comply with all other requirements of Section VII (Injunctive Measures), including provisions in the Appendices: Penalty Per Violation Per Day Period of Noncompliance $ 2,000 $ 3,500 $ 5,000 1st through 14th Day 15th through 30th Day 31st Day and beyond Violation of Other Requirements of the Consent Decree: The following stipulated penalties shall accrue per Day for each violation of the requirements of this Consent Decree other than those in Section V (Civil Penalty), Section VI (Payments for Removal Costs), or Section VII (Injunctive Measures). Penalty Per Violation Per Day Period of Noncompliance $ 500 $1,000 $2,000 1st through 14th Day 15th through 30th Day 31st Day and beyond Stipulated penalties under this Section shall begin to accrue on the Day after performance is due or on the Day a violation occurs, whichever is applicable, and shall continue to accrue until performance is satisfactorily completed or until the violation ceases. Stipulated penalties shall accrue simultaneously for separate violations of this Consent Decree. Enbridge shall pay any stipulated penalty within 30 Days of receiving a written demand from the United States. If Enbridge fails to pay stipulated penalties according to the terms of this Consent Decree, Enbridge shall be liable for Interest on such penalties, accruing as of the date payment became due. The United States may in the unreviewable exercise of its discretion, reduce or waive stipulated penalties otherwise due it under this Consent Decree. 145 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1450 Page 150 of 225 Enbridge shall pay stipulated penalties and any Interest owing to the United States by EFT, in accordance with the instructions to be provided by the FLU of the U.S. Attorney’s Office for Western District of Michigan. At the time of payment, Enbridge shall send a copy of the EFT authorization form and the EFT transaction record, together with a transmittal letter, to the United States in accordance with Section XVI (Notices) of the Consent Decree, stating that the payment is for the civil penalty owed pursuant to the Consent Decree in this case, and shall reference the Civil Action Number assigned to this case and DOJ Number 90-5-1-1-10099. If Enbridge submits a Notice of Dispute in response to the written demand for payment of the stipulated penalties, Enbridge shall pay all uncontested stipulated penalties within 30 Days after Enbridge’s receipt of the bill requiring payment. Simultaneously, Enbridge shall establish, in a duly chartered bank or trust company, an interest-bearing escrow account (“Escrow Account”) that is insured by the Federal Deposit Insurance Corporation (FDIC), and remit to that Escrow Account funds equivalent to the amount of the contested stipulated penalties. Enbridge shall send to the United States, as provided in Section XVI (Notices), a copy of the transmittal letter and check paying the uncontested stipulated penalties into the Escrow Account, and a copy of the correspondence that establishes and funds the Escrow Account, including, but not limited to, information containing the identity of the bank and bank account under which the Escrow Account is established as well as a bank statement showing the initial balance of the escrow account. If the United States prevails in the dispute, Enbridge shall pay the sums due (with accrued Interest) to the United States within 7 Days after the resolution of the dispute. If Enbridge prevails concerning any aspect of the contested costs, Enbridge shall pay that portion of the Stipulated Penalties (plus associated accrued Interest) for which they did not prevail to the 146 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1451 Page 151 of 225 United States within 7 Days after the resolution of the dispute. Enbridge shall be disbursed any balance of the escrow account. Enbridge shall not deduct or capitalize stipulated penalties or Interest paid under this Section in calculating its federal income tax. Nothing in this Section shall be construed to limit the United States from seeking any remedy otherwise provided by law for Enbridge’s failure to pay any stipulated penalties. Subject to the provisions of Section XIV (Effect of Settlement/Reservation of Rights), the stipulated penalties provided for in this Consent Decree shall be in addition to any other rights, remedies, or sanctions available to the United States for Enbridge’s violation of this Consent Decree or applicable law. FORCE MAJEURE “Force Majeure,” for purposes of this Consent Decree, is defined as any event arising from causes beyond the control of Enbridge, of any entity controlled by Enbridge, or of Enbridge’s contractors, that delays or prevents the performance of any obligation under this Consent Decree despite Enbridge’s best efforts to fulfill the obligation. The requirement that Enbridge exercise “best efforts to fulfill the obligation” includes using best efforts to anticipate any potential Force Majeure event and best efforts to address the effects of any such event (a) as it is occurring and (b) following its occurrence, such that the delay and any adverse effects of the delay are minimized to the greatest extent possible. “Force Majeure” does not include Enbridge’s financial inability to perform any obligation under this Consent Decree. If any event occurs or has occurred that may delay the performance of any obligation under this Consent Decree, whether or not caused by a Force Majeure event, Enbridge shall provide notice orally or by electronic transmission to EPA, within five Days of when 147 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1452 Page 152 of 225 Enbridge first knew that the event might cause a delay. Within 10 Days thereafter, Enbridge shall provide in writing to EPA an explanation and description of the reasons for the delay; the anticipated duration of the delay; all actions taken or to be taken to prevent or minimize the delay; a schedule for implementation of any measures to be taken to prevent or mitigate the delay or the effect of the delay; Enbridge’s rationale for attributing such delay to a Force Majeure event if it intends to assert such a claim; and a statement as to whether, in the opinion of Enbridge, such event may cause or contribute to an endangerment to public health, welfare, or the environment. Enbridge shall include with any notice all available documentation supporting the claim that the delay was attributable to a Force Majeure. Failure to comply with the above requirements shall preclude Enbridge from asserting any claim of Force Majeure for that event for the period of time of such failure to comply, and for any additional delay caused by such failure. Enbridge shall be deemed to know of any circumstance of which Enbridge, any entity controlled by Enbridge, or Enbridge’s contractors knew or should have known. If EPA agrees that the delay or anticipated delay is attributable to a Force Majeure event, the time for performance of the obligations under this Consent Decree that are affected by the Force Majeure event will be extended by EPA for such time as is necessary to complete those obligations. An extension of the time for performance of the obligations affected by the Force Majeure event shall not, of itself, extend the time for performance of any other obligation. EPA will notify Enbridge in writing of the length of the extension, if any, for performance of the obligations affected by the Force Majeure event. If EPA does not agree that the delay or anticipated delay has been or will be caused by a Force Majeure event, EPA will notify Enbridge in writing of its decision. 148 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1453 Page 153 of 225 If Enbridge elects to invoke the dispute resolution procedures set forth in Section XIII (Dispute Resolution) in response to EPA’s determination in Paragraph 177, it shall do so no later than 30 Days after receipt of EPA's notice. In any such proceeding, Enbridge shall have the burden of demonstrating by a preponderance of the evidence that the delay or anticipated delay has been or will be caused by a Force Majeure event, that the duration of the delay or the extension sought was or will be warranted under the circumstances, that best efforts were exercised to avoid and mitigate the effects of the delay, and that Enbridge complied with the requirements of Paragraphs 174 and 175. If Enbridge carries this burden, the delay at issue shall be deemed not to be a violation by Enbridge of the affected obligation of this Consent Decree identified to EPA and the Court. DISPUTE RESOLUTION Except with respect to matters committed to EPA’s sole discretion under this Consent Decree, or unless otherwise expressly provided for in this Consent Decree, (a) any dispute arising under this Consent Decree, including but not limited to any dispute as to whether Enbridge is subject to Stipulated Penalties under this Consent Decree shall be subject to this Section XIII (Dispute Resolution), and (b) the dispute resolution procedures of this Section shall be the exclusive mechanism to resolve disputes arising under or with respect to this Consent Decree. Enbridge’s failure to seek resolution of a dispute under this Section shall preclude Enbridge from raising any such issue as a defense to an action by the United States to enforce any obligation of Enbridge arising under this Decree. Informal Dispute Resolution. Any dispute subject to Dispute Resolution under this Consent Decree shall first be the subject of informal negotiations. The dispute shall be considered to have arisen when Enbridge sends the United States a written Notice of Dispute. 149 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1454 Page 154 of 225 Such Notice of Dispute shall state clearly the matter in dispute. The period of informal negotiations shall not exceed 20 Days from the date that the Notice of Dispute is submitted to the United States by Enbridge, unless that period is modified by written agreement of the Parties. If the Parties cannot resolve a dispute by informal negotiations, then the position advanced by the United States shall be considered binding unless, within 20 Days after the conclusion of the informal negotiation period, Enbridge invokes formal dispute resolution procedures as set forth below. Formal Dispute Resolution. Enbridge shall invoke formal dispute resolution procedures, within the time period provided in the preceding Paragraph, by serving on the United States a written Statement of Position regarding the matter in dispute. The Statement of Position shall include, but need not be limited to, any factual data, analysis, or opinion supporting Enbridge’s position and any supporting documentation relied upon by Enbridge. The United States shall serve its Statement of Position within 45 Days of receipt of Enbridge’s Statement of Position. The United States’ Statement of Position shall include, but need not be limited to, any factual data, analysis, or opinion supporting that position and any supporting documentation relied upon by the United States. The United States’ Statement of Position shall be binding on Enbridge, unless Enbridge files a motion for judicial review of the dispute in accordance with the following Paragraph. Enbridge may seek judicial review of the dispute by filing with the Court and serving on the United States, in accordance with Section XVI (Notices) of the Consent Decree, a motion requesting judicial resolution of the dispute. The motion must be filed within 30 Days of receipt of the United States’ Statement of Position pursuant to the preceding Paragraph. The motion shall contain a written statement of Enbridge’s position on the matter in dispute, including 150 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1455 Page 155 of 225 any supporting factual data, analysis, opinion, or documentation, and shall set forth the relief requested and any schedule within which the dispute must be resolved for orderly implementation of the Consent Decree. The United States shall respond to Enbridge’s motion within the time period allowed by the Local Rules of this Court. Enbridge may file a reply memorandum, to the extent permitted by the Local Rules. Standard of Review; In any dispute, Enbridge shall bear the burden of demonstrating that its position complies with this Consent Decree and furthers the objectives of the Consent Decree and the CWA. The invocation of dispute resolution procedures under this Section shall not, by itself, extend, postpone, or affect in any way any obligation of Enbridge under this Consent Decree, unless and until final resolution of the dispute so provides. Stipulated penalties and Interest with respect to the disputed matter shall continue to accrue from the first Day of noncompliance, but payment shall be stayed pending resolution of the dispute. If Enbridge does not prevail on the disputed issue, stipulated penalties shall be assessed and paid as provided in Section XI (Stipulated Penalties). EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS This Consent Decree resolves the civil claims of the United States for injunctive relief and civil penalties for violations of the Clean Water Act alleged in the Complaint, as well as the civil claims of the United States in the Complaint for recovery of removal costs and damages under the Oil Pollution Act with respect to the Line 6A Discharges and the Line 6B Discharges, subject only to any reservations of rights set forth below in this Section. Nothing in this Consent Decree shall be construed to alter or effect the terms of a covenant not to sue in the Consent 151 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1456 Page 156 of 225 Decree in United States et al. v. Enbridge Energy, Ltd. P’ship, et al., Case 1:15-cv-00590-GJQ (W.D. Michigan), relating to claims for natural resource damages relating to the Line 6B discharges. The United States reserves all legal and equitable remedies available to enforce the provision of this Consent Decree, except as expressly stated in Paragraph 187. The United States reserves all legal and equitable remedies with respect to any and all claims other than those described in Paragraph 187. This Consent Decree shall not be construed to limit the rights of the United States to obtain additional relief under any federal law, implementing regulations of federal law, or permit conditions, except as expressly specified in this Consent Decree. Notwithstanding Paragraph 187, the United States reserves the right to assert claims against Enbridge to recover the amount of any third party damage claims that the Oil Spill Liability Trust Fund pays after October 1, 2015. In any subsequent administrative or judicial proceeding initiated by the United States for injunctive relief, civil penalties, response or removal costs, expenses, damages, criminal liability, or other appropriate relief relating to the Lakehead System or Enbridge’s violations alleged in the Complaint, including any proceeding related to any Corrective Action Order or Notices of Probable Violations issued by PHMSA, pertaining to the Line 6A Discharges or the Line 6B Discharges, Enbridge shall not assert, and may not maintain, any defense or claim based upon the principles of waiver, res judicata, collateral estoppel, issue preclusion, claim preclusion, claim-splitting, or other defenses based upon any contention that the claims raised by the United States in the subsequent proceeding were or should have been brought in the instant case, except 152 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1457 Page 157 of 225 with respect to the claims that have been specifically resolved pursuant to Paragraph 187. Enbridge reserves any and all defenses or claims not specifically resolved in this Section XIV. This Consent Decree is not a permit, or a modification of any