Enbridge Pipelines Inc

TABLE OF CONTENTS

1.0 Application Overview/Executive Summary 1.1 Overview of the Southern Access Expansion Program (Stages 2A and 2B) 1.2 Capacity Changes 1.3 Construction Schedule

2.0 Project Description 2.1 Engineering Design Details – Pumping Facilities 2.2 Engineering Design Details – Station Piping 2.3 Pipeline Control, Communication and Leak Detection 2.4 Engineering Design Philosophy and Onshore Pipeline Regulations 2.5 Piping Decommissioning and Removal 2.6 Alternatives

3.0 Environmental Assessment Process

4.0 Economics 4.1 Supply 4.2 Transportation Matters 4.3 Markets 4.4 Financing

5.0 Public Interest/Consultation 5.1 Principles and Goals of the Public Consultation Program 5.2 Design of the Public Consultation Program 5.3 Consultation Program Implementation 5.4 Notification of Commercial Third Parties

6.0 Appendices Appendix 1 Environmental and Socio-Economic Assessment for the Proposed Enbridge Pipelines Inc. Southern Access Upstream Expansion Program – Phases 2A and 2B Appendix 2 Sub-appendices to the ESA Appendix 3 Detailed Schedule for the Proposed Project Appendix 4 CAPP Letter of Support Appendix 5 Enbridge’s Corporate Social Responsibility and Indigenous Peoples Policies Appendix 6 Public Consultation Mail-outs Appendix 7 Capacity Definitions, Flow Formulae & Calculations Appendix 8 Drawings Appendix 9 Abbreviations Appendix 10 NEB Filing Manual Checklists

1.0 APPLICATION OVERVIEW/EXECUTIVE SUMMARY

Project Name: Southern Access Expansion Program (Stages 2A and 2B) Project Reference: 0641188B01 Project Cost: $175,000,000

Enbridge Pipelines Inc. (“Enbridge”) applies for approval to construct and operate upstream facilities in support of the overall Southern Access Program.

1.1 OVERVIEW OF THE SOUTHERN ACCESS EXPANSION PROGRAM PHASE 2

The Southern Access Upstream Expansion Project is a capacity enhancing program to allow for increased flow rates of heavy crude from Alberta to markets in the USA and Eastern Canada on Enbridge’s existing Line 4 pipeline. The expansion program is supported by the Canadian Association of Petroleum Producers (“CAPP”), as they confirmed in their August 22, 2006 letter (attached as Appendix 4), which requested that Enbridge proceed to develop Stages 2A and 2B.

The Canadian portion of Stages 2A and 2B (collectively referred to in this Application as “Phase 2”, or the “Project”) of this multi-phase project will build upon the efficiencies that will be realized from earlier phases of the project by increasing pumping capacity at all 18 Enbridge pump stations and terminals on Line 4 between Hardisty, Alberta and Gretna, Manitoba (inclusive).

This additional Line 4 pumping capacity will be attained through pump and piping upgrades at these locations. Upgraded pump units with larger motors will be installed at 6 stations, upgraded pump units will be installed at 16 stations, and a new pump unit and motor will be installed at one station. The station and terminal modifications will also require changes to existing fixtures (including piping, valves, fittings, flanges, etc.) so as to achieve the pressures and flow rates that the Stage 2 facilities have been designed to operate at. Specifically, these facilities will have a discharge piping MAOP of 9,928 kPa(g).

The Project will not require any piping modifications, upgrades or additions to the Line 4 mainline, and the Line 4 mainline MAOP of 7,598 kPa(g) will remain unchanged. No additional land will be required outside of existing previously disturbed pump station boundaries.

1.2 CAPACITY CHANGES

Southern Access Stages 2A and 2B scope of work will be executed in two increments; completion of these increments will increase the heavy crude Annual Capacity of Line 4 from Hardisty to Superior by 10,000 m 3/day and 13,500 m 3/day respectively.

The total annual capacity of Line 4 will be 126,500 m 3/day at completion of Stage 2A and 140,000 m 3/day at completion of Stage 2B. This increase is required as the existing Line 4 pipeline does not provide sufficient capacity to complement planned expansion ex-Superior.

1.3 CONSTRUCTION SCHEDULE

Pending receipt of National Energy Board (“NEB”) regulatory approval, it is anticipated that the Southern Access Phase 2 facilities will be constructed between March 2007 and April 2009. All modified pipeline facilities will be operational by April 2009.

A detailed schedule for the proposed Project is included as Appendix 3.

2.0 PROJECT DESCRIPTION

2.1 ENGINEERING DESIGN DETAILS – PUMPING FACILITIES

Line 4 transports heavy crude from Hardisty, Alberta to Superior, Wisconsin. Between Hardisty and the international border, Line 4 has both 914 mm (36”) and 1219 mm (48”) pipe segments. The Line 4 stations and terminals were first commissioned in the time period of 1964 through 1971. In order to permit increased heavy crude flow rates, Southern Access Phase 2 proposes the installation of new pumping units on Line 4, as well as modifications to existing pumping units and associated piping facilities at existing Enbridge station and terminal properties.