permit, under any federal, State, or local laws or regulations. Enbridge is responsible for achieving and maintaining compliance with all applicable federal, State, and local laws, regulations, orders, and permits. Enbridge’s compliance with this Consent Decree shall be no defense to any action commenced pursuant to any such laws, regulations, orders, or permits except to the extent provided in this Section XIV. The United States does not, by its consent to the entry of this Consent Decree, warrant or aver in any manner that Enbridge’s compliance with any aspect of this Consent Decree will result in compliance with provisions of the CWA, Federal pipeline safety laws, 49 U.S.C. § 60101 et seq., or with any other provision of federal, state, or local laws, regulations, permits, or other requirements, including requirements set forth in the Consent Agreement and Order (CPF No. 3-2012-5017H) with PHMSA, which mandates implementation of the Lakehead Plan. This Consent Decree does not limit or affect the rights of Enbridge or of the United States against any third parties, not party to this Consent Decree, nor does it limit the rights of third parties, not party to this Consent Decree, against Enbridge, except as otherwise provided by law, including but not limited to, claims of third parties for damages under the Oil Pollution Act, and claims under 33 U.S.C. § 1365(b)(1)(B) and 42 U.S.C. § 7604(b)(1)(B). This Consent Decree shall not be construed to create rights in, or grant any cause of action to, any third party not party to this Consent Decree. Enbridge covenants not to sue and agrees not to assert any claims related to the Line 6A Discharges or Line 6B Discharges, or response activities in connection with such discharges, against the United States pursuant to the CWA, Oil Pollution Act, or any other federal 153 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1458 Page 158 of 225 law, state law, or regulation. Enbridge further covenants not to sue and agrees not to assert any direct or indirect claim for reimbursement from the Oil Spill Liability Trust Fund or pursuant to any other provision of law. Finally, Enbridge covenants and agrees not to assert the limitation on liability at 33 U.S.C. § 2704(a)(4) as a defense to any claim or bill presented to Enbridge for payment of removal costs or damages relating to the Line 6A Discharges and Line 6B Discharges. COSTS The Parties shall bear their own costs of this action, including attorneys’ fees, except that the United States shall be entitled to collect the costs, including attorneys’ fees, incurred in any action necessary to collect any portion of the civil penalty or any stipulated penalties due but not paid by Enbridge. NOTICES Unless otherwise specified in this Decree, whenever notifications, submissions, or communications are required by this Consent Decree, they shall be made in writing and addressed as follows: As to the United States by email: eescdcopy.enrd@usdoj.gov Re: DJ # 90-5-1-1-10099 As to the United States by mail: EES Case Management Unit Environment and Natural Resources Division U.S. Department of Justice P.O. Box 7611 Washington, D.C. 20044-7611 Re: DJ # 90-5-1-1-10099 With copies to the EPA representatives listed below As to EPA Region 5 by email: kirby-miles.leslie@epa.gov Riley.ellen@epa.gov Whelan.ann@epa.gov 154 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1459 Page 159 of 225 As to EPA Region 5 by mail: Leslie A. Kirby-Miles U.S. EPA, Region 5 Office of Regional Counsel (C-14J) 77 W. Jackson Blvd. Chicago, IL 60604 Ellen Riley U.S. EPA, Region 5 (SC-5J) Superfund Division 77 W. Jackson Blvd. Chicago, IL 60604 Ann Whelan U.S. EPA, Region 5 (SE-5J) Superfund Division 77 W. Jackson Blvd. Chicago, IL 60604 As to EPA OECA: Cheryl T. Rose U.S. EPA Office of Enforcement and Compliance Assurance Mail Code 2243-A 1200 Pennsylvania Ave., NW Washington, DC 20460 Email: rose.cheryl@epa.gov As to USCG: Director (NPFC) ATTN: Thomas Van Horn Chief, Legal Division CG National Pollution Funds Center U.S. Coast Guard Stop 7605 2703 Martin Luther King Jr Avenue SE Washington, DC 20593-7605 Email: Thomas.H.VanHorn@uscg.mil As to Enbridge: Chris Kaitson Vice President-US Law & Deputy General Counsel Enbridge 1100 Louisiana Street, #3300 Houston, TX 77002 E-mail: chris.kaitson@enbridge.com 155 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1460 Page 160 of 225 Any Party may, by written notice to the other Parties, change its designated notice recipient or notice address provided above. Notices submitted pursuant to this Section shall be deemed submitted upon mailing or emailing, unless otherwise provided in this Consent Decree or by mutual agreement of the Parties in writing. EFFECTIVE DATE The Effective Date of this Consent Decree shall be the date upon which this Consent Decree is entered by the Court or a motion to enter the Consent Decree is granted, whichever occurs first, as recorded on the Court’s docket; provided, however, that Enbridge hereby agrees that they shall be bound to perform duties scheduled to occur prior to the Effective Date. In the event the United States withdraws or withholds consent to this Consent Decree before entry, or the Court declines to enter the Consent Decree, then the preceding requirement to perform duties scheduled to occur before the Effective Date shall terminate. RETENTION OF JURISDICTION The Court shall retain jurisdiction over this case until termination of this Consent Decree for the purpose of resolving disputes arising under this Decree or entering orders modifying this Decree, pursuant to Sections XIII and XIX, or effectuating or enforcing compliance with the terms of this Decree. MODIFICATION This Consent Decree, including Appendices, contains the entire agreement of the Parties and shall not be modified by any prior oral or written agreement, representation, or understanding. Prior drafts of this Consent Decree shall not be used in any action involving the interpretation or enforcement of this Consent Decree. The terms of this Consent Decree, 156 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1461 Page 161 of 225 including any attached appendices, may be modified only by a subsequent written agreement signed by all the Parties, except as provided herein. Where the modification constitutes a material change to this Decree, it shall be effective only upon approval by the Court. Material changes shall not include agreed-upon changes to deadlines or EPA-approved schedules, provided that the Parties provide notice to the Court of these changes. Any disputes concerning modification of this Decree shall be resolved pursuant to Section XIII (Dispute Resolution), provided, however, that, instead of the burden of proof provided by Paragraph 185, the Party seeking the modification bears the burden of demonstrating that it is entitled to the requested modification in accordance with Federal Rule of Civil Procedure 60(b). TERMINATION Enbridge may serve upon the United States a written Request for Termination and Final Report in accordance with the requirements specified below in this Paragraph after: (i) Enbridge has implemented all requirements of this Consent Decree, (ii) Enbridge has maintained substantial compliance with the requirements of this Consent Decree for at least the last 12 continuous months, and (iii) at least four years have elapsed since the Effective Date. The Request for Termination and Final Report shall include: documentation that Enbridge has paid all civil penalties required under Section V of this Consent Decree, together with any interest due thereon; documentation that Enbridge has paid all stipulated penalties demanded by the United States pursuant to Paragraph 167, above, together with any interest due thereon, except to the extent that such penalties have been successfully contested by Enbridge; 157 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1462 Page 162 of 225 documentation that Enbridge has paid all recoverable removal costs and damages (other than natural resource damages) that the United States has incurred and paid with respect to the Line 6B Discharges; documentation, which may incorporate by reference prior Semi-Annual Reports, that Enbridge has implemented all requirements of the Consent Decree. With regard to the ongoing requirements in the Consent Decree, Enbridge must document that all such obligations are current and up-to-date as of the date of the Request for Termination and Final Report and certify that such obligations will continue to be implemented in compliance with the Consent Decree until Termination by the Court; a summary of all instances of noncompliance with any requirement or schedule set forth pursuant to or in this Consent Decree that occurred during the 12-month period prior to submission of the Request for Termination and Final Report, including any such instances that occurred subsequent to the last Semi-Annual Report pursuant to Paragraph 143, and a description of any resolution of each such non-compliance, including any payment of stipulated penalties; a certification that there are no unresolved assertions of Force Majeure under Section XII or Dispute Resolution proceedings under Section XIII, relating to any obligations that Enbridge was required to complete prior to submission of the Request for Termination and Final Report. Following receipt by the United States of Defendants’ Request for Termination and Final Report, the Parties shall confer informally concerning the Request and any disagreement that the Parties may have as to whether Defendants have satisfactorily complied with the requirements for termination of this Consent Decree. If the United States agrees that the 158 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1463 Page 163 of 225 Decree may be terminated, the Parties shall submit, for the Court’s approval, a joint stipulation terminating requirements of the Consent Decree, except as provided in Paragraph 206. If the United States does not agree that the Decree may be terminated, Enbridge may invoke Dispute Resolution under Section XIII. However, Enbridge shall not seek Dispute Resolution of any dispute regarding termination until 120 Days after service of their Request for Termination. Notwithstanding termination of other provisions of the Consent Decree, the restrictions on any resumption of operation of Original US Line 3 or Original Line 6B to transport oil, gas, diluent or any hazardous substance shall remain in effect and enforceable until 10 years after the Effective Date or until Defendant has satisfied the requirements for termination specified above, whichever is later. PUBLIC PARTICIPATION This Consent Decree shall be lodged with the Court for a period of not less than 30 Days for public notice and comment in accordance with 28 C.F.R. § 50.7. The United States reserves the right to withdraw or withhold its consent if the comments regarding the Consent Decree disclose facts or considerations indicating that the Consent Decree is inappropriate, improper, or inadequate. Enbridge consents to entry of this Consent Decree without further notice and agrees not to withdraw from or oppose entry of this Consent Decree by the Court or to challenge any provision of the Decree, unless the United States has notified Enbridge in writing that it no longer supports entry of the Decree. 159 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1464 Page 164 of 225 SIGNATORIES/SERVICE Each undersigned representative of Enbridge and the Deputy Assistant Attorney General for the Environment and Natural Resources Division of the Department of Justice certifies that he or she is fully authorized to enter into the terms and conditions of this Consent Decree and to execute and legally bind the Party he or she represents to this document. This Consent Decree may be signed in counterparts, and its validity shall not be challenged on that basis. Enbridge agrees to accept service of process by mail with respect to all matters arising under or relating to this Consent Decree and to waive the formal service requirements set forth in Rules 4 and 5 of the Federal Rules of Civil Procedure and any applicable Local Rules of this Court including, but not limited to, service of a summons. The Parties agree that Enbridge does not need to file an answer to the complaint in this action unless or until this Court expressly declines to enter this Consent Decree. INTEGRATION This Consent Decree constitutes the final, complete, and exclusive agreement and understanding among the Parties with respect to the settlement embodied in the Decree and supersedes all prior agreements and understandings, whether oral or written, concerning the settlement embodied herein. Other than deliverables that are subsequently submitted and approved pursuant to this Decree, no other document, or any representation, inducement, agreement, understanding, or promise, constitutes any part of this Decree or the settlement it represents, nor shall it be used in construing the terms of this Decree. FINAL JUDGMENT Upon approval and entry of this Consent Decree by the Court, this Consent Decree shall constitute a final judgment of the Court as to the United States and Enbridge. The Court 160 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1465 Page 165 of 225 finds that there is no just reason for delay and therefore enters this judgment as a final judgment under Fed. R. Civ. P. 54 and 58. APPENDICES The following Appendices are attached to and part of this Consent Decree: “Appendix A” lists Priority Features criteria; “Appendix B” lists input values for Predicted Burst Pressure calculations; “Appendix C” lists Lakehead System local responders for Field Exercises and Table-Top Exercises; “Appendix D” lists all Control Point locations covered by the Consent Decree; “Appendix E” is a sample format for Control Point information; and “Appendix F” is an illustration of leak detection S-R Performance curves. Dated and entered this day of __________, 2017 __________________________________ HON. GORDON J. QUIST UNITED STATES DISTRICT JUDGE 161 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1466 Page 166 of 225 THE UNDERSIGNED PARTY enters into this Consent Decree regarding claims under the CWA and OPA for injunctive relief, civil penalties, and recovery of removal costs relating to the 2010 Discharges from Enbridge's Line 6A and Line 6B FOR PLAINTIFF UNITED STATES OF AMERICA: RUCE S. GELBER Deputy Assistant Attorney General Environment and Natural Resources Division s/Steven J. Willey(OH 0025361) STEVEN J. WILLEY JOSEPH W.C. WARREN Environmental Enforcement Section Environment and Natural Resources Division Department of Justice P.O. Box 7611 Washington, D.C. 20530 (202)616-1303 PATRICK A. MILES, JR. United States Attorney Western District of Michigan RYAN COBB Assistant U.S. Attorney 330 Ionia Avenue, N.W. Suite 501 Grand Rapids, MI 49503 616-456-2404 162 Case ECF No. 9-5 filed 01/19/17 PageID.1467 Page 167 of 225 THE UNDERSIGNED PARTY enters into this Consent Decree regarding claims under the CWA and GPA for injunctive relief, civil penalties, and recovery of removal costs relating to the 20l0 Discharges from Enbridge?s Line 6A and Line 68 FOR PLAINTIFF UNITED STATES OF AMERICA (CONTINUED) QM A 2.4% ROBERT A KAPLAN Acting Regional Administr/atm U. EPA Region 5 Chicago, Illinois KW KAREN L. PEACEMAN LESLIE A. KIRBY- MILES Associate Regional Counsel US. EPA, Region 5 Chicago, Illinois 163 Case ECF No. 9-5 filed 01/19/17 PageID.1468 Page 168 of 225 THE UNDERSIGNED PARTY enters into this Consent Decree regarding claims under the CWA and GPA for injunctive relief, civil penalties, and recovery of removal costs relating to the 2010 Discharges from Enbridge?s Line 6A and Line 6B FOR PLAINTIFF UNITED STATES OF AMERICA (CONTINUED) ?7mm 0sz f? Assistant Ad inistrator of Of?ce