In total, 57 of the existing 61 Line 4 mainline pump units are to be modified or replaced with new units. The remaining four existing pump units will be idled and used as spares. Six pump stations will undergo pump unit upgrades that will result in additional horsepower: Hardisty, Kerrobert, Milden, Craik, Regina and Glenavon. To facilitate these upgrades, additional modifications will be made to each station’s piping, electrical, and control systems. The total incremental horsepower proposed for these stations is 40,000 HP. In addition to the pump upgrades described above, Metiskow Station will receive an additional 5000 HP pump unit, and so the total incremental horsepower proposed for Line 4 is 45,000 HP. Further details regarding these installations and modifications are provided in Tables 1, 2, 3 and 4 below.

It should be noted that the Regina terminal modifications will utilize vacant pump unit locations in the existing building. Although additional pump units are not required at Regina, upgraded pumps will be installed in the existing vacant locations to speed project execution. The obsolete pump units replaced at Regina will be decommissioned.

Table 1 summarizes the mainline pump configuration of the Enbridge system following completion of Southern Access Stage 1, and contrasts it with the proposed configuration upon completion of Phase 2. It describes in detail the Line 4 pumping facility upgrade requirements for Southern Access Phase 2, including the number of mainline pump units to be added or upgraded and the resultant changes in horsepower.

Plot plans and piping schematics illustrating the location of proposed modifications and additions to existing pump station and terminal facilities are located in Appendix 8.

Table 1: Current and Proposed Pump Configuration All Line Summary Line 4 Mainline Pump Summary (Lines 1,2,3,4,13) Current Post Final Post Phase Stage 1 Pump Unit Upgrades Total Post Phase 2 2 Configuration Configuration Pump Additional Pump Pump Pump Upgraded Additional Pump Pump Pump Pump station Pump HP % units HP pump units HP units HP units HP units Increase Hardisty 4 17,500 0 4 2.500 4 20,000 17 53,400 5% Metiskow 3 15,000 1 3 5,000 4 20,000 13 39,500 14% Cactus 3 15,000 0 3 0 3 15,000 12 42,900 Lake Kerrobert 4 12,500 0 4 7,500 4 20,000 17 58,384 15% Herschel 3 15,000 0 3 0 3 15,000 11 33,500 Milden 4 12,500 0 4 7,500 4 20,000 14 47,900 19% Loreburn 3 15,000 0 3 0 3 15,000 15 49,700 Craik 4 12,500 0 3 5,000 4 17,500 11 35,265 17% Bethune 3 15,000 0 3 0 3 20,000 12 42,900 Regina 4 10,000 0 4 10,000 4 15,000 15 48,684 26% Odessa 3 15,000 0 3 0 3 19,000 14 45,250 Glenavon 5 11,500 0 3 7,500 5 15,000 18 52,651 17% Langbank 3 15,000 0 3 0 3 15,000 14 45,500 Cromer 3 15,000 0 3 0 3 15,000 18 39,010 Souris 3 15,000 0 3 0 3 15,000 10 31,250 Glenboro 3 15,000 0 2 0 3 15,000 18 51,651 St. Leon 3 15,000 0 3 0 3 15,000 9 32,750 Gretna 3 15,000 0 3 0 3 15,000 16 47,020

TOTAL 61 256,500 1 57 45,000 62 301,500 254 797,215 6%

NOTE: The data in the column titled “Pump HP % Increase” may differ slightly from those values communicated in the public consultation letters. The values used in the public consultation letters are based on the total site installed pump HP, and therefore include booster and transfer pumps.

Table 2: Phase 2A Pump Modifications Phase 2A Station Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 Unit 6 VFD Hardisty (YP) PM RU Yes Metiskow (ME) Yes Cactus Lake (CC) PM PM RP Yes Kerrobert (KB) RU Yes Herschel (HR) PM PM RP Yes Milden (MI) RU Yes Loreburn (ZP) PM RP Yes Craik (CK) Yes Bethune (BU) PM Regina (QU) RU RU Yes Odessa (OD) PM PM Glenavon (AP) RU RU Yes Langbank (LB) PM PM Cromer (CM) Yes Souris (SP) PM PM Glenboro (LP) Yes St. Leon (LO) PM Gretna (GF) Yes

Legend Total PM Impeller and Pump Modification 14 RP Pump Replaced 3 RU Pump and Motor Replaced 7 Total Upgrades 24