of Enforcement and Complia' ce Assurance US. EPA Washington, DC. I CHERYL ROSE Attorney Advisor Of?ce of Enforcement and Compliance Assurance US. EPA Washington, DC. 164 Case ECF No. 9-5 filed 01/19/17 PageID.1469 Page 169 of 225 THE UNDERSIGNED PARTY enters into this Consent Decree regarding claims under the CWA and GPA for injunctive relief, civil penalties, and recovery of removal costs relating to the 2010 Discharges from Enbridge?s Line 6A and Line 6B FOR DEFENDAN TS: ENBRIDGE ENERGY, LIMITED PARTNERSHIP, ENBRIDGE PIPELINES (LAKEHEAD) L.L.C., - ENBRIDGE ENERGY PARTNERS, L.P., ENBRIDGE ENERGY MANAGEMENT, L.L.C., ENBRIDGE ENERGY COMPANY, INC, and ENBRIDGE EMPLOYEE SERVICES, INC. [1 Stephen/?. Neyland, Vi? President Kat: FOR DEFENDANTS: ENBRIDGE OPERATIONAL SERVICES, INC., ENBRIDGE PIPELINES INC, and EMPLOYEE SERVICES CANADA INC. fen D. Guy Jarvis, President 3% 165 Case ECF No. 9-5 filed 01/19/17 Page 170 of 225 THE UNDERSIGNED PARTY enters into this Consent Decree regarding claims under the CWA and GPA for injunctive relief, civil penalties, and recovery of removal costs relating to the 2010 Discharges from Enbridge?s Line 6A and Line: 613 FOR DEFENDANTS: ENBRIDGE ENERGY, LIMITED PARTNERSHIP, ENBRIDGE PIPELINES (LAKEHEAD) - ENBREDGE ENERGY PARTNERS, L.P., ENBRID GE ENERGY MANAGEMENT, L.L.C., ENERGY COMPANY, INC, and ENE RIDGE EMPLOYEE SERVICES, INC., Stephen .T. Neyland, Vice President LK FOR DEFENDANTS: OPERATIONAL SERVICES, INC, ENBRIDGE PIPELINES INC, and ENBREGE EMPLOYEE SERVICES CANADA D. Guy J'arvisgikwt (J E65 Case ECF No. 9-5 filed 01/19/17 PageID.1471 Page 171 of 225 APPENDIX A Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1472 Page 172 of 225 APPENDIX A Technology Priority Notification Criteria Line Proving & Geometry 1. Dent or Geometric features ≥ 5% OD, or 2. Priority notification criteria specifically identified in the project work order Corrosion Ultrasonics & Magnetic flux Leakage 1. Metal loss features with peak depth ≥ 75% Nominal Wall Thickness (“NWT”), or 2. Metal loss feature with an effective area RPR ≤ 0.85, or 3. Priority notification criteria specifically identified in the project work order 4. Metal loss features forecasted to reach maximum depth ≥ 75% NWT or actual wall thickness within 365 calendar days, or 5. Unmatched metal loss features with a depth ≥ 50% NWT or actual wall thickness Crack Ultrasonics 1. Crack features that meet or exceed the saturation limit of the crack detection tool 2. Crack features ≥ 2.5 mm (0.098 inch), and have been detected on the internal and external pipe surface at the same location 3. Priority notification criteria specifically identified in the project work order Case ECF No. 9-5 filed 01/19/17 PageID.1473 Page 173 of 225 APPENDIX Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1474 Page 174 of 225 Appendix B Predicted Burst Pressure Calculations A. Calculation of ILI Burst Pressure 1. Enbridge shall calculate the Predicted Burst Pressure of all Crack features detected by an ILI tools using the CorLASTM Model. 2. Enbridge shall calculate the Predicted Burst Pressure of all Corrosion features using the following models: a. Enbridge shall calculate Predicted Burst Pressure using the effective area method (“RSTRENG”) or the modified B31G when the Corrosion feature is detected by (i) an ultrasonic wall measurement (“USWM”) tool or (ii) a magnetic flux leakage tool that: (A) provides an axial sampling interval no greater than 3 mm and a circumferential sampling interval no greater than 8 mm, and (B) characterizes feature depth with an accuracy of 8% of the wall thickness or better, and b. Enbridge shall calculate Predicted Burst Pressure using the modified B31G method (i.e. 0.85 x depth of feature x length of feature) when the corrosion feature is detected by any magnetic flux leakage (“MFL”) tool that does not meet the requirements specified in 2.a, above. 3. In using each model, Enbridge shall calculate the Predicted Burst Pressure of a feature using the data inputs specified in Paragraphs 4 to 7 below. For those inputs that are not specified below, Enbridge shall use all applicable and appropriate data inputs for achieving accurate and reasonable estimates of the Predicted Burst Pressure of a feature detected by an ILI tool. Such inputs shall include, among other things, all information regarding the Joint where the feature is located, including (but not limited to) pipe grade, pipe diameter, SMYS, ultimate tensile strength, and flow stress. 4. “Wall thickness” Input: In selecting an input value for the wall thickness of the Joint with a Crack or Corrosion feature, Enbridge shall apply the following rules: a. General Rule: Enbridge shall select a value for wall thickness equal to the wall thickness of the Joint as measured by a USWM tool. If no USWM data exists, Enbridge shall apply the wall thickness of the Joint as determined by the best available ILI tool for measuring wall thickness. b. Exception to General Rule: The general rule in the preceding subparagraph shall not apply if it yields a wall-thickness value for the Joint that is greater than the specified nominal wall thickness of the Joint. In that circumstance, Enbridge shall select a value for wall thickness equal to the specified nominal wall thickness of the Joint. c. Exception to Exception: If the specified nominal wall thickness of the Joint is more than 15% thinner than the wall thickness as determined in accordance with Subparagraph A.4.a, Enbridge is not required to use the specified nominal wall thickness of the Joint for the purpose of calculating the Predicted Burst Pressure of the feature, provided that 1 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1475 Page 175 of 225 Enbridge documents, in writing, that the specified nominal wall thickness is incorrect and does not reflect the actual wall thickness of the Joint as determined through historical dig information, as-built drawings, or other comparable records relating to the Joint. After making such a written determination, Enbridge may input a value for wall thickness that is equal to either of the following values, whichever yields the thinnest possible wall for the Joint: (i) the wall thickness as determined by historical records or (ii) the wall thickness as determined in accordance with Subparagraph A.4.a. 5. “Depth of feature” Input: In selecting an input value for the depth of a Crack or Corrosion feature detected by an ILI tool, Enbridge shall select a value equal to (a) the depth of the feature as reported by the IIL tool plus (b) an appropriate value representative of the tool tolerance of the ILI tool. If the ILI tool did not report a specific depth for a Crack feature but reported instead a minimum and maximum depth for the feature, Enbridge shall determine the depth of the feature using the following three-step process: (i) Step One: Enbridge shall input a value for the depth of the Crack feature equal to the maximum depth for the feature reported by the ILI tool. (ii) Step Two: Enbridge shall calculate the Predicted Burst Pressure of the Crack feature and then compare the value yielded by this calculation to the safe operating pressure determined by 1.25 x MOP. If Predicted Burst Pressure is less than the safe operating pressure for the Joint, Enbridge shall proceed to step 3 below. (iii) Step Three: For the purpose of assessing the potential severity of the Crack feature, Enbridge shall recalculate the Predicted Burst Pressure of the Crack feature after inputting a new value for the depth of the Crack feature. The new value for the depth of the Crack feature shall be equal to (a) the maximum depth of the feature as reported by the ILI tool plus (b) an appropriate value representative of the maximum variance due to tool tolerance. 6. “Length of Feature” Input: In selecting an input value for the length of a Crack feature or Corrosion feature detected by an ILI tool, Enbridge shall select a value equal to the length of the feature reported by the ILI tool, unless the feature is classified as a “crack field.” With respect to crack fields, Enbridge shall select a value representative of the total interacting length of cracks in the field as reported by the ILI tool vendor. 7. “Notch Toughness” Input: In selecting an input value for the “notch toughness” of a Crack feature, Enbridge shall select a value equal to a Charpy V-notch energy of 5 foot/pounds (or an equivalent J integral value) for Crack features located in the long seams of low-frequency electric-resistance welded (“LF-ERW”) pipe or flash welded (“FW”) pipe. With respect to all other Crack features, Enbridge shall select an input value equal to a Charpy Vnotch energy value that is no greater than 15 foot/pounds (or an equivalent J integral value). B. Calculation of Field Burst Pressure 1. For purposes of Predicted Burst Pressure calculations performed after completing excavation and repair or mitigation of all Potentially Injurious Features identified in any initial 2 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1476 Page 176 of 225 Dig List, Enbridge apply the same procedures set forth above with respect to ILI Burst Pressure Calculations, except Enbridge shall use the inputs in Paragraph 2 and 3 below in lieu of those in Paragraph A.5 and A.6 above: 2. “Depth of feature” Input: In selecting an input value for the depth of a Crack feature or Corrosion feature analyzed in the field, Enbridge shall not select a single value for depth for the feature, but rather should input a number of values equal to the depth measurements collected by field personnel as they measured the feature’s varying depth over its entire length. In the event that the feature is a Crack feature that is located within a Corrosion feature, Enbridge shall ensure that the depth reported by field personnel reflects the combined depth of the features. 3, “Length of feature” Input: In selecting an input or the length of a Crack feature or Corrosion feature analyzed in the field, Enbridge shall select a value equal to the length reported by field personnel using NDE methodologies to measure the feature’s length. 3 Case ECF No. 9-5 filed 01/19/17 PageID.1477 Page 177 of 225 APPENDIX Case 1:16-cv-00914-GJQ-ESC ECF APPENDIX No. 9-5 filedC01/19/17 PageID.1478 Page 178 of 225 Company Name ADDISON TOWNSHIP FIRE DEPARTMENT ADDISON TOWNSHIP FIRE DEPARTMENT-STA 2 Algonquin Lake in the Hills Fire Protection Dist S ARMADA TOWNSHIP FIRE DEPARTMENT EMS AURORA FIRE DEPARTMENT STATION 12 Aurora Fire Department Station 8 AURORA FIRE DEPARTMENT STATION 9 BARTLETT FIRE PROTECTION DISTRICT STA 1 BARTLETT FIRE PROTECTION DISTRICT STA 3 BELVIDERE FIRE DEPARTMENT Belvidere Fire Department Station 2 BIG FLATS VOLUNTEER FIRE DEPARTMENT BIG ROCK FIRE PROTECTION DISTRICT Boone County Fire Protection District 2 Station 2 Brandon Fire Department Station 2 BRUCE TOWNSHIP FIRE DEPARTMENT STATION 2 CAMERON TOWNSHIP FIRE DEPARTMENT Carpentersville Fire Department Station 2 CARY FIRE PROTECTION DISTRICT Cary Fire Protection District Station 2 CHICAGO HEIGHTS FIRE DEPARTMENT Chicago Heights Fire Department Olympia Gardens St Chicago Heights Fire Department Station 1 Chicago Heights Fire Department Station 2 Chicago Heights Fire Department Station 4 Chicago Heights Fire Department Station 5 COOLSPRING TOWNSHIP VOL FIRE DEPARTMENT Coolspring Volunteer Fire Department Station 2 DARIEN VOLUNTEER FIRE DEPARTMENT DELAVAN CITY VOLUNTEER FIRE DEPARTMENT Delavan Township Fire Department Station 2 Dyer Fire Department Station 2 DYER VOLUNTEER FIRE DEPARTMENT DYER VOLUNTEER FIRE DEPARTMENT STATION 2 EAST DUNDEE FIRE DEPARTMENT ELGIN FIRE DEPARTMENT STATION 1 ELGIN FIRE DEPARTMENT STATION 2 ELGIN FIRE DEPARTMENT STATION 5 FORT ATKINSON FIRE DEPARTMENT FOX RIVER GROVE FIRE PROTECTION DISTRICT FRANKENLUST VOLUNTEER FIRE DEPARTMENT FRANKFORT FIRE PROTECTION DIST STATION 4 FRANKFORT FIRE PROTECTION DISTRICT STA 1 FRANKFORT FIRE PROTECTION DISTRICT STA 2 Gibson Township Fire Department GILMAN RURAL VOLUNTEER FIRE DEPARTMENT Griffith Fire Department Station 2 Griffith Fire Department Station 3 GRIFFITH VOLUNTEER FIRE DEPARTMENT HAMPSHIRE FIRE PROTECTION DISTRICT HOBART AMBULANCE SERVICE Hobart Fire Department Station 4 City LEONARD LEONARD ALGONQUIN ARMADA AURORA AURORA AURORA BARTLETT BARTLETT BELVIDERE BELVIDERE ARKDALE BIG ROCK GARDEN PRAIRIE OXFORD ROMEO MARSHFIELD CARPENTERSVILLE CARY CARY CHICAGO HEIGHTS CHICAGO HEIGHTS CHICAGO HEIGHTS CHICAGO HEIGHTS CHICAGO HEIGHTS CHICAGO HEIGHTS MICHIGAN CITY MICHIGAN CITY DARIEN DELAVAN DELAVAN DYER DYER DYER EAST DUNDEE ELGIN ELGIN ELGIN FORT ATKINSON FOX RIVER GROVE BAY CITY FRANKFORT FRANKFORT FRANKFORT BENTLEY GILMAN GRIFFITH GRIFFITH GRIFFITH HAMPSHIRE HOBART HOBART 1 State MI MI IL MI IL IL IL IL IL IL IL WI IL IL MI MI WI IL IL IL IL IL IL IL IL IL IN IN WI WI WI IN IN IN IL IL IL IL WI IL MI IL IL IL MI WI IN IN IN IL IN IN Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1479 Page 179 of 225 Company Name HOLLY FIRE DEPARTMENT HOMER TOWNSHIP FIRE PROTECTION DISTRICT Homer Township Fire Protection District Station 2 Homer Township Fire Protection District Station 3 JOLIET FIRE DEPARTMENT STATION 1 JOLIET FIRE DEPARTMENT STATION 3 JOLIET FIRE DEPARTMENT STATION 6 JOLIET FIRE DEPARTMENT STATION 7 KANEVILLE FIRE PROTECTION DISTRICT KAWKAWLIN TOWNSHIP FIRE DEPARTMENT Kirkland Fire Protection District LADYSMITH FIRE DEPARTMENT Lemont Fire Protection District Station 2 LEROY TOWNSHIP FIRE DEPARTMENT Lincoln Fire & Rescue Lisbon - Seward Fire Protection District 2 LITTLE ROCK FOX FIRE DISTRICT STATION 1 LITTLE ROCK FOX FIRE DISTRICT STATION 2 LITTLE ROCK FOX FIRE DISTRICT STATION 3 LOCKPORT TOWNSHIP FIRE PROT DIST STA 1 LOCKPORT TOWNSHIP FIRE PROT DIST STA 3 LUBLIN AREA VOLUNTEER FIRE DEPARTMENT LUZERNE VOLUNTEER FIRE DEPARTMENT MANHATTAN VOLUNTEER FIRE PROT DISTRICT MARQUETTE COUNTY EMS-OXFORD BRANCH MARSEILLES FIRE PROTECTION DISTRICT MARSHALL TOWNSHIP FIRE DEPARTMENT MARSHALL VOLUNTEER FIRE DEPARTMENT MARYSVILLE FIRE DEPARTMENT MATTESON FIRE DEPARTMENT Matteson Fire Department Station 2 MEMPHIS FIRE DEPARTMENT MERRILLVILLE FIRE DEPARTMENT 71 MERRITT TOWNSHIP FIRE DEPARTMENT MOKENA FIRE PROTECTION DISTRICT Mokena Fire Protection District Station 2 NAPERVILLE FIRE DEPARTMENT Naperville Fire Department Station 10 Naperville Fire Department Station 4 Naperville Fire Department Station 6 NEKOOSA FIRE DEPT-AMBULANCE SERVICE NEW LENOX FIRE PROTECTION DIST STATION 3 NEW LENOX FIRE PROTECTION DIST STATION 4 NEW LENOX FIRE PROTECTION DISTRICT STA 1 NEWTON TOWNSHIP FIRE DEPARTMENT 1ST RESP Niles Twp Fire Dept NILES TWP FIRE DEPT SOUTH- MAIN STATION NORTHWEST HOMER FIRE PROTECTION DISTRICT NUNDA RURAL FIRE PROTECTION DISTRICT OGEMAW FIRE DEPARTMENT STATION 6 Orland Fire Protection District Station 3 City HOLLY LOCKPORT HOMER GLEN LOCKPORT JOLIET JOLIET JOLIET JOLIET KANEVILLE KAWKAWLIN KIRKLAND LADYSMITH LEMONT EAST LEROY MARSHFIELD YORKVILLE PLANO MILLBROOK PLANO LOCKPORT ROMEOVILLE LUBLIN LUZERNE MANHATTAN MONTELLO MARSEILLES MARSHALL MARSHALL MARYSVILLE MATTESON MATTESON MEMPHIS MERRILLVILLE MUNGER MOKENA MOKENA NAPERVILLE NAPERVILLE NAPERVILLE NAPERVILLE NEKOOSA NEW LENOX NEW LENOX NEW LENOX CERESCO NILES NILES LOCKPORT CRYSTAL LAKE WEST BRANCH ORLAND PARK 2 State MI IL IL IL IL IL IL IL IL MI IL WI IL MI WI IL IL IL IL IL IL WI MI IL WI IL MI WI MI IL IL MI IN MI IL IL IL IL IL IL WI IL IL IL MI MI MI IL IL MI IL Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1480 Page 180 of 225 Company Name Orland Park Fire Protection District OWEN-WITHEE-CURTISS FIRE ASSOCIATION OXFORD FIRE DEPARTMENT OXFORD FIRE DEPARTMENT STATION 1 PARDEEVILLE FIRE DEPARTMENT PARK FOREST FIRE DEPARTMENT Pinconning Fraser Township Fire Department PORT EDWARDS FIRE DEPARTMENT Port Huron Fire Department Station 4 PORTSMOUTH TOWNSHIP FIRE DEPARTMENT REESE FIRE RESCUE RICHFIELD RURAL FIRE DEPARTMENT