Table 3: Phase 2B Pump Modifications Phase 2A Station Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 Unit 6 VFD Hardisty (YP) PM PM Yes Metiskow (ME) PM PM PM A Yes Cactus Lake (CC) Yes Kerrobert (KB) RU RU PM Yes Herschel (HR) Yes Milden (MI) RU RU PM Yes Loreburn (ZP) PM Yes Craik (CK) RU RU PM Yes Bethune (BU) PM RP Regina (QU) RU RU Yes Odessa (OD) RP Glenavon (AP) RU Yes Langbank (LB) RP Cromer (CM) PM PM PM Yes Souris (SP) RP Glenboro (LP) PM PM Yes St. Leon (LO) PM RP Gretna (GF) PM PM PM Yes

Legend Total PM Impeller and Pump Modification 19 RP Pump Replaced 5 RU Pump and Motor Replaced 9 A Pump and Motor Added 1 Total Upgrades 34

To support the increased capacity, new booster or transfer pump units must be added at the Hardisty, Kerrobert, and Regina terminals, for a total incremental horsepower of 5,500 HP. A summary of the pump units that are to be added at each terminal is located in Table 4.

Table 4: Current & Proposed Booster/Transfer Pumps at Hardisty, Kerrobert & Regina Terminals LINE 4 TERMINAL PUMP SUMMARY

Current Post Phase 1 Final Post Phase 2 Pump Unit Upgrades Configuration Configuration

Additional Upgraded Pump Additional Pump Pump Units HP Pump Pump HP station HP Units Units Units Hardisty 12 14,750 2 0 2,500 12 17,250 Kerrobert 6 4,575 1 0 1,000 7 5,575 Regina 3 3,000 2 0 2,000 5 5,000

TOTAL 21 22,325 5 0 5,500 26 27,825

Pump Types and Energy Sources All new pumping units will be driven by electric motors and mounted on a bedplate common with the motor. Pumps will be equipped with casing vibration and bearing temperature monitoring equipment. The existing Enbridge Pipeline Control System in Edmonton will remotely control operation of all pumping units, new, modified and existing.

All motors on the new pumping units will be squirrel cage induction type, 3-phase, 60 cycle, 4160 V. The motors will be equipped with the following features:

• 1.15 service factors, rated for Class B rise, with Class F insulation

• bearing temperature detectors

• stator winding temperature detectors

No significant increases in existing station noise levels are anticipated as a result of the construction of these facilities. All Line 4 pumps with the exception of the new pump installation at Metiskow will be housed inside existing buildings. Existing noise levels and noise levels after new units are operating will be evaluated and, if necessary, appropriate mitigative measures will be implemented as discussed in Section 7 of this Application.

All new electrical switchgear and associated control equipment will be installed in modified existing buildings. Electrical infrastructure within station sites will be upgraded as required to facilitate new pumping equipment. All equipment will be installed to the requirements of the CSA C22.1-06 Canadian Electrical Code Part 1.

Existing buildings will be modified and expanded at fifteen of the eighteen station locations in order to house the new electrical equipment that will be required to facilitate the pump station upgrades. The building additions will be constructed entirely within existing Enbridge station property and will be pre- engineered, rigid frame, metal clad structures anchored to a concrete floor. Emergency lighting will be installed in each building.

2.2 ENGINEERING DESIGN DETAILS – STATION PIPING

There are no mainline piping modifications required for Southern Access Phase 2. Pump station pipe will be installed to connect new pumping units to existing mainline piping facilities. All pipe materials will be selected and all of the pipe will be designed and hydrotested in accordance with CSA Z662-03.

All new station pipe will be externally coated in a qualified plant with fusion bond epoxy in accordance with CSA Z662-03. New below grade station or terminal pipe fittings and weld joints will be externally coated by a qualified field coating contractor with fusion bond epoxy, spray applied polyurethane or two part epoxy in accordance with CSA Z662-03.

Station and terminal pipe and fittings will be protected by an impressed current cathodic protection system and will become subject to the Enbridge ongoing integrity maintenance management programs which includes the maintenance of cathodic protection.

2.3 PIPELINE CONTROL, COMMUNICATION AND LEAK DETECTION

Full time pipeline operators located at the Edmonton Control Centre will operate the Southern Access facilities. Using Supervisory Control and Data Acquisition (“SCADA”) systems known as PCS (“Pipeline Control System”), the control centre operators are able to monitor pressures, densities, pump and valve status, alarms, and other indications of the current pipeline condition, and control the operation of the line through a variety of commands. This system will be expanded and modified as necessary to provide the appropriate monitoring and control capabilities to ensure the safe and efficient operation of the pipeline network after the Southern Access Phase 2 expansion.

Changes to the PCS system currently contemplated consist primarily of expansions to the current and historical database configuration so as to include all new and modified equipment, and to the user interface so as to provide the pipeline operators with information on the configuration of the new facilities. Other related components of the PCS system, such as leak detection, batch tracking, test plans, and documentation may also be expanded as necessary.