RICHVILLE FIRE DEPARTMENT RIO FIRE DEPARTMENT-AMBULANCE SERVICE ROCKDALE FIRE PROTECTION DISTRICT ROME TOWNSHIP FIRE DEPARTMENT ROMEOVILLE VILLAGE FIRE DEPARTMENT STA 1 SANDWICH COMMUNITY FIRE PROTECTION DIST SAUK VILLAGE FIRE DEPARTMENT Schererville Fire Department SCHERERVILLE FIRE DEPARTMENT Schererville Fire Department SERENA COMMUNITY FIRE PROTECTION DIST SHELDON FIRE PROTECTION DISTRICT SOUTH KALAMAZOO CNTY FIRE ATHRTY STA 3 SPENCER COMMUNITY AMBULANCE SERVICE SPRINGFIELD TOWNSHIP FIRE DEPT STA 1 SPRINGFIELD TOWNSHIP FIRE DEPT STA 2 SPRINGPORT-CLARENCE TOWNSHIP FIRE DEPT STEGER ESTATES VLNTR FIRE PROTECT DIST STEGER FIRE DEPARTMENT-STATION 1 STOCKBRIDGE AREA EMERGENCY SVC AUTH-ELM Tinley Park Fire Department Station 3 TROY FIRE PROTECTION DISTRICT STA 1 TROY FIRE PROTECTION DISTRICT STA 2 Troy Township Fire Protection District VASSAR FIRE AND RESCUE DEPARTMENT VERONA-KINSMAN FIRE DISTRICT WALWORTH FIRE-RESCUE SQUAD AND AMBULANCE Warrenville Fire Department WARRENVILLE FIRE PROTECTION DISTRICT WEST CHICAGO FIRE PROTECTION DISTRICT West Chicago Fire Protection District Station 2 West Chicago Fire Protection District Station 3 WEST DUNDEE FIRE DEPARTMENT STATION 1 Wonder Lake Fire Protection District Station 16 WATERMAN CMNTY FIRE PROTECTION DISTRICT ALLEN TOWNSHIP FIRE PROTECTION DISTRICT Bay City Fire Department Bay City Fire Department Bay City Fire Department City ORLAND PARK OWEN OXFORD OXFORD PARDEEVILLE PARK FOREST LINWOOD PORT EDWARDS PORT HURON BAY CITY REESE MARSHFIELD RICHVILLE RIO ROCKDALE NEKOOSA ROMEOVILLE SANDWICH SAUK VILLAGE SCHERERVILLE SCHERERVILLE CROWN POINT SERENA SHELDON VICKSBURG SPENCER DAVISBURG DAVISBURG SPRINGPORT CRETE STEGER STOCKBRIDGE TINLEY PARK SHOREWOOD SHOREWOOD SHOREWOOD VASSAR VERONA WALWORTH WARRENVILLE WARRENVILLE WEST CHICAGO WEST CHICAGO WEST CHICAGO WEST DUNDEE WONDER LAKE WATERMAN RANSOM BAY CITY BAY CITY BAY CITY 3 State IL WI WI MI WI IL MI WI MI MI MI WI MI WI IL WI IL IL IL IN IN IN IL WI MI WI MI MI MI IL IL MI IL IL IL IL MI IL WI IL IL IL IL IL IL IL IL IL MI MI MI Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1481 Page 181 of 225 Company Name BOLINGBROOK FIRE DEPARTMENT STATION 5 BP Joliet Works Fire Department CHANNAHON FIRE PROTECTION DISTRICT STA 2 CHARTER TOWNSHIP MONITOR FIRE DEPARTMENT COAL CITY FIRE PROTECTION DISTRICT EAST JOLIET FIRE PROTECTION DISTRICT 3 East Joliet Fire Protection District Station 2 Ford Heights Fire Department FRANKFORT FIRE PROTECTION DIST STATION 5 GE PLASTICS FIRE DEPARTMENT Genoa - Kingston Fire Department Station 2 GROVELAND TOWNSHIP FIRE DEPARTMENT STA 1 Hartland Area Fire Department Station 62 HEBRON-ALDEN-GREENWOOD FIRE DIST-STA 2 Highland Fire Department South Station HOFFMAN ESTATES FIRE STATION 24 LAKE HILLS FIRE DEPARTMENT LESLIE VOLUNTEER FIRE DEPARTMENT LISBON-SEWARD FIRE COMPANY 2 LYNWOOD FIRE DEPARTMENT MARSHALL FIRE DEPARTMENT MAYVILLE FIRE DEPARTMENT MAZON VOLUNTEER FIRE DEPARTMENT McHenry Township Fire Protection District Station MERRILLVILLE EMERGENCY MEDICAL SERVICE MOFFATT TOWNSHIP VOLUNTEER FIRE DEPT Newark Fire Protection District Millbrook Station North Boon Fire District 3 Station 2 North Boone Fire District 3 NORTH BRANCH TOWNSHIP FIRE DEPARTMENT NORTH OAKLAND COUNTY FIRE AUTHORI STA 3 NORTHWEST HOMER FIRE PROTECTION DISTRICT Northwest Homer Fire Protection District Station 2 Orland Fire Protection District Station 6 PEOTONE FIRE PROTECTION DISTRICT PLAINFIELD FIRE PROTECTION DIST STA 1 Plainfield Fire Protection District Station 2 Plainfield Fire Protection District Station 3 RICHTON PARK FIRE DEPARTMENT Richton Park Fire Department Station 1 Romeoville Fire Department Station 2 ROSS TOWNSHIP FIRE DEPARTMENT STATION 4 SAINT CHARLES FIRE DEPARTMENT STATION 2 SOMONAUK COMMUNTIY FIRE PROTECTION DIST SOUTH CHICAGO HEIGHTS FIRE DEPARTMENT SOUTH HAVEN FIRE DEPARTMENT UNIVERSITY PARK FIRE DEPARTMENT STA 1 WESTFIELD TOWNSHIP FIRE DEPARTMENT WILMINGTON FIRE PROTECTION DISTRICT Windfield Fire Protection District City BOLINGBROOK CHANNAHON CHANNAHON BAY CITY COAL CITY JOLIET JOLIET FORD HEIGHTS FRANKFORT OTTAWA KINGSTON HOLLY FENTON HARVARD HIGHLAND HOFFMAN ESTATES SCHERERVILLE LESLIE NEWARK LYNWOOD MARSHALL MAYVILLE MAZON MCHENRY MERRILLVILLE ALGER MILLBROOK CALEDONIA POPLAR GROVE NORTH BRANCH HOLLY LOCKPORT HOMER GLEN ORLAND PARK PEOTONE PLAINFIELD PLAINFIELD PLAINFIELD RICHTON PARK RICHTON PARK ROMEOVILLE MERRILLVILLE SAINT CHARLES SOMONAUK S CHICAGO HTS VALPARAISO UNIVERSITY PARK WESTFIELD WILMINGTON WINFIELD 4 State IL IL IL MI IL IL IL IL IL IL IL MI MI IL IN IL IN MI IL IL MI MI IL IL IN MI IL IL IL MI MI IL IL IL IL IL IL IL IL IL IL IN IL IL IL IN IL WI IL IL Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1482 Page 182 of 225 PSAP City State DeKalb County Sheriff's Office Sycamore IL La Salle County Sheriff's Office Ottawa IL McHenry County Sheriff's Office Woodstock IL Orland Park ETSB Orland Park IL Sauk Village Police Department Sauk Village IL Southeast Emergency Communications "Seecom" Woodstock IL Tri-Comm Central Dispatch St. Charles IL Highland Police Department Crown Point IN Calhoun County Central Dispatch Marshall MI Kalamazoo Consolidated Dispatch Kalamazoo MI Oxford Police Department Pontiac MI Clark County Sheriff's Office Neillsville WI Dane County Public Safety Communications Madison WI Taylor County Sheriff's Department Medford WI Wood County Dispatch Center Wisconsin Rapids WI Hobart Police Department Crown Point IN Lincolnway Police Dispatch Joliet IL Du-Comm Zone 1 Glendale Heights IL Elgin Police Department Elgin IL Joliet Communications Joliet IL Kane County 9-1-1 Center Geneva IL KenCom Public Safety Dispatch Yorkville IL Naperville Police Department Naperville IL Quadcomm 9-1-1 Carpentersville IL Romeoville Police Department Joliet IL Southcom Combined Dispatch Griffith Police Department La Porte County 9-1-1 Merrillville Police Department Porter County 9-1-1 Schererville Police Department Bay County Central Dispatch Ingham County Consolidated 9-1-1 Dispatch Center Lapeer County E9-1-1 Central Livingston County E9-1-1 Macomb County Sheriff's Office Oakland County Sheriff Ogemaw County Central Dispatch St Clair County Sheriff's Office Tuscola County Central Dispatch Adams County Sheriff's Office Columbia County Sheriff's Office Ft Atkinson Police Department Marquette County Sheriffs Department Rusk County Sheriff's Office Matteson Crown Point La Porte Crown Point Valparaiso Crown Point Bay City Lansing Lapeer Howell Mount Clemens Pontiac West Branch Port Huron Caro Friendship Portage Fort Atkinson Montello Ladysmith IL IN IN IN IN IN MI MI MI MI MI MI MI MI MI WI WI WI WI WI 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1483 Page 183 of 225 PSAP Walworth County Sheriff's Office EastCom Dispatch Center Wescom Will County Sheriff Lake County Sheriff Bolingbrook Police Chicago Heights Police Department Lynwood-Thornton East Hazel Crest Police Fire Ems Marseilles Police Department Village Of Tinley Park Police Department Dyer Police Department Oscoda County Sheriff's Office Delavan Police Department Marathon County Sheriff's Office Boone County E9-1-1 Cook County Sheriffs Communications Center Grundy County Consolidated 9-1-1 Center Southwest Central 9-1-1 System Munster Police Department Arenac County Central Dispatch Jackson County Sheriff's Office Crawford Emergency Central Dispatch Saginaw County Central Dispatch Jefferson County Sheriff's Office Rock County 911 Communications Chippewa County Sheriff's Office City Elkhorn Joliet Joliet Joliet Crown Point Joliet Chicago Heights Lynwood Marseilles Tinley Park Crown Point Mio Delavan Wausau Belvidere Des Plaines Morris Palos Heights Crown Point Standish Jackson Grayling Saginaw Jefferson Janesville Chippewa Falls 6 State WI IL IL IL IN IL IL IL IL IL IN MI WI WI IL IL IL IL IN MI MI MI MI WI WI WI Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1484 Page 184 of 225 Company Name City ASHLAND FIRE DEPARTMENT ASHLAND State WI BALDWIN TOWNSHIP VOLUNTEER FIRE DEPT PERKINS MI BESSEMER FIRE DEPARTMENT BESSEMER MI BRAMPTON TOWNSHIP VOLUNTEER FIRE DEPT GLADSTONE MI CARLTON FIRE AND AMBULANCE CARLTON MN CASS LAKE FIRE AND RESCUE DEPARTMENT CASS LAKE MN CITY OF MANISTIQUE AMBULANCE SERVICE MANISTIQUE MI CLEARBROOK VOLUNTEER FIRE DEPARTMENT CLEARBROOK MN CLOQUET AREA FIRE DISTRICT (MERGED WITH PERCH LAKE) CLOQUET MN COHASSET FIRE DEPARTMENT COHASSET MN CRYSTAL FALLS FIRE DEPARTMENT CRYSTAL FALLS MI DEER RIVER FIRE DEPARTMENT DEER RIVER MN GARFIELD TOWNSHIP EMERGENCY SERVICES ENGADINE MI GONVICK FIRE DEPARTMENT GONVICK MN GRAND RAPIDS FIRE DEPARTMENT GRAND RAPIDS MN HIAWATHA TOWNSHIP FIRE DEPARTMENT MANISTIQUE MI INWOOD TOWNSHIP VLNTR FIRE DEPT AND EMS COOKS MI IRONWOOD TOWNSHIP VOLUNTEER FIRE DEPT IRONWOOD MI KIMBALL TOWNSHIP FIRE DEPARTMENT OSHKOSH WI LAKESIDE FIRE DEPARTMENT POPLAR WI Mackinac Island Fire Department MACKINAC ISLAND MI MARENISCO VOLUNTEER FIRE DEPARTMENT MARENISCO MI MASONVILLE TOWNSHIP VOL FIRE DEPARTMENT RAPID RIVER MI Newton Township Fire Department GOULD CITY MI OAKLAND VOLUNTEER FIRE DEPARTMENT SOUTH RANGE WI PARKLAND VOLUNTEER FIRE DEPARTMENT SAINT IGNACE FIRE DEPARTMENT SAXON-GURNEY FIRE DEPARTMENT SOLON SPRINGS FIRE DEPARTMENT Superior Fire Department Station 3 THOMPSON TOWNSHIP FIRE DEPARTMENT TOPINABEE FIRE DEPARTMENT TUSCARORA TOWNSHIP VOLUNTEER FIRE DEPT WAKEFIELD FIRE DEPARTMENT WATERSMEET TOWNSHIP VOLUNTEER FIRE DEPT Wells Township Volunteer Fire Department WEST BRANCH TOWNSHIP VOL FIRE DEPARTMENT Wrenshall Fire Department WRENSHALL FIRE DEPARTMENT Bemidji Fire Department CARP LAKE TOWNSHIP FIRE DEPARTMENT CHARLTON TOWNSHIP FIRE DEPARTMENT FLOODWOOD FIRE DEPARTMENT GORDON VOLUNTEER FIRE DEPARTMENT Hendricks Township Volunteer Fire Department SOUTH RANGE SAINT IGNACE SAXON SOLON SPRINGS SUPERIOR MANISTIQUE TOPINABEE INDIAN RIVER WAKEFIELD WATERSMEET FELCH RALPH WRENSHALL WRENSHALL BEMIDJI CARP LAKE JOHANNESBURG FLOODWOOD GORDON NAUBINWAY WI MI WI WI WI MI MI MI MI MI MI MI MN MN MN MI MI MN WI MI 7 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1485 Page 185 of 225 Company Name Mueller Township Volunteer Fire Department Neche Fire Protection District OKLEE VOLUNTEER FIRE DEPARTMENT PLUMMER FIRE DEPARTMENT SAINT HILAIRE FIRE DEPARTMENT U S Forest Service Watersmeet Ranger Station US FOREST SERVICE WATERSMEET RANGER DIST US FOREST SERVICE-ST IGNACE RANGER DIST Vienna Township Fire Department WARBA-FEELEY-SAGO FIRE DEPARTMENT City GULLIVER NECHE OKLEE PLUMMER SAINT HILAIRE WATERSMEET WATERSMEET SAINT IGNACE JOHANNESBURG WARBA 8 State MI ND MN MN MN MI MI MI MI MN Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1486 Page 186 of 225 PSAP City State Beltrami County Law Enforcement Center Bemidji MN Carlton County Sheriff's Office Carlton MN Cass County Sheriff's Office Walker MN Cce Central Dispatch - Charlevoix Petoskey MI Chippewa County Central Dispatch Kincheloe MI Delta County Central Dispatch Escanaba MI Douglas County-City of Superior Dispatch Center Superior WI Iron County 9-1-1 Crystal Falls MI Iron County Sheriff's Office Hurley WI Michigan State Police - Negaunee Regional Dispatch Negaunee MI Pennington County Sheriff's Office Thief River Falls MN St Louis County Emergency Communications Department Duluth MN Ashland County 9-1-1 Communications Center Ashland WI Dickinson County Central Dispatch / 911 Center Iron Mountain MI Itasca County Sheriff's Office Grand Rapids MN Marquette County Central Dispatch Negaunee MI Pembina County Cavalier ND 9 Case ECF No. 9-5 filed 01/19/17 PageID.1487 Page 187 of 225 APPENDIX Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1488 Page 188 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Deer Creek Deer Creek Deer Creek Deer Creek Deer Creek Deer Creek Small (Unnamed) Creek Small (Unnamed) Creek Small (Unnamed) Creek Small (Unnamed) Creek G.B. Creek G.B. Creek G.B. Creek G.B. Creek Unnamed Creek Unnamed Creek Unnamed Creek Unnamed Creek Goose Berry Creek Goose Berry Creek Goose Berry Creek Goose Berry Creek North Goose Berry Creek North Goose Berry Creek North Goose Berry Creek North Goose Berry Creek North Goose Berry Creek East Fork Mazon River East Fork Mazon River East Fork Mazon River East Fork Mazon River Ephemeral Creek Ephemeral Creek Ephemeral Creek Ephemeral Creek CP 2.20 - 0.10 CP 2.20 - 1.64 CP 2.20 - 2.90 CP 2.20 - 4.04 CP3.40 - 1.27 CP3.40 - 1.37 CP 9.00 - 0.67 CP 9.00 - 1.02 CP 9.00 - 2.19 CP 9.00 - 3.60 CP 11.00 - 0.71 CP 11.00 - 1.87 CP 11.00 - 3.19 CP 11.00 - 3.41 CP 13.60 - 0.13 CP 13.60 - 1.45 CP 13.60 - 2.14 CP 13.60 - 3.08 CP 16.60 - 0.52 CP 16.60 - 1.75 CP 16.60 - 2.19 CP 16.60 - 4.02 CP 19.60 - 0.44 CP 20.60 - 2.26 CP 20.60 - 3.82 CP 20.60 - 4.92 CP 20.60 - 6.67 CP 20.60 - 2.26 CP 20.60 - 3.82 CP 20.60 - 4.92 CP 20.60 - 6.67 CP 23.10 - 0.56 CP 23.10 - 1.66 CP 23.10 - 3.22 CP 23.10 - 4.52 -88.609298 -88.619316 -88.629204 -88.639156 -88.605061 -88.605469 -88.49331 -88.490058 -88.481907 -88.483459 -88.460209 -88.460623 -88.465879 -88.462217 -88.414242 -88.409277 -88.400458 -88.392194 -88.361817 -88.346784 -88.341156 -88.328684 -88.30966 -88.290195 -88.279573 -88.279248 -88.272822 -88.290195 -88.279573 -88.279248 -88.272822 -88.263852 -88.260581 -88.25076 -88.258552 40.96125 40.946705 40.935558 40.931978 40.962549 40.961285 41.006374 41.010194 41.020661 41.035488 41.020985 41.035572 41.049786 41.050039 41.035906 41.050122 41.054723 41.065713 41.065079 41.076981 41.080575 41.100431 41.081455 41.112773 41.128327 41.141837 41.157213 41.112773 41.128327 41.141837 41.157213 41.114296 41.126668 41.142912 41.157399 Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent 1 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 2 2 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 4 4 4 4 4 4 4 4 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1489 Page 189 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude West Reddick Run West Reddick Run West Reddick Run West Reddick Run East Reddick Run East Reddick Run East Reddick Run East Reddick Run Crane Creek Crane Creek Crane Creek Crane Creek Granary Creek Granary Creek Granary Creek Granary Creek West Horse Creek (FC) West Horse Creek (FC) West Horse Creek (FC) West Horse Creek (FC) West Horse Creek West Horse Creek West Horse Creek West Horse Creek Terry Creek Terry Creek Terry Creek Terry Creek Kankakee River Kankakee River Kankakee River Kankakee River Kankakee River Kankakee River Kankakee River CP 24.10 - 0.90 CP 24.10 - 2.11 CP 24.10 - 3.32 CP 24.10 - 4.10 CP 24.70 - 0.74 CP 24.10 - 2.11 CP 24.10 - 3.32 CP 24.10 - 4.10 CP 25.55 - 1.15 CP 25.55 - 2.34 CP 25.55 - 3.33 CP 25.55 - 3.50 CP 27.60 - 0.94 CP 27.60 - 1.84 CP 27.60 - 2.48 CP 27.60 - 3.50 CP 30.40 - 0.58 CP 31.10 - 2.39 CP 31.10 - 3.17 CP 31.10 - 7.05 CP 31.10 - 0.74 CP 31.10 - 2.39 CP 31.10 - 3.17 CP 31.10 - 7.05 CP 35.10 - 0.74 CP 35.10 - 1.79 CP 35.10 - 2.68 CP 37.59 - 3.08 CP 37.59 - 0.66 CP 37.59 - 2.63 CP 37.59 - 3.08 CP 37.59 - 4.77 CP 37.59 - 5.49 CP 37.59 - 6.87 CP 37.59 - 8.26 -88.243074 -88.243085 -88.249542 -88.252083 -88.243074 -88.243085 -88.249542 -88.252083 -88.226342 -88.221999 -88.222813 -88.223495 -88.192063 -88.204521 -88.212734 -88.223495 -88.147699 -88.150348 -88.14398 -88.133257 -88.147699 -88.150348 -88.14398 -88.133257 -88.08487 -88.092628 -88.09783 -88.094195 -88.052272 -88.087926 -88.094195 -88.124379 -88.13284 -88.145401 -88.152977 41.129167 41.143704 41.157637 41.168761 41.129167 41.143704 41.157637 41.168761 41.144808 41.159782 41.171653 41.17353 41.158813 41.16641 41.172447 41.17353 41.176718 41.194734 41.203731 41.246775 41.176718 41.194734 41.203731 41.246775 41.211649 41.222251 41.230696 41.237776 41.228135 41.234183 41.237776 41.24283 41.250596 41.268127 41.286512 Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent 2 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 12 12 12 12 12 12 12 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1490 Page 190 