The existing Line 4 line pressure protection scheme will be enhanced via installation of variable frequency motor drives. A Variable Frequency Drive (“VFD”) allows operators to optimize pump motor speeds and control pipeline pressure without the use of throttling control valves. VFDs offer both improved pressure control and reduced pump motor power consumption. In addition to VFDs, new Pressure Control Valves (“PCVs”) will be installed at each station. New PCVs will provide pressure control redundancy and are required to achieve the proposed Line 4 capacity increase. Pressure monitoring, protection and control will be further improved with the installation of pressure instruments on the second last, and last pump at each station.

Leak detection on the Enbridge system is accomplished by a variety of techniques, including monitoring of line conditions by Pipeline Controllers, software based monitoring or Computational Pipeline Monitoring (“CPM”), inspections by company staff, product or gas sensors, aerial/ground line patrol and third party reports. The components of Enbridge's leak detection system complement each other to provide a system to detect leaks of all sizes and types. All Southern Access Phase 2 pipeline facilities will be subject to these existing leak detection techniques.

2.4 ENGINEERING DESIGN PHILOSOPHY AND ONSHORE PIPELINE REGULATIONS

In implementing the Project, Enbridge will comply with the requirements of the Onshore Pipeline Regulations, 1999 (“OPR”) to the extent they are relevant, as well as with the requirements of its Operations and Maintenance Manuals . In addition, Enbridge will also design and construct the Project in accordance with CSA Z662-03 , and Enbridge’s Engineering Standards and Environmental Guidelines for Construction (2003) (“EGC”).

The piping materials for the Project will be procured in accordance with the above regulations and standards as well as Enbridge’s supplemental specifications and in accordance with Enbridge's quality assurance program. Station pipe welding will be performed in accordance with Enbridge's field joining program as described in Book 4 of Enbridge’s Operating and Maintenance Procedures (“O&MP”) . Construction of the facilities will also be in accordance with Enbridge's construction safety procedures (O&MP Book 2, also on file with the NEB). Finally, all piping facilities will be hydrostatically tested in accordance with Book 3, Section 7 of Enbridge's O&MP manuals.

The relevant Enbridge manual references (which have all been filed with the NEB) are listed below:

Engineering Standards D02-101 Design Basis, Electrical Rev. July 20, 2006 D02-102 Design Basis, Mainline Rev. Sep 1, 1999 D02-103 Design Basis, Station & Terminal Rev. July 20, 2006 D02-104 Hazardous Area Classification Rev. Nov 16, 2006 D02-105 Fire Protection, Extinguishment Rev. Jan 06, 2000 D02-106 Noise & Acoustic Dampening Rev. Sep 1, 1999 D02-107 Station Manual, Preparation Rev. Sep 1, 1999 D03-101 Pipeline Corrosion Assessment Rev. Sep 1, 1999 D03-103 Internal Inspection, Mainline Rev. Sep 1, 1999 D03-104 Weld Inspection Rev. Sep 1, 1999 D03-105 Shop Inspection Rev. Sep 1, 1999 D04-101 Cathodic Protection Rev. Apr 20, 2006 D04-102 Painting, Coating & Lining Rev. July 28, 2006 D05-102 Site Preparation, Earthwork, Grading, Roads Rev. Sep 1, 1999 and Pavement D05-103 Trenches, Underground Lines Rev. Sep 1, 1999 D05-202 Foundation, Station & Terminal Rev. Sep 1, 1999 D05-301 Building, Station & Terminal Rev. Sep 1, 1999 D05-302 Laboratory, Sample & Sample Storage Buildings Rev. Sep 1, 1999 D05-401 Platforms, Stairs & Ladders Rev. Apr 29, 2003 D06-101 Piping Design & Construction, Mainline Rev. June 23, 2006 D06-102 Piping Design, Station & Terminal Rev. June 13, 2000 D06-104 Pipe & Fittings, Steel Rev. Nov. 15, 1999 D06-105 Valve, Steel Rev. June 15, 2000 D07-101 Pump, Mainline Rev. Nov 15, 1999 D07-102 Pump, Booster Rev. Nov 15, 1999 D07-201 HVAC, Building, Station & Terminal Rev. Nov 15, 1999 D07-202 Heat Tracing Rev. Nov 15, 1999 D07-203 HVAC, Pipeline Maintenance Building Rev. Nov 15, 1999 D09-101 Oil Measurement, Mechanical Rev. July 20, 2006 D09-102 Oil Measurement, Electrical Rev. Nov 15, 1999 D09-103 Sampler Rev. Nov 15, 1999 D10-101 Power System Design Rev. Oct 29, 2002 D10-102 Substation Design Rev. Dec 1, 1999 D10-103 Switchgear & Motor Control Center Rev. Oct 24, 2002 D10-104 Auxiliary Power Supplies Rev. Dec 1, 1999

D10-105 Power System Protective Relaying Rev. Nov 21, 2002 D10-106 Substation Grounding Rev. Dec 1, 1999 D10-107 Surge Protection & Insulation Coordination Rev. Dec 1, 1999 D10-201 Wiring Methods Rev. July 20, 2006 D10-202 Grounding Methods Rev. Dec 1, 1999 D11-101 Motor, Mainline Pump Rev. Dec 1, 1999 D11-102 Variable Frequency Drive Rev. Dec 1, 1999 D11-103 Motor Protection Rev. Dec 1, 1999 D11-201 Lighting, Indoor Rev. Dec 1, 1999 D11-202 Lighting, Outdoor Rev. Dec 1, 1999 D11-301 Valve Actuation & Control Rev. Aug 30, 2006 D12-101 Control, Pump Station Rev. July 20, 2006 D12-102 Control, Injection & Delivery Facility Rev. July 20, 2006 D12-104 Pressure Relief Rev. Oct 2, 2003 D12-201 Instrumentation, General Rev. Nov 26, 2002 D12-202 Gas Detection Rev. Dec 1, 1999 D12-203 Fire Detection Rev. Dec 1, 1999 D12-204 Vibration Monitoring Rev. Dec 1, 1999 D12-205 Programmable Logic Controllers Rev. Dec 1, 1999 D12-208 Pressure Control System Rev. Feb 21, 2006

Enbridge Environmental Guidelines for Construction December 2003

Enbridge Waste Management Plan October 2004 Section 2 – Waste Management Principles Section 3 – Classifying a Waste Section 4 – Storage Section 5 – Transportation Section 6 – Record Keeping System Section 7 – Treatment and Disposal

Enbridge Operating and Maintenance Procedures Book 3: Pipeline Facilities September 15, 2003 Book 7: Emergency Response December 1, 2004

For ease of reference, Appendix 7 provides definitions and details describing hydraulic design calculations used in this Application.

2.5 PIPING DECOMMISSIONING AND REMOVAL

As a consequence of the system upgrades proposed by Southern Access Phase 2, certain existing facilities will be removed and replaced. As such, there will be no effect on shipper services, other than during the time to remove and replace the facilities. Enbridge will endeavor to schedule the removal and replacement of the facilities in order to minimize the effects on shipper services. Removing these facilities, rather than abandoning them in the ground, will eliminate the need to manage the integrity of pipe that will no longer be in use.

All wastes generated as a result of these removals will be handled, sorted and transported in accordance with Enbridge's Waste Management Plan and applicable regulatory requirements. The drained oil will be taken by a qualified waste removal transportation service in a sealed vacuum truck and delivered to the closest Enbridge Terminal, where it will be injected into tankage and ultimately re-injected into one of Enbridge's pipelines. Waste disposal is discussed in greater detail in the Environment section of this Application.

2.6 ALTERNATIVES

In addition to the proposed scope two alternatives exist for increasing the capacity of the Line 4 pipeline. First, the option of increasing the pipe diameter of the Line 4 mainline was considered but ruled out due to both high cost and environmental effects. Secondly, the alternative of using Lines 1, 2, 3 or 13 to supplement Line 4 was also considered, however there currently is no additional capacity available to accept volumes from Line 4 on these lines, nor is any expected in the near future.

3.0 ENVIRONMENTAL ASSESSMENT PROCESS

Enbridge retained TERA Environmental Consultants (“TERA”) to prepare an Environmental and Socio-Economic Assessment (“ESA”) for the Project that would address the environmental impact of constructing and operating the proposed facilities, and to recommend preventative and mitigative measures to address any adverse environmental impacts identified. TERA’s report, entitled “Environmental and Socio-Economic Assessment for the Proposed Enbridge Pipelines Inc. Southern Access Upstream Expansion Project – Phases 2A & 2B”, is included as Appendix 1.

The ESA concludes that the environmental concerns identified are not extraordinary and potential impacts arising from this Project can be readily mitigated by standard environmental protection measures. Enbridge commits to undertaking the mitigative measures that have been recommended by TERA for the purpose of protecting the environment. One mitigative measure Enbridge will undertake includes a sweep for wildlife SARA species on noncultivated lands within 500m of the facilities where potential disturbance of wildlife species at risk may occur. If a SARA specie is identified, appropriate mitigative measures to minimize disturbance will be determined in consultation with Environment Canada. Further, Enbridge will undertake a post-construction noise impact assessment at each station following completion of the work, so as to ensure compliance with Alberta Energy and Utilities Board Noise Control Directive ID-99-8.

The report states that adverse residual environmental effects associated with this Project will generally be of limited areal extent and low in magnitude. Any impact as a result of the Project is not expected to significantly alter the environmental or socio-economic conditions in the respective areas.