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Kankakee River Kankakee River Kankakee River Kankakee River Kankakee River Mary Byron Creek Mary Byron Creek Mary Byron Creek Mary Byron Creek Rayns Creek Rayns Creek Rayns Creek Rayns Creek Rayns Creek Rayns Creek Rayns Creek Rayns Creek Unnamed Creek Unnamed Creek Unnamed Creek Unnamed Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Rock Creek Black Walnut Creek Black Walnut Creek Black Walnut Creek CP 37.59 - 9.91 CP 37.59 - 11.41 CP 37.59 - 14.13 CP 37.59 - 15.67 CP 37.59 - 18.67 CP 38.33 - 0.15 CP 38.33 - 0.67 CP 38.33 - 1.32 CP 38.33 - 2.43 CP 39.27 - 1.00 CP 39.27 - 1.35 CP 39.27 - 2.45 CP 39.27 - 2.93 CP 40.60 - 1.28 CP 40.60 - 2.54 CP 40.60 - 3.65 CP 40.60 - 5.23 CP 48.40 - 1.12 CP 48.40 - 3.16 CP 48.40 - 4.63 CP 48.40 - 6.27 CP 52.11 - 0.81 CP 52.11 - 3.90 CP 52.11 - 8.55 CP 52.11 - 13.20 CP 57.31 - 0.43 CP 57.31 - 2.70 CP 57.31 - 4.85 CP 57.31 - 6.55 CP 52.11 - 3.90 CP 52.11 - 8.55 CP 52.11 - 13.20 CP 61.80 - 0.43 CP 61.80 - 2.76 CP 61.80 - 6.69 -88.152264 -88.165235 -88.191106 -88.216979 -88.260374 -88.031803 -88.040406 -88.051051 -88.071052 -88.032153 -88.051063 -88.051051 -88.071052 -88.012514 -88.032153 -88.051063 -88.051051 -87.880961 -87.902066 -87.920108 -87.920108 -87.823467 -87.850642 -87.903156 -87.9692 -87.748114 -87.777103 -87.804594 -87.823467 -87.850642 -87.903156 -87.9692 -87.679837 -87.708513 -87.746826 41.309633 41.321774 41.348302 41.358926 41.378504 41.230408 41.234367 41.238798 41.241924 41.235948 41.238827 41.238798 41.241924 41.240369 41.235948 41.238827 41.238798 41.301625 41.27951 41.264603 41.258612 41.3317 41.295239 41.250486 41.225519 41.383275 41.368703 41.349067 41.3317 41.295239 41.250486 41.225519 41.400846 41.377677 41.354555 Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent 3 Control Points Upstream Lakehead in Series Pipelines 12 12 12 12 12 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 7 7 7 7 7 7 7 4 4 4 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 6A,Line14,Line 62,Line 78 Line 6A,Line14,Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 78 Line 78 Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 78 Line 62,Line 78 Line 62,Line 78 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1491 Page 191 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Black Walnut Creek Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Bishop Ford DD Deer Creek Deer Creek Deer Creek Deer Creek North Creek North Creek North Creek North Creek Plum Creek Plum Creek Plum Creek Plum Creek Plum Creek Deer Creek Deer Creek Deer Creek Deer Creek Spring Creek Spring Creek Spring Creek Spring Creek Oak Street Pond CP 61.80 - 12.97 CP 70.56 - 0.09 CP 70.56 - 0.88 CP 70.56 - 2.31 CP 70.56 - 4.22 CP 71.24 - 0.09 CP 71.24 - 0.60 CP 71.24 - 1.63 CP 71.24 - 2.73 CP 71.56 - 0.26 CP 71.56 - 1.25 CP 71.56 - 2.33 CP 71.56 - 5.33 CP 72.87 - 0.64 CP 72.87 - 1.89 CP 72.87 - 5.33 CP 72.87 - 8.48 CP 74.71 - 0.73 CP 74.71 - 2.23 CP 74.71 - 4.01 CP 74.71 - 4.76 CP 76.10 - 0.06 CP 76.10 - 0.86 CP 76.10 - 1.59 CP 76.10 - 2.30 CP 76.80 - 4.15 CP 76.80 - 0.43 CP 76.80 - 1.23 CP 76.80 - 2.27 CP 76.80 - 4.15 CP 79.07 - 0.13 CP 79.07 - 0.38 CP 79.07 - 1.38 CP 79.07 - 2.22 CP 79.67 - 0.01 -87.801203 -87.583285 -87.58593 -87.578388 -87.589973 -87.585861 -87.582537 -87.579274 -87.582517 -87.582628 -87.578305 -87.582517 -87.625237 -87.582194 -87.590086 -87.62523 -87.608602 -87.531833 -87.529424 -87.539371 -87.540563 -87.5162 -87.509595 -87.503923 -87.492986 -87.481725 -87.503967 -87.503967 -87.498122 -87.481725 -87.463159 -87.462674 -87.466689 -87.46947 -87.452295 41.280197 41.470169 41.479855 41.499412 41.520903 41.479837 41.486524 41.499438 41.513543 41.486466 41.499355 41.513543 41.547379 41.506582 41.520726 41.547441 41.567182 41.503604 41.524684 41.543434 41.553783 41.499583 41.509078 41.518233 41.535679 41.551864 41.518233 41.518233 41.527581 41.551864 41.511608 41.515068 41.529036 41.540765 41.514267 Mid-Continent Mid-Continent Mid-Continent Mid-Continent Mid-Continent Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region Chicago Region 4 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 4 4 4 4 4 4 4 4 1 Line 62,Line 78 Line 78 Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 78 Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1492 Page 192 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Amnicon River Amnicon River Amnicon River Amnicon River Bad River Bad River Bad River Bad River Bad River Bad River Bad River Ball Club River Ball Club River Ball Club River Ball Club River Ball Club River Ball Club River Bass Brook Bass Brook Bass Brook Bay City Creek Bay City Creek Bay City Creek Bay City Creek Bear Brook Creek Tributary Bear Brook Creek Tributary Bear Creek Bear Creek Bear Creek Bear Creek Bear Creek Bear Creek Beartrap Creek Beartrap Creek Beartrap Creek CP1107-0.1B CP1107-0.4W CP1107-4.3E CP1107-5.0E CP1165-10.5W CP1165-11.2N CP1165-11.6E CP1165-11.8E CP1165-15.5S CP1165-4.7W CP1165-9.4E CP989-11.9W CP989-14.0W CP989-18.2E CP989-18.5B CP989-27.4N CP989-8.0E CP1004-0.9N CP1004-3.4B CP1104-0.7W CP1157-1.0B CP1157-3.7B CP1157-5.0B CP1157-5.4W CP981-0.2W CP981-0.6N CP1102-0.2W CP1102-0.4B CP1102-0.5E CP1102-2.2N CP1102-2.5W CP1102-2.8W CP1160-10.4N CP1160-18.0W CP1160-3.6B -91.89786932 -91.89892949 -91.86387906 -91.85747736 -90.70259143 -90.68889261 -90.68599983 -90.682293 -90.65170238 -90.68853863 -90.68875209 -93.80520349 -93.80218542 -93.76083877 -93.75804769 -93.62331187 -93.7815815 -93.62424368 -93.58723235 -93.61782406 -90.87696345 -90.87057604 -90.87303928 -90.88260262 -94.06625387 -94.073708 -92.00852229 -92.00558161 -92.00428206 -91.98796006 -92.01354246 -92.01303041 -90.7329334 -90.77982377 -90.79654313 46.654603 46.658083 46.685852 46.691492 46.60847 46.606855 46.608234 46.610824 46.637791 46.566867 46.599295 47.251238 47.22488 47.225386 47.229131 47.262732 47.289422 47.262771 47.251317 47.262622 46.567021 46.592109 46.599507 46.596686 47.33055 47.327566 46.670628 46.672414 46.673559 46.691744 46.687109 46.697411 46.619641 46.630726 46.582861 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 5 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 7 7 7 7 7 7 7 6 6 6 6 6 6 3 3 3 4 4 4 4 2 2 6 6 6 6 6 6 4 4 4 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1493 Page 193 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Beartrap Creek Big Lake Big Lake Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Black River Black River Black River Black River Black River Black River Black River Black River Bluff Creek Bluff Creek Bluff Creek Bluff Creek Bois Brule River Bois Brule River Bois Brule River Bois Brule River Bois Brule River Bois Brule River Bois Brule River Bois Brule River Brevort River Brevort River CP1160-7.9B CP1066-1.0W CP1066-2.0E CP85-2.5B CP85-1.2S CP85-5.2B CP85-6.4B CP85-7.6W CP85-9.9B CP85-14.6E CP85-19.0S CP85-19.2B CP85-25.3E CP1200-0.4B CP1200-20.6W CP1200-3.8B CP1200-4.8B CP1200-9.0W CP1439-3.1B CP1439-3.3E CP1439-8.9W CP1101-0.6B CP1101-0.8B CP1101-1.0W CP1101-1.7W CP1121-0.1B CP1121-0.8E CP1121-12.4E CP1121-13.6E CP1121-5.5W CP1121-5.6E CP1121-7.6E CP1121-8.6W CP1464-3.5B CP1464-3.7S -90.76038234 -92.64059638 -92.62269442 -91.22085823 -91.24073746 -91.2058941 -91.21339365 -91.22424324 -91.22860871 -91.25245848 -91.25630508 -91.26040715 -91.28968159 -89.99607941 -90.04773288 -90.05294982 -90.07334829 -90.0746603 -85.34056087 -85.34391594 -85.44483218 -92.01595157 -92.01502637 -92.01354246 -92.01303041 -91.59756747 -91.59647366 -91.60194062 -91.6102563 -91.59455057 -91.59493695 -91.60260957 -91.60346476 -84.93645482 -84.93587303 46.609291 46.709678 46.701436 45.619824 45.614809 45.602861 45.591971 45.580994 45.552168 45.500856 45.453032 45.452642 45.391996 46.505292 46.666136 46.512134 46.511058 46.552535 46.094532 46.091395 46.087191 46.682181 46.683885 46.687109 46.697411 46.63301 46.638329 46.73613 46.747517 46.67613 46.677699 46.696771 46.70521 45.956822 45.954533 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 6 Control Points Upstream Lakehead in Series Pipelines 4 2 2 10 10 10 10 10 10 10 10 10 10 5 5 5 5 5 3 3 3 4 4 4 4 8 8 8 8 8 8 8 8 2 2 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1494 Page 194 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Briar Hill Creek Briar Hill Creek Briar Hill Creek Briar Hill Creek Cass Lake Cass Lake Cass Lake Cass Lake Cass Lake Cass Lake Cass Lake Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Cisco Branch Ontonagon River Cisco Branch Ontonagon River Cisco Branch Ontonagon River Cisco Branch Ontonagon River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Clearwater River Cooks Run Cooks Run Cooks Run Cooks Run CP1285-1.2B CP1285-3.4S CP1285-4.0B CP1285-4.2E CP956-0.0W CP956-0.4W CP956-0.5W CP956-0.6E CP956-3.0E CP956-3.5E CP956-3.5S CP88-2.4B CP88-7.0E CP88-11.5S CP88-11.7B CP88-17.8E CP88-24.4E CP1232-0.7B CP1232-17.3B CP1232-39.2E CP1232-7.0B CP875-0.9B CP875-13.8B CP875-2.2B CP875-23.3S CP875-31.7E CP875-6.3B CP922-0.3B CP922-12.1E CP922-18.3W CP922-8.7B CP1260-0.7B CP1260-10.2B CP1260-12.4W CP1260-14.7B -88.38585649 -88.35051859 -88.33763518 -88.33448987 -94.59023066 -94.59602619 -94.58890206 -94.57395784 -94.53617873 -94.52353026 -94.58398764 -91.22951988 -91.25212019 -91.25631628 -91.26075304 -91.29084959 -91.32713687 -89.39889375 -89.34334345 -89.27681 -89.45252169 -96.04961332 -96.12820953 -96.06058896 -96.22241556 -96.28187928 -96.07569539 -95.15545107 -95.16954255 -95.20726537 -95.17307916 -88.88132319 -88.76035129 -88.75427716 -88.71744265 46.10221 46.107317 46.107497 46.106782 47.381071 47.386612 47.372719 47.378869 47.362141 47.379845 47.329503 45.55231 45.500766 45.452921 45.452887 45.391804 45.338511 46.318601 46.409571 46.534184 46.336424 47.911129 47.843327 47.905272 47.86132 47.894007 47.876419 47.612967 47.691613 47.743903 47.672792 46.166611 46.208103 46.232574 46.23184 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 7 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 7 7 7 7 7 7 7 6 6 6 6 6 6 4 4 4 4 6 6 6 6 6 6 4 4 4 4 12 12 12 12 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1495 Page 195 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Cooks Run Cooks Run Cooks Run Cooks Run Cooks Run Cooks Run Cooks Run Cooks Run County Ditch No. 33 County Ditch No. 33 Cut River Davenport Creek Davenport Creek Deer River Denomie Creek Denomie Creek Denomie Creek Duck Creek Duck Creek Duck Creek Duck Creek Duck Creek Duck Creek Duck Creek Dutchman Creek East Savannah River East Savannah River East Savannah River East Savannah River Eau Claire River Eau Claire River Eau Claire River Eau Claire River Eau Claire River Escanaba River CP1260-15.6B CP1260-19.6N CP1260-2.2S CP1260-3.0N CP1260-4.8B CP1260-6.7B CP1260-7.6B CP1260-8.2E CP782-1.5B CP782-2.6B CP1452-0.8S CP1444-2.7B CP1444-3.3S CP995-2.6N CP1172-10.5B CP1172-11.0W CP1172-9.8B CP1244-0.7B CP1244-1.3B CP1244-10.8E CP1244-17.1B CP1244-5.1B CP1244-7.8B CP1244-9.6B CP1104-1.9W CP1046-1.1B CP1046-11.9S CP1046-19.9S CP1046-22.4E CP34-6.8N CP34-8.8W CP34-1.5B CP34-1.1B CP34-0.7B CP1342-0.8W -88.70019987 -88.63333597 -88.86202728 -88.84948372 -88.82089929 -88.78738403 -88.77151578 -88.76222077 -97.38025893 -97.35879564 -85.12672687 -85.2645628 -85.26110923 -93.79036961 -90.65226385 -90.65554236 -90.65466794 -89.17455012 -89.17581761 -89.05399764 -89.07684586 -89.12025586 -89.08601097 -89.0555875 -91.94308153 -92.91235916 -92.76456464 -92.60395253 -92.57527852 -91.88429648 -91.92686 -91.8002384 -91.79815455 -91.79335137 -87.27160819 46.229406 46.241704 46.176157 46.176759 46.181853 46.183431 46.185131 46.188287 48.904434 48.901681 46.044134 46.067419 46.062253 47.316911 46.601411 46.605168 46.594505 46.268118 46.27476 46.313332 46.35665 46.294397 46.299992 46.299127 46.679781 46.921148 46.874327 46.869418 46.848784 46.263476 46.25309 46.252057 46.248605 46.24481 45.993302 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 8 Control Points Upstream Lakehead in Series Pipelines 12 12 12 12 12 12 12 12 2 2 1 2 2 1 3 3 3 7 7 7 7 7 7 7 1 4 4 4 4 5 5 5 5 5 8 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1496 Page 196 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Escanaba River Escanaba River Escanaba River Escanaba River Escanaba River Escanaba River Escanaba River Escanaba River Trib. Escanaba River Trib. Floodwood Station Ditch Floodwood Station Ditch Floodwood Station Ditch Floodwood Station Ditch Floodwood Station Ditch Floodwood Station Ditch Floodwood Station Ditch Ford River Ford River Ford River Ford River Grant Creek Grant Creek Grant Creek Grant Creek Grant Creek Indian River Indian River Indian River Indian River Indian River Indian River Indian River Indian River Indian River Iron River CP1342-10.1S CP1342-19.3W CP1342-22.1W CP1342-23.2W CP1342-23.3B CP1342-24.8S CP1342-8.8B CP1337-0.5B CP1337-6.4W CP1044-0.2B CP1044-0.3B CP1044-0.7W CP1044-1.5B CP1044-1.6W CP1044-1.8N CP1044-12.8S CP1316-11.1B CP1316-15.4B CP1316-19.7B CP1316-2.0S CP927-12.3B CP927-2.2B CP927-5.2B CP927-6.6B CP927-9.6B CP1393-1.0W CP1393-1.7N CP1393-2.0S CP1393-2.5W CP1393-3.7W CP1508-0.3S US CP1508-1.2W US CP1508-2.3S CP1508-6.0W CP1130-0.1B -87.19631007 -87.09134263 -87.09595271 -87.08103024 -87.07820598 -87.06422909 -87.21317899 -87.3510286 -87.27166377 -92.93384642 -92.93239672 -92.92306047 -92.92028079 -92.91698378 -92.91454982 -92.76452715 -87.63975033 -87.57380419 -87.53662925 -87.76892797 -95.01309685 -95.05552922 -95.03786316 -95.02696931 -94.98614965 -86.23165357 -86.2358585 -86.24239928 -86.24826532 -86.24839286 -84.60862341 -84.62806767 -84.58178524 -84.58497405 -91.42247746 45.895128 45.840222 45.804594 45.796518 45.794944 45.777949 45.909238 46.031563 45.993334 46.939637 46.939555 46.93936 46.929776 46.929183 46.927783 46.874205 46.084203 46.061007 46.02959 46.077121 47.484178 47.558208 47.527752 47.513257 47.501572 45.976238 45.973392 45.970564 45.966389 45.951192 45.412817 45.403593 45.439484 45.48754 46.618802 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 9 Control Points Upstream Lakehead in Series Pipelines 8 8 8 8 8 8 8 2 2 7 7 7 7 7 7 7 4 4 4 4 5 5 5 5 5 5 5 5 5 5 4 4 4 4 7 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1497 Page 197 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Iron River Kallander Creek Kallander Creek Kallander Creek Kankakee River Kankakee River Kankakee River Kankakee River Kankakee River Little Otter Creek Little Otter Creek Little Otter Creek Little Otter Creek Little Pokegama River Little Pokegama River Lost River Lost River Lost River Lost River CP1130-15.5E CP1130-15.9N CP1130-17.4E CP1130-5.3B CP1130-8.2E CP1130-9.7E CP1272-1.0B CP1272-14.9N CP1272-19.7B CP1272-2.8B CP1272-4.0B CP1272-5.0N CP1272-5.6W CP1272-7.0B CP1272-7.8N CP1272-8.8B CP1272-8.9B CP1197-0.8B CP1197-18.0W CP1197-2.0B CP37-0.8S CP37-15.7N CP37-5.4S CP37-9.3E CP37-9.4W CP1074-0.7S CP1074-12.7N CP1074-4.7B CP1074-5.6B CP1090-1.1B CP1090-5.8B CP886-1.4N CP886-14.3B CP886-14.9B CP886-2.9B -91.484546 -91.49206482 -91.48739059 -91.4470982 -91.46689611 -91.46868353 -88.67830069 -88.56644149 -88.50112225 -88.67666771 -88.65788843 -88.64074213 -88.63584318 -88.63704749 -88.62849477 -88.62693941 -88.62849477 -90.05294982 -90.04773288 -90.07334829 -88.05528107 -88.21736335 -88.13256041 -88.15010111 -88.14718706 -92.48490454 -92.30854169 -92.42439955 -92.4126048 -92.19261912 -92.16712125 -95.88033238 -96.00437703 -96.01009941 -95.90196539 46.747092 46.748703 46.765511 46.655208 46.675807 46.691948 46.115884 46.015456 46.001576 46.100371 46.093839 46.097105 46.090573 46.07353 46.066895 46.058377 46.057097 46.512134 46.666136 46.511058 41.226608 41.359226 41.250203 41.300945 41.302984 46.648997 46.667816 46.660885 46.662635 46.623734 46.659865 47.842629 47.842909 47.843191 47.845472 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Mid Continent Mid Continent Mid Continent Mid Continent Mid