4.0 ECONOMICS

4.1 SUPPLY

Please refer to Enbridge’s prior June 1, 2006 application for Stages 1A and 1B of the Southern Access Upstream Expansion for a discussion of various long-term forecasts for Western Canadian crude production.

4.2 TRANSPORTATION MATTERS

The “Enbridge Pipeline system” originates in Edmonton with connections to further receive or deliver Canadian crude oil and petroleum products at Hardisty; Kerrobert and Regina, Saskatchewan; and Cromer and Gretna, Manitoba. In the U.S., Enbridge Pipeline system connects with the Enbridge Energy Partner’s Lakehead system. Crude oil is delivered to the Northern Tier refineries in Minnesota and Wisconsin. Enbridge Pipeline also serves the Ontario and Midwest markets of Chicago, Toledo/Detroit and Warren, Pennsylvania. Through a connection to the newly reversed Spearhead Pipeline at Chicago, Canadian crude oil can access the southern PADD II Cushing, Oklahoma market. Via a connection to the Mustang Pipeline, connecting Chicago with Patoka, Illinois, crude oil can be transported to the refinery in Wood River, Illinois, east of Patoka, as well as the U.S. Gulf Coast through the recently reversed ExxonMobil pipeline.

Increased supply entering the market in the next few years is expected to constrain pipeline capacity, particularly heavy crude oil capacity, in the 2007-2009 timeframe. The proposed Southern Access capacity expansion in western Canada is for an additional 23,500 m 3/d (0.148 Mbpd). Table 5 demonstrates the increased capacities of Line 4.

Table 5: Annual Capacities of Line 4 Line Pre- Stage 2A Pipe Size Commodity Post- Stage 2B Capacity No. Capacity 4 NPS 36/48 Heavy Crude 116,500 m 3/d 140,000 m 3/d

The total overall take away capacity of Enbridge’s system downstream of Superior will slightly exceed the upstream total capacity of which the Phase 2 expansion is part of as indicated by Table 6.

Table 6: Enbridge Total System Annual Capacities Upstream and Downstream of Superior Annual Capacity Upstream of Superior Annual Capacity Downstream of Superior After Stage 2B After Stage 2B Line 3 Line 3 (m /d) (m /d) 2B 65,000 5 78,100 3 80,000 6A 106,000 4 140,000 14/64/61 Super Loop 73,500 Total 285,000 Total 257,600

Upstream Deliveries NGL Movements 3 (50,000) 3 (20,000) (m /d) (m /d) Movements into Movements into 3 235,000 3 237,600 Superior (m /d) Superior (m /d)

4.3 MARKETS

Please refer to Enbridge’s prior June 1, 2006 application for Stages 1A and 1B of the Southern Access Upstream Expansion for an analysis of various forecasts regarding the markets for Western Canadian crude production.

4.4 FINANCING

The estimated total reference capital cost of the Project is CDN $175,000,000, with an estimated cost of $57,312,000 for Stage 2A, and an estimated cost of $117,688,000 for Stage 2B. The Project will be financed through the use of internally generated funds. An estimated breakdown of the main elements of the capital cost of the Project is as follows:

Table 7: Capital Cost Elements ACTIVITY Material Labour Contract Contingency Total Engineering & Design - 1,149,900 4,860,500 901,600 6,912,000 Station Upgrades 67,509,300 2,148,700 23,183,300 13,838,900 106,680,200 Terminal Modifications 7,106,200 3,316,200 10,192,200 3,072,800 23,687,500 Transformer Upgrades 2,355,800 - 22,451,500 3,721,100 28,528,400 Subtotal 76,971,300 6,614,700 60,687,500 21,534,300 165,808,000

AFUDC 4,267,100 366,700 3,364,400 1,193,800 9,192,000

Total Estimated Capital Costs 1 175,000,000

1 The estimated costs of the Southern Access Stage 2 facilities are shown in 2006 dollars and are based upon Enbridge construction experience acquired through a number of construction projects completed within the past few years. Engineering and Project Management and General and Administration costs are based on Enbridge historical costs as a percentage of direct costs.

The proposed Project, which is a part of the Southern Access Expansion Program, involves $175 million in capital expenditures and will have a small toll impact. As such, Enbridge intends to file for a Southern Access Surcharge to the tolls at a later date and in the interim apply annual carrying charges to the revenue requirements to cover the non-material interim expenditures until such time that the sum of these expenditures for all phases necessitates a separate Southern Access surcharge. Enbridge has discussed this approach and the tolling impacts with CAPP, which concurs with the approach. The Surcharge terms are as per sub-Appendix 2 (Southern Access Enbridge Pipelines surcharge Terms) of Appendix A from the original 2005 document. A letter expressing CAPP’s support in this regard is also attached as Appendix 4.