Continent Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 10 Control Points Upstream Lakehead in Series Pipelines 7 7 7 7 7 7 11 11 11 11 11 11 11 11 11 11 11 8 8 8 8 8 8 8 8 4 4 4 4 2 2 6 6 6 6 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 62,Line 78 Line 6A,Line14,Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 62,Line 78 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1498 Page 198 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Lost River Lost River Lost River Lost River Lost River Lost River Lost River Lost River Lost River Lost River Lost River Lost River Louden Coulee Lower Millecoquins River Manistique River Manistique River Manistique River Manistique River Michigamme River Michigamme River Michigamme River Michigamme River Michigamme River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle Branch Ontonagon River Middle River Middle River Middle River Mississippi River CP886-4.5S CP886-8.9B CP904-2.3B CP904-2.5B CP904-3.5B CP904-3.7B CP904-3.8S CP904-6.5B CP904-6.8B CP904-7.2B CP904-8.7N CP904-9.2B CP781-0.4N CP1434-4.6B CP1394-2.4N CP1394-2.8S CP1394-3.3W CP1394-4.5W CP1295-0.6W CP1295-10.0N CP1295-11.2E CP1295-15.0E CP1295-8.5N CP1237-1.0B CP1237-10.4S CP1237-14.4B CP1237-17.1B CP1237-18.9B CP1237-20.2E CP1237-26.5B CP1237-5.4B CP1111-0.4 CP1111-0.7 CP1111-5.6W CP940-1.1E -95.92347988 -95.96644766 -95.51679791 -95.51918703 -95.51825114 -95.51655245 -95.51415538 -95.49483114 -95.49447263 -95.49508136 -95.49822052 -95.50626017 -97.41618605 -85.47399499 -86.2358585 -86.24239928 -86.24826532 -86.24839286 -88.2231918 -88.22336212 -88.20561946 -88.19513924 -88.20927534 -89.29018187 -89.17652378 -89.12025586 -89.08601714 -89.05559 -89.05399764 -89.07685094 -89.24085975 -91.80481209 -91.80492197 -91.82882382 -94.86922512 47.842116 47.850566 47.730439 47.731672 47.737515 47.739624 47.740182 47.757137 47.760717 47.76498 47.775063 47.775203 48.919958 46.095575 45.973392 45.970564 45.966389 45.951192 46.084094 46.015527 45.991992 45.956349 46.023988 46.284916 46.274569 46.294397 46.299994 46.299125 46.313332 46.356653 46.276805 46.647457 46.650955 46.689699 47.458777 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 11 Control Points Upstream Lakehead in Series Pipelines 6 6 10 10 10 10 10 10 10 10 10 10 1 1 4 4 4 4 5 5 5 5 5 8 8 8 8 8 8 8 8 3 3 3 3 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1499 Page 199 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Mississippi River Montreal River Montreal River Montreal River Montreal River Morrison Creek Mud Creek Mud Creek Mud Creek Mud Creek Mud Creek Mud Creek Mud Creek Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River Namekagon River CP940-1.4E CP940-1.6S CP986-13.0E CP986-17.1W CP986-19.5W CP986-23.7E CP986-24.0B CP986-4.6N CP986-4.7B CP986-7.9S CP1189-0.7W CP1189-18.5S CP1189-22.2B CP1189-9.1S CP1105-2.2N CP452-2.0W CP452-3.5E CP452-18.2E CP452-16.3E CP452-7.8E CP452-9.4S CP452-12.8E CP54-1.7B CP54-3.9S CP54-6.0B CP54-6.4S CP54-24.9S CP54-8.9W CP54-11.3W CP54-22.6S CP54-15.0N CP54-16.5B CP54-19.6N CP54-19.8S CP54-19.0N -94.87941882 -94.87712099 -93.78153202 -93.80520349 -93.80218542 -93.76083877 -93.75804769 -93.90336276 -93.90152695 -93.86112335 -90.21496334 -90.37455943 -90.4143952 -90.30249348 -91.936336 -88.67926325 -88.68146444 -88.75736103 -88.74041741 -88.68651853 -88.70063344 -88.7193389 -91.63484629 -91.65531262 -91.68111843 -91.68644632 -91.88852695 -91.72075003 -91.75032152 -91.86825779 -91.76414028 -91.78127463 -91.82471075 -91.82543823 -91.81547942 47.465612 47.468466 47.289363 47.251238 47.22488 47.225386 47.229131 47.302107 47.301995 47.313264 46.498264 46.53873 46.557331 46.517433 46.680766 41.047984 41.033564 41.025464 41.018541 41.007771 41.005506 41.005472 45.995787 45.975761 45.956971 45.953488 45.94765 45.942296 45.932285 45.921476 45.915905 45.910326 45.909572 45.906953 45.906549 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Mid Continent Mid Continent Mid Continent Mid Continent Mid Continent Mid Continent Mid Continent Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 12 Control Points Upstream Lakehead in Series Pipelines 3 3 8 8 8 8 8 8 8 8 4 4 4 4 1 7 7 7 7 7 7 7 13 13 13 13 13 13 13 13 13 13 13 13 13 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1500 Page 200 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Nash Creek Necktie River Necktie River Necktie River Necktie River Necktie River Necktie River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River Nemadji River North Fish Creek North Fish Creek North Fish Creek Paint River Paint River CP1270-0.8B CP1270-10.0N CP1270-11.0B CP1270-11.1B CP1270-17.2N CP1270-3.5B CP1270-5.0B CP1270-6.3B CP1270-7.3N CP1270-7.9W CP1270-9.2B CP945-1.3B CP945-11.4B CP945-12.7B CP945-2.9B CP945-5.9B CP945-8.4B CP1099-0.0N CP1099-0.4N CP1099-1.4N CP1099-1.6B CP1099-1.7B CP1099-2.3W CP2-5.3W CP2-4.7B CP2-4.6B CP2-4.4N CP2-3.4N CP2-3.0N CP2-1.7N CP1150-3.0B CP1150-4.0B CP1150-6.8W CP1290-0.2W CP1290-10.6E -88.70204601 -88.62785 -88.62684849 -88.62844836 -88.56621945 -88.67811181 -88.67631675 -88.65776775 -88.64041546 -88.63562862 -88.63704749 -94.77743081 -94.73678989 -94.75046388 -94.75565746 -94.73401309 -94.73397332 -92.04829525 -92.04172982 -92.03720959 -92.034765 -92.03275178 -92.03499337 -92.03440696 -92.03275487 -92.03477015 -92.03720425 -92.0416933 -92.04772338 -92.06060801 -90.97575 -90.96594984 -90.94496169 -88.31212332 -88.20552461 46.126223 46.066986 46.058372 46.057412 46.015527 46.116051 46.099895 46.093912 46.096904 46.090322 46.07353 47.388655 47.3097 47.296979 47.383471 47.362494 47.337386 46.686149 46.689025 46.694796 46.697218 46.697471 46.700452 46.699811 46.697474 46.697222 46.694786 46.689084 46.686136 46.680919 46.574899 46.578705 46.588608 46.08364 45.991861 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 13 Control Points Upstream Lakehead in Series Pipelines 11 11 11 11 11 11 11 11 11 11 11 6 6 6 6 6 6 6 6 6 6 6 6 7 7 7 7 7 7 7 3 3 3 12 12 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1501 Page 201 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Paint River Paint River Paint River Paint River Paint River Paint River Paint River Paint River Paint River Paint River Parks Creek Tributary Parks Creek Tributary Parks Creek Tributary Parks Creek Tributary Pelton Creek Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pembina Pigeon River Pigeon River Pigeon River Pigeon River Pigeon River Pigeon River Pigeon River Pigeon River CP1290-10.8W CP1290-12.9S CP1290-14.4E CP1290-15.0S CP1290-4.0W CP1290-6.9E CP1290-7.5W CP1290-8.0B CP1290-8.1W CP1290-8.9N CP1297-13.2E CP1297-7.8N CP1297-8.3N CP1297-9.4E CP1222-4.0W CP776-0.8S CP776-1.9B CP776-11.9B CP776-15.9S CP776-18.0S CP776-21.5B CP776-25.9S CP776-26.7B CP776-28.6B CP776-28.7W CP776-6.8B CP776-8.3B CP1529-11.0B CP1529-13.2E CP1529-15.9B CP1529-17.5E CP1529-2.0B CP1529-23.0B CP1529-25.9B CP1529-26.9B -88.27599995 -88.2498812 -88.1950118 -88.21925761 -88.27181632 -88.25757189 -88.25824377 -88.24179426 -88.26198487 -88.22327265 -88.19491336 -88.20947334 -88.2237078 -88.20544345 -89.55105555 -97.50166559 -97.48833769 -97.40390769 -97.35909953 -97.33387827 -97.29389767 -97.26916354 -97.25997641 -97.24272638 -97.23854516 -97.44707491 -97.43497855 -84.42889337 -84.44619812 -84.45974343 -84.46757087 -84.4728809 -84.49483536 -84.50741128 -84.51475557 45.981455 45.963115 45.956367 45.947043 46.050213 46.021623 46.013157 46.015038 46.005381 46.015361 45.956862 46.023619 46.015755 45.991704 46.409417 48.977627 48.978583 48.956227 48.94925 48.94835 48.943037 48.955651 48.956146 48.966246 48.965169 48.967571 48.963267 45.224219 45.244448 45.271995 45.289334 45.145838 45.330403 45.364159 45.374516 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 14 Control Points Upstream Lakehead in Series Pipelines 12 12 12 12 12 12 12 12 12 12 4 4 4 4 1 12 12 12 12 12 12 12 12 12 12 12 12 10 10 10 10 10 10 10 10 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1502 Page 202 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Pigeon River Pigeon River Planter Creek Planter Creek Planter Creek Planter Creek Planter Creek Planter Creek Planter Creek Planter Creek Pokegama River Pokegama River Pokegama River Poplar River Poplar River Poplar River Prairie River Prairie River Prairie River Prairie River Prairie River Prairie River Prairie River Presque Isle River Presque Isle River Presque Isle River Presque Isle River Presque Isle River Presque Isle River Presque Isle River Presque Isle River Rapid River Rapid River Rapid River Red Lake River CP1529-3.2B CP1529-6.8B CP1203-0.3B CP1203-12.8W CP1203-2.6W CP1203-24.4W CP1203-3.1B CP1203-4.3S CP1203-7.5B CP1203-8.6B CP1094-1.2B CP1094-1.8B CP1094-2.8E CP1112-1.1B CP1112-6.4B CP1112-7.2E CP1011-0.1W CP1011-0.5B CP1011-1.4B CP1011-15.1W CP1011-17.5E CP1011-33.1W CP1011-8.1N CP1217-1.6W CP1217-18.1B CP1217-2.1W CP1217-28.0B CP1217-3.4B CP1217-36.2B CP1217-37.1W CP1217-5.0B CP1357-0.7E CP1357-1.5B CP1357-2.7E CP864-2.3B -84.46763875 -84.42623394 -89.93635181 -90.07452812 -89.97228612 -90.04773288 -89.97974685 -89.99677444 -90.05294982 -90.07334829 -92.11906083 -92.12686144 -92.13456087 -91.78544264 -91.79266672 -91.79653624 -93.48942521 -93.48631427 -93.47864277 -93.40521791 -93.39038492 -93.32287826 -93.41827661 -89.6993695 -89.77776826 -89.69587891 -89.87744125 -89.68150494 -89.97412169 -89.97257945 -89.69418661 -86.96524947 -86.96363272 -86.96572409 -96.20279914 45.156266 45.177309 46.5047 46.552222 46.510699 46.666136 46.509512 46.506086 46.512134 46.511058 46.661803 46.665869 46.671349 46.64824 46.687176 46.69349 47.251405 47.246107 47.219371 47.129115 47.108414 47.034295 47.17347 46.409308 46.547314 46.415276 46.641991 46.430149 46.695798 46.708112 46.445091 45.937535 45.926555 45.914266 48.020438 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 15 Control Points Upstream Lakehead in Series Pipelines 10 10 8 8 8 8 8 8 8 8 3 3 3 3 3 3 7 7 7 7 7 7 7 8 8 8 8 8 8 8 8 3 3 3 8 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1503 Page 203 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Red Lake River Red Lake River Red Lake River Red Lake River Red Lake River Red Lake River Red Lake River Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North Red River of the North S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Br. Iron River S. Branch Paint River S. Branch Paint River CP864-21.5B CP864-23.0B CP864-25.6B CP864-26.3S CP864-3.2W CP864-4.7N CP864-9.6W CP802-0.1W US CP802-0.4E CP802-1.3E CP802-12.9N CP802-15.8E CP802-18.2E CP802-2.4W CP802-2.7E CP802-3.9W CP802-5.1N CP802-6.2E CP802-7.3E CP802-9.3E CP1268-0.3B CP1268-0.8B CP1268-10.4B CP1268-11.2N CP1268-12.3B CP1268-12.4B CP1268-18.4N CP1268-2.0B CP1268-4.7B CP1268-6.4B CP1268-7.6B CP1268-8.6N CP1268-9.2W CP1254-0.3B CP1254-11.1B -96.24008366 -96.25994102 -96.27492877 -96.28190832 -96.21075759 -96.20852152 -96.19376061 -97.12180982 -97.10889765 -97.12238192 -97.17203931 -97.18117701 -97.17375996 -97.13784401 -97.12836092 -97.14159864 -97.14452429 -97.14659307 -97.15146686 -97.15756278 -88.73117841 -88.72357786 -88.63731814 -88.62808652 -88.62705013 -88.62829318 -88.56623135 -88.70196523 -88.67819907 -88.6766148 -88.65799374 -88.64047392 -88.63555216 -88.99529708 -88.86877351 47.891947 47.894237 47.897152 47.893879 48.010808 48.00939 47.962947 48.702039 48.707334 48.716555 48.803828 48.818136 48.842736 48.727024 48.730896 48.737778 48.751383 48.761476 48.772687 48.787781 46.126772 46.124271 46.073465 46.066895 46.058446 46.057441 46.01552 46.125944 46.116134 46.10007 46.093785 46.096741 46.090528 46.193114 46.225729 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 16 Control Points Upstream Lakehead in Series Pipelines 8 8 8 8 8 8 8 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1504 Page 204 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River S. Branch Paint River Sand Creek Sand Creek Sand Creek Sand Creek Siemens Creek Siemens Creek Siemens Creek Siemens Creek Siemens Creek Siemens Creek Siemens Creek Six Mile Lake Tributary Ditch Slate River South Fish Creek South Fish Creek Spoon Creek Spoon Creek Spoon Creek Spoon Creek Tributary St. Croix River St. Croix River St. Croix River Stoney Brook Stoney Brook CP1254-16.0B CP1254-18.7B CP1254-19.6B CP1254-2.0W CP1254-20.2E CP1254-22.2B CP1254-24.7N CP1254-26.8B CP1254-27.7B CP1254-5.2B CP1254-6.9B CP66-1.1B CP66-0.2B CP66-0.3N-US CP66-1.6S CP1194-0.1W CP1194-13.7S CP1194-23.1S CP1194-3.0B CP1194-4.1B CP1194-5.1B CP1194-6.2B CP975-3.8E CP1224-4.4W CP1153-1.8B CP1153-4.0W CP1177/1178-5.0B CP1177/1178-5.3W CP1177-0.4E CP1178-0.1W CP33-5.6N CP33-7.6W CP33-0.2B CP1062-0.1E CP1062-10.3B -88.81986077 -88.78731425 -88.77151945 -88.97709754 -88.76359826 -88.76033888 -88.7517487 -88.71735415 -88.70021832 -88.93897707 -88.90916606 -91.45723177 -91.47157552 -91.4784699 -91.45701604 -90.12436955 -90.30249348 -90.374106 -90.15591833 -90.17691986 -90.19752829 -90.21863157 -94.12463061 -89.55159957 -90.95220876 -90.94496169 -90.43975665 -90.43681013 -90.45300739 -90.44844578 -91.88429648 -91.92686 -91.80022302 -92.67521356 -92.60707204 46.191275 46.18343 46.18513 46.207722 46.18912 46.208114 46.234416 46.231829 46.229329 46.227399 46.221448 45.860969 45.855027 45.851504 45.850494 46.500946 46.517433 46.53913 46.512877 46.513398 46.515863 46.514421 47.309629 46.410765 46.571067 46.588608 46.560442 46.562414 46.514163 46.51064 46.263476 46.25309 46.252026 46.756737 46.854708 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 17 Control Points Upstream Lakehead in Series Pipelines 13 13 13 13 13 13 13 13 13 13 13 4 4 4 4 7 7 7 7 7 7 7 1 1 2 2 3 3 3 1 3 3 3 5 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1505 Page 205 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Stoney Brook Stoney Brook Stoney Brook Straits of Mackinac Straits of Mackinac Straits of Mackinac Straits of Mackinac Sturgeon River Sturgeon River Sturgeon River Sturgeon River Sturgeon River Sturgeon River Sturgeon River Sturgeon River Sturgeon River Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Summit Creek Swan River CP1062-10.8E CP1062-3.4B CP1062-5.7E CP1477-3.8E CP1477-4.0E CP1477-5.0E CP1477-6.9E CP1370-0.4W CP1370-10.5W CP1370-13.3B CP1370-14.2W CP1370-14.7B CP1370-14.9E CP1370-15.2E CP1370-6.2B CP1370-7.7W CP71-3.6N CP71-3.9N CP71-4.3N CP71-7.3N CP71-1.2B CP71-7.8N CP71-1.0B CP71-6.1B CP71-8.9N CP71-8.3B CP71-8.5S CP71-0.4B CP71-10.9B CP71-11.8B CP71-14.0S CP71-14.1B CP71-23.7E CP71-32.3W CP1024-1.5E -92.60449763 -92.63705135 -92.62436417 -84.72438748 -84.72359639 -84.70268132 -84.72510372 -86.70547651 -86.67890697 -86.66948355 -86.67555697 -86.66863258 -86.66709598 -86.66231039 -86.7037272 -86.69969114 -91.3972599 -91.3917502 -91.38542124 -91.3333352 -91.42566257 -91.32394866 -91.42779206 -91.35234876 -91.30506612 -91.31762345 -91.31372322 -91.43475253 -91.27820438 -91.26660502 -91.22493348 -91.22166149 -91.18100618 -91.22390748 -93.26196697 46.861721 46.781508 46.810005 45.780421 45.777938 45.854355 45.874975 45.936056 45.86633 45.850718 45.844996 45.84088 45.838442 45.838617 45.89548 45.882834 45.803825 45.801483 45.800154 45.800148 45.797707 45.797138 45.79569 45.795313 45.793475 45.792878 45.792092 45.78993 45.776999 45.770605 45.766622 45.765834 45.671085 45.581524 47.10891 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 18 Control Points Upstream Lakehead in Series Pipelines 5 5 5 4 4 4 4 9 9 9 9 9 9 9 9 9 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 4 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 1,Line 2B,Line 3,Line4,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1506 Page 206 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Swan River Swan River Swan River Tacoosh River Tacoosh River Tacoosh River Tacoosh River Tacoosh River Tacoosh River Tacoosh River Tamarac River Tamarac River Tamarac River Tamarac River Tamarac River Tamarac River Thornapple River Thornapple River Thornapple River Thornapple River Thornapple River Thornapple River Thornapple River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Tongue River Cutoff Tongue River Cutoff CP1024-13.2B CP1024-14.7B CP1024-15.5B CP1353-1.0B CP1353-4.0B CP1353-5.7B CP1353-6.3B CP1353-7.2B CP1353-7.5B CP1353-8.7E CP829-11.2S CP829-12.2B CP829-15.1B CP829-2.0S CP829-3.5B CP829-9.4B CP94-4.8B CP94-7.2S CP94-7.5B CP94-13.6E CP94-20.0E CP94-28.1N CP94-26.1B CP786-0.6B CP786-1.9B CP786-12.4S CP786-13.2B CP786-15.1B CP786-15.2W CP786-3.5E CP786-4.9B CP786-6.3B CP786-8.0B CP783-0.5B CP783-2.5B -93.25293519 -93.23365214 -93.22883717 -87.05282331 -87.01340011 -86.99079982 -86.98224007 -86.9737912 -86.97140142 -86.96600607 -96.79473853 -96.80249808 -96.82393465 -96.7358511 -96.7472321 -96.78353653 -91.23618554 -91.25630399 -91.2604634 -91.2896311 -91.3268417 -91.19822976 -91.23734924 -97.3467139 -97.3447455 -97.26949324 -97.25995489 -97.24273563 -97.23795914 -97.32769395 -97.3189263 -97.30171851 -97.29381392 -97.38120749 -97.33735646 47.057189 47.054274 47.051095 45.955874 45.945215 45.942315 45.937668 45.930527 45.926625 45.914784 48.396576 48.401966 48.404204 48.41204 48.412073 48.400421 45.474586 45.452923 45.452657 45.391895 45.339053 45.304857 45.297463 48.876315 48.890867 48.955817 48.956318 48.966207 48.96619 48.90537 48.919943 48.934318 48.943111 48.898078 48.898271 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior 19 Control Points Upstream Lakehead in Series Pipelines 4 4 4 7 7 7 7 7 7 7 6 6 6 6 6 6 7 7 7 7 7 7 7 10 10 10 10 10 10 10 10 10 10 2 2 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 1,Line 2B,Line 3,Line4,Line67 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Line 1,Line 2B,Line 3,Line4,Line 65,Line67 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1507 Page 207 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Totogatic River Welch Creek Welch Creek Welch Creek Welch Creek West Mile Creek West Mile Creek West Mile Creek White Fish River White Fish River White Fish River White River White River White River White River White River Aux Sable Creek Aux Sable Creek Aux Sable Creek Aux Sable Creek Beaver Creek Beaver Creek Beaver Creek Beaver Creek Beaver Creek CP41-21.1N CP41-20.0B CP41-18.5W CP41-17.5W CP41-22.2E CP41-1.5B CP41-10.5B CP41-9.9B CP41-23.3W CP41-8.0B CP41-25.0W CP1191-0.3B CP1191-11.8S CP1191-2.4B CP1191-21.3S CP1436-1.6B CP1436-1.7S CP1436-3.1W CP1358-1.7B CP1358-2.9E CP1358-3.9E CP1163-10.0N CP1163-10.1E CP-1163-10.5E CP1163-14.6S CP-1163-9.2W CP434-4.1 CP434-7.0 CP434-10.0 CP434-14.6 CP351-11.8 CP351-17.8 CP351-19.4 CP351-2.8 CP351-5.6 -91.92425983 -91.90062215 -91.88789495 -91.88216823 -91.92289226 -91.75297055 -91.82320277 -91.8141471 -91.93978487 -91.8099014 -91.93455418 -90.17676941 -90.30249348 -90.19781332 -90.37456204 -85.42741222 -85.4271862 -85.4445857 -86.94611627 -86.95125818 -86.96659383 -90.68889106 -90.68599634 -90.682293 -90.65162242 -90.70259493 -88.30035124 -88.3089039 -88.34780613 -88.33062937 -88.851611 -88.905096 -88.909752 -88.789018 -88.793787 46.17116 46.16907 46.158049 46.15412 46.152317 46.15044 46.14638 46.143507 46.139545 46.131038 46.120335 46.497282 46.517433 46.508519 46.538734 46.102695 46.101754 46.086948 45.925683 45.908815 45.914327 46.606849 46.608183 46.610824 46.637757 46.608521 41.48341768 41.45409368 41.41704931 41.39657492 42.327651 42.305377 42.290907 42.393167 42.363949 Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Superior Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 20 Control Points Upstream Lakehead in Series Pipelines 11 11 11 11 11 11 11 11 11 11 11 4 4 4 4 3 3 3 3 3 3 5 5 5 5 5 4 4 4 4 5 5 5 5 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 14 Line 14 Line 14 Line 14 Line 61 Line 61 Line 61 Line 61 Line 61 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1508 Page 208 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Big Rock Creek Big Rock Creek Big Rock Creek Big Rock Creek Big Rock Creek Boone Creek Boone Creek Boone Creek Boone Creek Boone Creek Boone Creek Boone Creek Boone Creek Boone Creek Chicago Sanitary & Ship Canal Chicago Sanitary & Ship Canal Chicago Sanitary & Ship Canal Chicago Sanitary & Ship Canal Chicago Ship Canal/Des Plaines Chicago Ship Canal/Des Plaines Deer Creek Deer Creek Deer Creek Deer Creek Des Plaines River Des Plaines River Des Plaines River Des Plaines River Des Plaines River DuPage River DuPage River DuPage River DuPage River DuPage River DuPage River CP408-1.9 CP408-2.7 CP408-4.2 CP408-6.1 CP408-8.6 CP365-2.1 CP365-3.4 CP365-5.3N CP365-5.2 CP365-7.8 CP365-9.9 CP365-14.6 CP365-16.2 CP365-20.3 CP425-10.3 CP425-18.5 CP425-24.0 CP425-8.0 CP425-1.2 CP425-5.5 CP458-4.3 CP458-6.4 CP458-3.5 CP458-2.0 CP445-12.0 CP445-6.5 CP445-9.5 CP425-3.7 CP425-4.8 CP440-6.1 CP418-1.8 CP418-3.6 CP418-5.8 CP418-9.1 CP418-13.3 -88.50772205 -88.49812602 -88.493917 -88.51464629 -88.52408327 -88.30479088 -88.29229699 -88.26156436 -88.26234205 -88.25021697 -88.22794351 -88.21429677 -88.18645819 -88.2139579 -88.09751422 -88.19538513 -88.21740401 -88.08359939 -88.06429946 -88.07792333 -87.60943782 -87.62509848 -87.59728678 -87.59001481 -88.21740401 -88.19538513 -88.23064674 -88.0687561 -88.07234172 -88.22822223 -88.19078345 -88.20172148 -88.22435317 -88.1893377 -88.20041594 41.73336806 41.72804591 41.7138625 41.69491516 41.66645081 42.33302688 42.34598715 42.34375985 42.3430018 42.30962455 42.28498698 42.24326865 42.23878433 42.2049571 41.508803 41.422984 41.359276 41.537948 41.628446 41.569848 41.54141766 41.54759689 41.53646912 41.52082259 41.359276 41.422984 41.391668 41.59620322 41.58200307 41.42017913 41.6368282 41.61697109 41.59239937 41.56520459 41.51871261 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 21 Control Points Upstream Lakehead in Series Pipelines 5 5 5 5 5 9 9 9 9 9 9 9 9 9 4 4 4 4 2 2 4 4 4 4 5 5 5 5 5 7 7 7 7 7 7 Line 14 Line 14 Line 14 Line 14 Line 14 Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 14,Line 6A Line 6A,Line14,Line 62,Line 78 Line 6A Line 6A Line 6A Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line14,Line 62,Line 78 Line 14,Line 6A Line 14,Line 6A Line 6A Line 6A Line 14,Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1509 Page 209 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude DuPage River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Fox River Hickory Creek Hickory Creek Hickory Creek Hickory Creek Hickory Creek Hickory Creek Hickory Creek Illinois River CP440-1.4 CP421-11.9 CP421-13.0 CP421-19.0 CP421-21.2 CP421-4.5 CP421-7.3 CP419-14.1 CP419-20.3 CP419-1.0 CP419-4.4 CP419-6.2 CP419-9.5 CP419-11.8 CP377-3.3 CP377-4.9 CP377-6.3 CP377-7.4 CP377-8.2 CP377-9.3 CP377-11.5 CP377-12.1 CP377-13.5 CP377-16.3 CP377-20.1 CP377-25.1E CP377-25.1W CP447-6.3 CP447-8.9 CP447-11.5 CP447-12.9 CP447-3.1 CP447-2.0 CP447-4.9 CP432-10.3 -88.20923828 -88.83238919 -88.84215941 -88.94596497 -88.98207202 -88.77324572 -88.79020986 -88.68578027 -88.76300963 -88.56279679 -88.59981046 -88.62472501 -88.68418702 -88.69902859 -88.28262913 -88.29351082 -88.27827065 -88.28457071 -88.29364383 -88.28170835 -88.27401582 -88.27225027 -88.28906898 -88.27816689 -88.30047961 -88.31635068 -88.31856137 -87.84979997 -87.88894849 -87.92785678 -87.94850837 -87.81710182 -87.80256483 -87.83223395 -88.94578819 41.46802367 41.349762 41.343536 41.320585 41.323583 41.426895 41.38765 41.48628897 41.43998187 41.60700651 41.56881389 41.5543047 41.54013215 41.51297534 42.1710785 42.15166617 42.13834555 42.12541633 42.11460582 42.10156446 42.07619613 42.06795843 42.05395546 42.01804681 41.96978016 41.92007026 41.92018422 41.52083534 41.5180907 41.51803257 41.52538417 41.4979215 41.49447532 41.51364801 41.320658 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 22 Control Points Upstream Lakehead in Series Pipelines 7 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 7 7 7 7 7 7 7 4 Line 14,Line 6A Line 62,Line 14 Line 62,Line 14 Line 62,Line 14 Line 62,Line 14 Line 62,Line 14 Line 62,Line 14 Line 14 Line 62,Line 14 Line 14 Line 14 Line 14 Line 14 Line 14 Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A,Line 64 Line 6A,Line 64 Line 6A,Line 14,Line 64 Line 6A,Line 14,Line 64 Line 6A,Line 64 Line 6A,Line 64 Line 6A,Line 64 Line 62,Line 14 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1510 Page 210 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Illinois River Illinois River Illinois River Kishwaukee Coon Kishwaukee Coon Kishwaukee Coon Kishwaukee Coon Kishwaukee Coon Kishwaukee Coon Kishwaukee River Kishwaukee River Kishwaukee River Kishwaukee River Kishwaukee River Kishwaukee River Lily Cache Creek Lily Cache Creek Little Rock Creek Little Rock Creek Little Rock Creek Marley Creek Marley Creek Marley Creek Marley Creek Piscasaw Creek Piscasaw Creek Piscasaw Creek Piscasaw Creek Piscasaw Creek Piscasaw Creek Poplar Creek Rock Run S Br. Kish MP50.61 S Br. Kish MP50.61 S Br. Kish MP50.61 CP432-10.3 CP432-12.4 CP432-4.3 CP363-10.6 CP363-12.7 CP363-17.4 CP363-2.5 CP363-21.2 CP363-3.7 CP369-3.3 CP369-4.2 CP369-6.4 CP369-7.9 CP369-11.6 CP369-14.5 CP420-2.0 CP420-3.1 CP415-4.5 CP415-1.9 CP415-5.8 CP438-1.6 CP438-2.5 CP438-3.5X CP438-4.6 CP356-10.5 CP356-12.6 CP356-19.3 CP356-5.5 CP356-7.5 CP356-9.0 CP388-3.6 CP441-4.7 CP374-12.2 CP374-13.1 CP374-15.9 -88.93976184 -88.9816947 -88.84178275 -88.93011487 -88.95467707 -88.9995664 -88.82810461 -89.05602268 -88.84449951 -88.54038 -88.5598261 -88.58887312 -88.60844196 -88.66470448 -88.70545504 -88.16924533 -88.1685486 -88.53814647 -88.57337089 -88.55216815 -87.91709644 -87.92884556 -87.93382069 -87.93757376 -88.81760895 -88.84651427 -88.93015182 -88.80647028 -88.81029584 -88.80996236 -88.27466911 -88.2314672 -88.93319374 -88.93972269 -88.95082025 41.311151 41.323524 41.34215 42.253832 42.235972 42.194468 42.263274 42.182936 42.258857 42.26719172 42.26343771 42.26469105 42.2654553 42.26593166 42.25639826 41.63783359 41.60897264 41.63516129 41.64606294 41.62199607 41.55662263 41.54875556 41.54157062 41.53196925 42.262493 42.256853 42.253803 42.309018 42.291518 42.276877 42.01398648 41.43366048 42.137823 42.147962 42.180044 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 23 Control Points Upstream Lakehead in Series Pipelines 4 4 4 6 6 6 6 6 6 6 6 6 6 6 6 2 2 3 3 3 4 4 4 4 6 6 6 6 6 6 1 1 6 6 6 Line 62,Line 14 Line 62,Line 14 Line 62,Line 14 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 14 Line 14 Line 14 Line 14 Line 14 Line 14 Line 6A Line 6A Line 14 Line 14 Line 14 Line 6A Line 6A Line 6A Line 6A Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 6A Line 14,Line 6A Line 61 Line 61 Line 61 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1511 Page 211 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude S Br. Kish MP50.61 S Br. Kish MP50.61 S Br. Kish MP50.61 S Br. Kish MP67.8 S Br. Kish MP67.8 S Br. Kish MP67.8 S Br. Kish MP67.8 S Br. Kish MP67.8 South Branch Kishwaukee River South Branch Kishwaukee River Thorn Creek Unnamed Creek Unnamed Creek Unnamed Creek Waubonsie Creek Waubonsie Creek Waubonsie Creek Waubonsie Creek Waubonsie Creek West Branch DuPage River West Branch DuPage River West Branch DuPage River West Branch DuPage River Plum Creek Plum Creek Plum Creek Plum Creek Salt Creek Salt Creek Salt Creek Turkey Creek Turkey Creek Au Sable River Au Sable River Au Sable River CP374-3.5 CP374-5.5 CP374-8.4 CP390-1.8 CP390-10.1 CP390-14.1 CP390-5.0 CP390-8.2 CP371-3.4 CP371-5.0 CP454-0.5 CP357-3.3 CP357-4.6 CP357-5.4 CP409-1.9 CP409-5.1 CP409-7.1 CP409-9.2 CP409-0.9 CP401-1.9 CP401-3.3 CP401-4.2 CP401-5.4 CP462-1.5 CP462-2.4 CP462-3.1 CP462-4.2 CP484-2.7 CP484-6.1 CP484-8.7 CP471-2.7 CP471-4.4 CP1562-1.2 CP1562-10.0 CP1562-10.8 -88.84179325 -88.86388521 -88.90056199 -88.78623326 -88.73687875 -88.72224631 -88.76623851 -88.741096 -88.55983609 -88.54034567 -87.65446649 -88.35204186 -88.34511375 -88.36950081 -88.26074633 -88.30732807 -88.32488566 -88.35569087 -88.24870637 -88.19835269 -88.18514539 -88.17245148 -88.1868161 -87.50420685 -87.49702655 -87.49158916 -87.48156253 -87.12437983 -87.14405595 -87.1687111 -87.3068661 -87.28022381 -84.29322146 -84.18714843 -84.17818846 42.097178 42.096681 42.110264 41.892786 41.96666 41.996745 41.921884 41.947122 42.26136262 42.24914538 41.49143108 42.39315437 42.40195689 42.38537032 41.73746153 41.71213673 41.69307125 41.68521054 41.74694565 41.84218262 41.82835609 41.82091608 41.79605208 41.51785124 41.52916465 41.5378932 41.55200749 41.56377037 41.59660007 41.61181464 41.51192614 41.5236767 44.67548 44.668993 44.669158 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 24 Control Points Upstream Lakehead in Series Pipelines 6 6 6 5 5 5 5 5 2 2 1 3 3 3 5 5 5 5 5 4 4 4 4 4 4 4 4 3 3 3 2 2 6 6 6 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 61 Line 14 Line 14 Line 6A,Line 64 Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6A,Line 64,Line 78 Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1512 Page 212 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Au Sable River Au Sable River Au Sable River Belle River Belle River Belle River Belle River Brandywine Creek Brandywine Creek Buckhorn Creek Buckhorn Creek Buckhorn Creek Cass River Cass River Crapo Creek Crapo Creek Crapo Creek Crapo Creek East Branch Big Creek East Branch Big Creek East Branch Big Creek Grand River Grand River Grand River Grand River Grand River Grand River Grand River Indian Creek Indian Creek Indian Creek Indian Creek Kalamazoo River Kalamazoo River Kalamazoo River CP1562-14.1 CP1562-3.1 CP1562-5.5 CP737-8.4 CP737-13.7 CP737-20.9 CP737-27.5 CP536-1.6 CP536-2.9 CP689-3.1 CP689-4.0 CP689-5.4 CP1669-9.9 CP1669-2.6 CP1587-3.9 CP1587-2.3 CP1587-5.9 CP1587-7.8 CP1556-7.5 CP1556-10.0 CP1556-3.7 CP634-3.4 CP634-6.1 CP634-8.5 CP634-6.4 CP634-10.4 CP634-0.3 CP634--3.9 CP1688-4.7 CP1688-8.0 CP1688-9.7 CP1688-13.6 CP611-1.3 CP611-1.6 CP611-11.1 -84.13617948 -84.27256097 -84.24081033 -82.68404585 -82.64394513 -82.59496081 -82.54937147 -86.2398083 -86.25449417 -83.62550252 -83.63527754 -83.64769833 -83.65692165 -83.58189601 -84.19983223 -84.20350568 -84.20788728 -84.20529228 -84.40915188 -84.41135897 -84.38010271 -84.55243518 -84.56024994 -84.56829505 -84.55768966 -84.5818585 -84.54188668 -84.48953022 -83.27053068 -83.29308207 -83.30058232 -83.32121907 -84.95135356 -84.9559976 -85.11108577 44.661423 44.675461 44.682087 42.83108781 42.81254797 42.79972328 42.7748885 41.80981876 41.80445911 42.78618858 42.79225227 42.79876009 43.32428414 43.36964627 44.29157093 44.30492992 44.27740968 44.26007102 44.71559769 44.69754997 44.73899232 42.41579471 42.43920616 42.46570044 42.441974 42.48272182 42.39134786 42.39605232 43.25092291 43.2363072 43.22388169 43.20447224 42.261385 42.262514 42.288606 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 25 Control Points Upstream Lakehead in Series Pipelines 6 6 6 4 4 4 4 2 2 3 3 3 2 2 4 4 4 4 3 3 3 7 7 7 7 7 7 7 4 4 4 4 37 37 37 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1513 Page 213 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kalamazoo River Kawkawlin River CP611-11.4 CP611-11.9 CP611-13.3 CP611-14.1 CP611-14.6 CP611-15.1 CP611-15.3 CP611-16.8 CP611-17.4 CP611-19.6 CP611-20.1 CP611-20.7 CP611-21.0 CP611-21.2 CP611-21.4 CP611-22.5 CP611-23.3 CP611-26.6 CP611-28.9 CP611-30.2 CP611-30.8 CP611-31.3 CP611-32.0 CP611-37.1 CP611-38.5 CP611-39.8 CP611-4.3 CP611-40.6 CP611-41.9 CP611-6.8 CP611-7.1 CP611-7.4 CP611-7.8 CP611-9.4 CP1638-4.4 -85.11498422 -85.12400708 -85.13955362 -85.14573784 -85.15057418 -85.15970004 -85.16411444 -85.18310522 -85.1873792 -85.21257342 -85.21789326 -85.23052218 -85.23562704 -85.23957311 -85.24214404 -85.26268229 -85.2753427 -85.30289998 -85.3300441 -85.33652084 -85.3452939 -85.35306377 -85.35803105 -85.41287104 -85.42881927 -85.45184539 -84.99853607 -85.46614567 -85.49149476 -85.04320081 -85.04758775 -85.05394464 -85.06075016 -85.08523293 -83.9485765 42.290215 42.293341 42.303749 42.307929 42.302078 42.29879 42.298794 