Although at the time of CAPP's letter of support the cost estimate for Stages 2A and 2B was for an amount of $138 million, more detailed Engineering in the interim has led to a revised estimate of $175 million. The original estimate was based on a Class V Engineering estimate, which typically has a range of -30 to +45%, and which in this case translated into a range from $97 million to $200 million. The current forecasted cost of $175M falls within the approved estimate range.

5.0 PUBLIC CONSULTATION

5.1 Principles and Goals of the Consultation Program

Public notification and consultation for the Project are founded on Enbridge’s Corporate Social Responsibility (“CSR”) Policy (Appendix 5), which recognizes the value and importance of public consultation and stakeholder engagement as key components of good business practice. The Project consultation program has been guided by Enbridge’s public consultation principles: • Stakeholders will be informed in a timely and accurate manner about Enbridge’s business activities, and Enbridge will seek stakeholder input on business decisions potentially affecting them and on associated environmental and social impact assessments; • Enbridge will engage stakeholders early in the development planning process to learn about community goals and perspectives, and take those into account in decision- making; • Stakeholder consultation processes will be transparent and open; • Enbridge will endeavour to learn about and respect local, historical and traditional knowledge and economies; and • Enbridge will develop and maintain ongoing dialogue with stakeholders to increase knowledge of the effects of its business activities, develop balanced standards and expectations, and seek solutions to problems.

5.2 Design of the Consultation Program

Objectives The consultation program for the Project was designed to ensure that all parties that may be directly or adversely affected by the Project were provided with detailed and timely Project information.

The consultation program was also designed to ensure that interested parties had sufficient opportunity to respond with comments, questions or concerns, and, if they so chose, to meet in person with Enbridge representatives to discuss issues or obtain further information. Other objectives included: • identify all key stakeholder publics in accordance with regulatory requirements; • provide the publics identified with advance notification and information about the Project and, as events require, updated information in the time leading up to the Application filing;

• identify stakeholders’ issues of interest, provide the means for comment and input and, where possible, resolve concerns raised; • effectively reach stakeholders and provide them sufficient opportunity to learn about the Project and, if desired, provide input to the project planning and environmental assessment process; • document issues raised throughout the consultation program, and how they were considered and incorporated into Project planning; and, • explore ways in which the Project may be able to contribute positively to surrounding communities.

Complement to Existing Public Awareness Program The consultation program was also designed in the context of, and to complement, the public awareness program already in place relating to Enbridge Pipelines’ existing facilities in the areas where work is to occur. As a result of this ongoing communication program, Enbridge is well known to most of those living and working in each of the different Project areas.

Methods of Consultation Enbridge employed the consultation methods most appropriate in view of the Project scope, the environmental and socio-economic character of the Project area, and the information needs and consultation interests of each stakeholder. Since the Project work will occur entirely within existing Enbridge pump station properties, Enbridge determined that the nature, magnitude and potential impacts associated with the proposed Project are not likely to be extensive or long- lasting, with minimal environmental and socio-economic effects.

As a result of these considerations, it was Enbridge’s judgment that it is appropriate that the consultation program make use of written correspondence with stakeholders. Depending on stakeholder responses, further correspondence, meetings or telephone discussions would be used as appropriate.

Stakeholder Identification Enbridge identified potentially impacted stakeholder interests as part of designing the public notification and consultation process for this Project. Potential impacts stemming from construction activity such as noise were taken into account in determining the notification radius out from each work site. The relatively small scale of the proposed work is not expected to create much additional vehicle / equipment traffic or dust at any of the pump station modification sites. Based on these assessments, the potentially affected persons and groups to be notified and

consulted initially included landowners and occupants within approximately 500 metres of the Project.

To enhance the public notification program’s comprehensiveness, within a few days of the initial mail out it was decided to extend the notification mailing to the nearest landowners and occupants beyond the 500 metre notification radius at each Project site. At a minimum, this extended the public notification reach by an additional 100 to 200 metres. Please note: the distances stated in this Application are measured from the Enbridge fence line outwards, whereas distances in the ESA are measured from the emission point to the receptor point.

Local government bodies and other government authorities with responsibilities relevant to the Project were also identified as Project stakeholders.

Consultation Timing Public consultation began in November 2006 with a mail out of Project information. Consultation will continue as appropriate throughout the Project.

Stakeholders’ Information Needs Enbridge’s assessment of stakeholders’ information needs indicated that detailed information about the Project and its timing was required, along with an outline of the reasons for the Project, NEB and regulatory process information, environmental management information, and how stakeholders could obtain more information and become involved in the consultation and regulatory processes.

Process for Responding to Issues and Concerns Enbridge typically responds within a few days to issues and concerns brought forward by stakeholders, through in-person discussions initiated and carried on via personal meetings and / or telephone calls. Written correspondence and information provision may be included as part of the process for these dialogues. Dialogues with stakeholders are aimed at resolving the concern(s) to their satisfaction.

Future Consultation As indicated in the consultation principles previously outlined, Enbridge will continue its Project public consultation and stakeholder engagement activities throughout the Project life cycle, from the development and planning, regulatory application and construction phases through to operation of the upgraded stations. Once the facilities are in operation, stakeholder

communications and consultation are maintained through the Public Awareness Program and our other ongoing contacts with stakeholders.

5.3 Consultation Program Implementation

Consultation Activities Further to the consultation program design outlined above, the following activities were undertaken: • An information package dated November 27, 2006 (attached as Appendix 6), was sent by registered mail to those with land / residences adjacent to the 18 Project sites (within a radius of approximately 500 metres from the pump station), providing public notification and Project details.

The information package used in the November 27, 2006 mailing was also sent out December 7, 2006 by registered mail to an additional 32 recipients, comprising those residing on and / or owning property nearest to the 500-metre notification radius that Enbridge initially established, as well as to the identified government authorities.

Information packages were tailored to each Project station site, and detailed the work to be performed at that particular site. The information packages sent to government authorities in Alberta, Saskatchewan and Manitoba detailed the pump stations and work to be performed particular to that province. The information package letter in each case also advised recipients of the toll-free line number to call with any questions or comments. • On December 13, 2006, Enbridge determined that the legal land location used in one of the notification letters (for the Cromer, Manitoba pump station) was incorrect. The incorrect information went to a total of 20 recipients, comprising those within and just outside the 500 metre notification radius as well as local municipal and provincial government authorities. A correction letter with the right land location information was written and sent Express Post (via Canada Post) December 14, 2006, to those same 20 recipients. The original Cromer letter was also corrected and included, together with the Project map and the NEB brochure. In addition, telephone numbers were found for all but three of these 20 recipients, and calls placed to them. The telephone calls advised of the incorrect land location in the recent letter, explained that a corrected letter was on its way to them, and provided a toll-free telephone number to call with any questions. • The Five Hills Health Region in Moose Jaw, SK made a telephone request on December 14, 2006, to obtain a Project information package for Craik station after receiving a

Bethune station Project information package. Consequently, a Craik information package was sent Express Post to the Five Hills Health Region the same day, December 14, 2006.

Information Disseminated to Stakeholders Information provided to date during the consultation program, according to Enbridge’s assessment of stakeholders’ information needs: • Project need and background • Project details and specifications, including Project location both described by legal land location and shown on a map • Project timeline • Environmental protection and environmental management policies followed during construction and operation • Project public notification and consultation, including how to become involved • Information about the NEB • How to obtain more information • A map of the various project sites in Alberta, Saskatchewan and Manitoba • A copy of the NEB brochure: “A Proposed Pipeline or Power Line Project: What You Need to Know”

Stakeholders Contacted Stakeholders contacted and engaged with to date:

(A) Landowners and Tenants Approximately 330 landowners, tenants and occupants in proximity to the proposed Project, notified by registered mail

(B) Local Authorities and Governments The local authorities, primarily municipal, provincial and federal government bodies, and agencies and representatives were notified by registered mail in each of the following areas: • Hardisty, Alberta • Metiskow, Alberta • Cactus Lake, Saskatchewan • Kerrobert, Saskatchewan • Herschel, Saskatchewan • Milden, Saskatchewan • Loreburn, Saskatchewan • Craik, Saskatchewan

• Bethune, Saskatchewan • Regina, Saskatchewan • Odessa, Saskatchewan • Langbank, Saskatchewan • Glenavon, Saskatchewan • Cromer, Manitoba • Souris, Manitoba • Glenboro, Manitoba • St. Leon, Manitoba • Gretna, Manitoba

Consultation Outcomes

Stakeholder Contact Outcomes To date the consultation program for the Project has accomplished the primary objectives Enbridge established for it. To this point, no stakeholder has raised any issues or concerns. In light of the recent mail-outs and telephone calls in relation to the Cromer station, Enbridge will further update the NEB in relation to stakeholder consultation in the first week of January 2007.

Toll-free Line Outcomes To date, no one has called the toll-free telephone line.

Next Steps As indicated, Enbridge will continue its consultation program through construction and up to the in-service date of the updated Project facilities. Pending regulatory approvals, once operational, the Project facilities will be integrated into regular pump station activities and communication initiatives, including Enbridge’s existing Public Awareness Program.

5.4 Notification of Commercial Third Parties

Enbridge’s mainline system is being expanded and extended in response to customer demand, in particular to Western Canadian producers’ need for greater pipeline transportation capacity as oil sands production grows and refinery demand for Canadian heavy oil increases in key U.S. markets. Commercial Third Parties have been primarily made aware of this Project through meetings and correspondence between Enbridge and the CAPP.