42.304756 42.310572 42.330971 42.334771 42.337361 42.339143 42.341027 42.343758 42.346276 42.350804 42.350977 42.347956 42.338055 42.334798 42.3318 42.324175 42.284726 42.280227 42.278134 42.258338 42.282532 42.283929 42.261477 42.265033 42.266257 42.269929 42.275712 43.6505028 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 26 Control Points Upstream Lakehead in Series Pipelines 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 37 4 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1514 Page 214 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Kawkawlin River Kawkawlin River Kawkawlin River Middle Branch Cedar River Middle Branch Cedar River Middle Branch Cedar River Middle Branch Cedar River North Branch Clinton River North Branch Clinton River North Branch Clinton River North Branch Clinton River North Branch Clinton River North Branch Kawkawlin River North Branch Kawkawlin River North Ore Creek North Ore Creek North Ore Creek North Ore Creek Pinconning River Pinconning River Pinconning River Pinconning River Pinconning River Pine River Pine River Pine River Pine River Pine River Pine River Pine River Pine River Pine River Pine River Pine River Pine River CP1638-2.4 CP1638-6.6 CP1638-7.6 CP662-4.2 CP662-2.0 CP662-5.2 CP662-7.1 CP723-9.8 CP723-14.2 CP723-16.6 CP723-17.4 CP723-21.7 CP1631-4.6 CP1631-5.8 CP679-2.2 CP679-3.1 CP679-4.4 CP679-0.8 CP1621-1.7 CP1621-3.2 CP1621-6.4 CP1621-5.3 CP1621-7.8 CP1718-8.3 CP1718-10.5 CP1718-13.6 CP1718-16.3 CP1718-18.9 CP1718-21.9 CP1718-24.4 CP1718-26.2 CP1718-30.3 CP1718-31.5 CP745-5.7 CP745-8.7 -83.97554068 -83.91309214 -83.89725178 -84.08106844 -84.08071258 -84.07947783 -84.0938674 -82.96233153 -82.92830737 -82.90657274 -82.9065381 -82.90451044 -83.97018918 -83.96161487 -83.79490151 -83.79701634 -83.80459974 -83.78417208 -84.00612411 -83.98611893 -83.94596841 -83.95921697 -83.92706145 -82.65293571 -82.63253087 -82.61300887 -82.61944185 -82.59395397 -82.56701284 -82.55479781 -82.5586253 -82.56918908 -82.56772889 -82.53901188 -82.5177884 43.63900921 43.64348695 43.65204861 42.64299844 42.61381784 42.65529648 42.67693708 42.79526093 42.76668092 42.75441557 42.74658891 42.71713348 43.66747794 43.65591587 42.72507868 42.73575807 42.75055251 42.70759427 43.84402813 43.85112847 43.85312691 43.8608014 43.84710348 43.02169949 43.01130316 42.99122254 42.96894661 42.96178162 42.94742102 42.93360862 42.91882468 42.88894534 42.8803917 42.83821262 42.82284389 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 27 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 4 4 4 7 7 7 7 7 7 7 4 4 4 4 5 5 5 5 5 10 10 10 10 10 10 10 10 10 10 5 5 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5,Line 6B Line 5,Line 6B Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1515 Page 215 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Pine River Pine River Pine River Portage River Portage River Portage River Quanicassee River Quanicassee River Quanicassee River Quanicassee River Red Cedar River Red Cedar River Red Cedar River Rocky River Rocky River Rocky River Rocky River Saganing Creek Saganing Creek Saganing Creek Saganing Creek Saganing Creek Saginaw River Saginaw River Saginaw River Shiawassee River Shiawassee River South Branch Shiawassee River South Branch Shiawassee River South Branch Shiawassee River South Branch Shiawassee River South Branch South Branch Flint River South Branch Flint River South Branch Flint River South Branch Flint River CP745-13.3 CP745-3.7 CP745-1.1 CP577-2.8 CP577-4.3 CP577-5.9 CP1655-7.1 CP1655-6.5 CP1655-3.1 CP1652-3.4 CP665-2.0 CP665-3.3 CP665-4.4 CP570-4.2 CP570-6.0 CP570-7.0N CP570-7.1S CP1616-6.5 CP1616-4.7 CP1616-10.9 CP1616-13.1 CP1616-8.3 CP1645-3.2 CP1645-4.9 CP1645-8.0 CP691-0.0 CP668-5.6 CP668-8.0 CP668-13.3 CP668-14.9 CP668-21.6 CP709-6.7 CP709-9.4 CP709-11.5 CP709-14.2 -82.49875747 -82.53806298 -82.55774115 -85.54783509 -85.56719505 -85.58505037 -83.68054169 -83.68762641 -83.71662857 -83.72416747 -84.03267134 -84.05291501 -84.07234418 -85.6475002 -85.64384261 -85.63329235 -85.63349354 -83.98630522 -84.00592411 -83.93650534 -83.91094342 -83.96693083 -83.89482987 -83.87160556 -83.85135126 -83.60397629 -83.98226039 -83.96841867 -83.91103627 -83.91089521 -83.94271742 -83.26446885 -83.24435734 -83.22313974 -83.22415075 42.81309541 42.85853092 42.87179014 42.01455404 42.00818857 41.99849792 43.58460111 43.57663818 43.53681877 43.53669298 42.63572306 42.6447796 42.64173222 41.97012968 41.95439917 41.94272975 41.94125919 43.92508724 43.91584023 43.93417896 43.92815394 43.9265633 43.597894 43.614641 43.640361 42.78122448 42.70886496 42.72816783 42.76112292 42.78106143 42.81793678 42.91335189 42.92844881 42.92816338 42.94927329 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 28 Control Points Upstream Lakehead in Series Pipelines 5 5 5 3 3 3 4 4 4 4 3 3 3 4 4 4 4 5 5 5 5 5 3 3 3 1 5 5 5 5 5 5 5 5 5 Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 5 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1516 Page 216 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude South Branch Flint River South Branch Rice Creek South Branch Rice Creek South Branch Rice Creek South Branch Rice Creek South Branch Rice Creek South Branch Rice Creek Squaconning Creek Squaconning Creek Squaconning Creek Squaconning Creek St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Clair River St. Joseph River St. Joseph River St. Joseph River St. Joseph River St. Joseph River West Branch Big Creek West Branch Big Creek West Branch Rifle River West Branch Rifle River CP709-18.2 CP618-2.9 CP618-4.3 CP618-5.3 CP618-7.4 CP618-8.9 CP618-9.3 CP1643-3.9 CP1643-2.0 CP1643-2.7E CP1643-2.7 CP1735-0.7 CP1735-15.4 CP1735-19.3 CP1735-6.7 CP1735-30.1 CP1735-26.1 CP1735-30.0 CP1735-27.9 CP1735-24.0 CP1735-22.0 CP1735-14.2 CP1735-8.5 CP1735-6.3 CP1735-23.4 CP1735-30.4 CP533-11.2 CP533-2.7 CP533-21.0 CP533-7.0 CP533-2.0 CP1566-2.8 CP1566-4.5 CP1592-6.7 CP1592-20.5 -83.24604251 -84.86273399 -84.8872409 -84.90697415 -84.93071255 -84.95414794 -84.96050554 -83.90272588 -83.91560781 -83.9046306 -83.91028027 -82.46660062 -82.50048841 -82.51401221 -82.4856649 -82.64085384 -82.59714309 -82.65323365 -82.64707246 -82.56096182 -82.53434678 -82.48968137 -82.4791623 -82.48496594 -82.5532628 -82.65797414 -86.34977105 -86.25740713 -86.33075682 -86.29115 -86.26028064 -84.26112082 -84.25866162 -84.12591761 -84.08281709 42.9722098 42.29702385 42.29512987 42.29296017 42.27614818 42.26731422 42.26557099 43.5809915 43.55725186 43.56583283 43.56581592 42.906291 42.702907 42.647006 42.820623 42.55596811 42.61319528 42.57650922 42.62735115 42.6183996 42.61375147 42.71933348 42.79417209 42.82656009 42.60805472 42.57457865 41.8390507 41.82601354 41.94309854 41.85924 41.81579332 44.63773959 44.65231043 44.25483358 44.19926627 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 29 Control Points Upstream Lakehead in Series Pipelines 5 6 6 6 6 6 6 4 4 4 4 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 5 5 5 5 5 2 2 3 3 Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 5,Line 6B Line 6B Line 6B Line 6B Line 6B Line 6B Line 5 Line 5 Line 5 Line 5 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1517 Page 217 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude West Branch Rifle River Buffalo River Buffalo River Niagara River - East Branch Niagara River - East Branch Niagara River - East Branch Niagara River - East Branch Niagara River - West Branch Niagara River - West Branch Niagara River - West Branch Niagara River - West Branch Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Big Weirgor Creek Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Chippewa River Crawfish River Crawfish River Crawfish River Crawfish River Eau Claire River North Fork Eau Claire River North Fork Eau Claire River North Fork Eau Claire River North Fork Eau Claire River North Fork Eau Claire River North Fork Eau Claire River North Fork CP1592-2.6 CP1951-6.4 CP1951-7.8 CP1933-2.4 CP1933-21.9 CP1933-28.0 CP1933-7.8 CP1928-15.3 CP1928-21.6 CP1928-4.0 CP1928-5.0 CP85-25.3E CP85-31.9E CP85-37.5B CP85-39.5N CP88-17.8E CP88-24.4E CP88-30.0B CP88-32.0N CP88-36.7N CP88-38.6W CP88-39.5W CP88-39.8S CP88-40.4N CP279-17.3 CP279-21.4 CP279-5.9 CP279-9.7 CP132-10.5 CP132-13.5 CP132-19.3 CP132-2.7 CP132-24.4 CP132-33.2 CP132-5.5 -84.16418947 -78.86840204 -78.88565638 -78.89191824 -79.04951552 -79.05925103 -78.95350005 -79.04953185 -79.05925103 -78.99734478 -78.95349999 -91.28968159 -91.32568835 -91.23727199 -91.19851761 -91.29084959 -91.32713687 -91.23727199 -91.19843087 -91.15321134 -91.15744885 -91.15930232 -91.14259708 -91.13061363 -89.01373707 -89.01346638 -89.08904075 -89.05624196 -90.81833455 -90.82575982 -90.85315219 -90.73990008 -90.84791009 -90.87898214 -90.7702303 44.24799299 42.866041 42.879337 43.016386 43.174212 43.260922 43.075951 43.174227 43.260922 43.05308 43.075951 45.391996 45.33865 45.297518 45.304691 45.391804 45.338511 45.297518 45.304689 45.272014 45.24418 45.234853 45.23478 45.234876 43.34227 43.31398 43.354235 43.358022 45.031579 45.002328 44.950024 45.048584 44.900841 44.828138 45.046087 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 30 Control Points Upstream Lakehead in Series Pipelines 3 2 2 4 4 4 4 4 4 4 4 4 4 4 4 9 9 9 9 9 9 9 9 9 4 4 4 4 7 7 7 7 7 7 7 Line 5 Line 10 Line 10 Line 10 Line 10 Line 10 Line 10 Line 10 Line 10 Line 10 Line 10 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1518 Page 218 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Flambeau River Flambeau River Flambeau River Flambeau River Fox River Fox River Fox River Fox River Fox River Fox River Jump River Jump River Jump River Jump River Little Jump River Little Jump River Little Jump River Little Jump River Maunesha River Maunesha River Maunesha River Maunesha River Popple River Popple River Popple River Popple River Popple River Rock River Rock River Rock River Thornapple River Thornapple River Thornapple River Thornapple River Turtle Creek CP100-2.8 CP100-3.4 CP100-3.7 CP100-7.0 CP253-0.4 CP253-11.0 CP253-3.8 CP261-2.1 CP261-3.7 CP253-7.6 CP111-2.4 CP111-3.1 CP111-8.5 CP111-9.5 CP110-1.4 CP110-2.1 CP110-7.4 CP110-8.6 CP291-0.8 CP291-10.7 CP291-14.4 CP291-5.9 CP144-11.0 CP144-14.2 CP144-17.4 CP144-24.9 CP144-4.0 CP313-0.7 CP313-2.2 CP313-2.8 CP94-13.6E CP94-20.0E CP94-26.1B CP94-28.1N CP337.3-17.5 -91.16093724 -91.16514744 -91.16925848 -91.21677568 -89.42476381 -89.4643544 -89.39567981 -89.35395932 -89.38554669 -89.42593638 -90.99685758 -91.00867717 -91.08989228 -91.1095832 -90.99685758 -91.00867717 -91.08989228 -91.1095832 -89.02931896 -88.94550641 -88.88765654 -88.98342281 -90.61268868 -90.60642911 -90.62241075 -90.62720443 -90.57152757 -88.87695336 -88.90477318 -88.91403947 -91.2896311 -91.3268417 -91.23734924 -91.19822976 -89.01136937 45.429103 45.421898 45.418127 45.411902 43.636179 43.716464 43.671685 43.544178 43.541403 43.69711906 45.304997 45.301438 45.281707 45.273894 45.304997 45.301438 45.281707 45.273894 43.182708 43.219323 43.234594 43.18911 44.821029 44.781907 44.741608 44.654563 44.886001 42.900044 42.895343 42.892138 45.391895 45.339053 45.297463 45.304857 42.511748 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 31 Control Points Upstream Lakehead in Series Pipelines 4 4 4 4 6 6 6 6 6 6 4 4 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 3 3 3 4 4 4 4 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1519 Page 219 of 225 APPENDIX D Vendor Provided WaterCrossing ControlPointID Region Longitude Latitude Turtle Creek Turtle Creek Turtle Creek Turtle Creek Wisconsin River Wisconsin River Wisconsin River Yellow River Yellow River Yellow River Yellow River Yellow River Yellow River East Branch Yellow River East Branch Yellow River East Branch Yellow River East Branch Yellow River East Branch CP337.3-2.2 CP337.3-4.0 CP337.3-7.8 CP337.3-9.0 CP201-1.5 CP201-2.0 CP201-5.2 CP124-17.3 CP124-21.5 CP124-24.9 CP124-3.3 CP124-6.1 CP169-15.8 CP169-2.6 CP169-21.8 CP169-27.2 CP169-5.5 -88.82902938 -88.86339495 -88.92317817 -88.94053924 -89.90933978 -89.91648966 -89.9052071 -91.01019863 -91.03447623 -91.0452122 -90.85516389 -90.89532425 -90.14026054 -90.25307947 -90.1500689 -90.11950648 -90.22388425 42.597515 42.596391 42.580817 42.573171 44.279308 44.271696 44.237712 45.093363 45.045194 45.017436 45.141211 45.126987 44.518612 44.634646 44.45346 44.393296 44.611685 Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 32 Control Points Upstream Lakehead in Series Pipelines 5 5 5 5 3 3 3 5 5 5 5 5 5 5 5 5 5 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Line 6A,Line 14,Line 61 Case ECF No. 9-5 filed 01/19/17 PageID.1520 Page 220 of 225 APPENDIX Case 1:16-cv-00914-GJQ-ESC ENBRIDGE PIPELINES – X Region ROW Name ECF No. 9-5 filed 01/19/17 PageID.1521 Page 221 of 225 APPENDIX E GPS Location of Control Point Upstream and Downstream Valve Sites Upstream Distance to Pipeline Access Requirements Objective Resources at Risk Watercourse Description and Navigability Staging Area Safety Concerns and Communications Implementation Closest Equipment Cache to this Control Point Required Contact Numbers CP Type CP Number Latitude: Longitude: Location of CP in Decimals (NAD83) Location of CP in Decimals (NAD83) Name of Line Crossing with MP/KP Upstream Control Point Marker and distance in Miles/kilometers to Control Point E.g. Road, Parking, Helicopter/Aerial Downstream Control access (any obstacles e.g. power lines) Point Primary Strategy of the Control Point (Containment & Recovery/Collection , Deflection/Exclusion) Include: waterbody name, flow direction, velocity (best case and worst case if known), width range (various conditions) underwater infrastructure and above-water infrastructure Location if applicable Boat Launch or Marina Location if applicable Name of Equipment cache and where applicable the response time in hours If publically available, Private Landowner/Business Owner Information Other Comments Date Strategy Updated: Insert date as dd-mmm-yyyy Date Strategy Site Visited: Insert date 1 Case 1:16-cv-00914-GJQ-ESC ENBRIDGE PIPELINES – X Region ROW Name Driving Directions: - Include starting point Text description that includes the entry point for vehicles to gain access to the CP ECF No. 9-5 filed 01/19/17 PageID.1522 Page 222 of 225 APPENDIX E Recommended Equipment Quantity Description number e.g. type and size of boom CP Type CP Number Recommended Personnel Number Description e.g. type and size of boat Equipment Notes Map of Driving Directions • Insert map Tactical Deployment Diagram • • • 2 Insert Tactical Diagram(s) with Instructional Bubbles – additional pages and photos if required. Include zoomed out picture with placement of equipment AND zoomed in tactical picture to show specific set-up Include anchor point locations for boom where applicable Case 1:16-cv-00914-GJQ-ESC ENBRIDGE PIPELINES – X Region ROW Name ECF No. 9-5 filed 01/19/17 PageID.1523 Page 223 of 225 APPENDIX E Photo 1 CP Type CP Number Photo 2 Append photos 3 Case ECF No. 9-5 filed 01/19/17 PageID.1524 Page 224 of 225 APPENDIX Case 1:16-cv-00914-GJQ-ESC ECF No. 9-5 filed 01/19/17 PageID.1525 Page 225 of 225 Appendix F Illustration of S-R Performance Curves Note: In the hypothetical data set below for New US Line 3, all of the S-R Performance curves would be compliant with the design and construction targets in Paragraph 89.a of the Consent Decree, except for the S-R Performance Curve for the 2-Hour MBS Alarm. 2-Hour MBS Alarm Sensitivity (% of the volume of oil injected or pumped into MBS Segment within alarm period) Sensitivity (% of the volume of oil injected or pumped into MBS Segment within alarm period) 5-Minute MBS Alarm 24-hour MBS Alarm Sensitivity (% of the volume of oil injected or pumped into MBS Segment within alarm period) Sensitivity (% of the volume of oil injected or pumped into MBS Segment within alarm period) 20-Minute MBS Alarm KEY S-R Performance Curve Design and Construction Target