expert report: pipeline variable assessments; nit- 900...

Expert Report:

Pipeline Variable Assessments; NIT-

900-034.993-1

Base Cost of 50 Kilometers of 4-Inch

Pipeline Built in Good Conditions with

Variable Assessments

Prepared for:

International Construction Consulting, LLC

8086 South Yale Avenue

Suite 290

Tulsa, Oklahoma, USA 74136

www.oil-gas-consulting.com

Comisión de Regulación de Energía y Gas (CREG)

Report 1502014-CREG-ICC-001

Comisión de Regulación de Energía y Gas (CREG) Greg Lamberson

Expert Report: Pipeline Variable Assessments; NIT-900-034.993-1 Base Cost per 50 Kilometers of 4-Inch Pipeline Built in Good Conditions with Variable

Assessments

Report 1502014-CREG-ICC-001 1 of 94 October 2014

Table of Contents

Change Log ..................................................................................................................................4

Disclaimer .....................................................................................................................................5

Executive Summary .....................................................................................................................9

1.0 Pipeline Construction Overview .......................................................................................... 14

1.1. Introduction ..................................................................................................................... 14

1.2. Terminology .................................................................................................................... 14

1.3. Regulatory Background ................................................................................................... 14

1.4. ASME Code B31.8 .......................................................................................................... 15

1.5. Pipeline Construction Safety ........................................................................................... 15

1.6. Engineering and Design Summary of Pipelines ............................................................... 16

1.7. Pipeline Construction Overview from an Estimating Standpoint ...................................... 17

2.0 Construction-Related Variables Assessed ......................................................................... 18

2.1. Soil Type ......................................................................................................................... 18

2.1.1. Overview of Typical Standard Industry Soil Classifications ....................................................... 18

2.1.2. General Overview of Soil Types Selected by CREG for Assessment ....................................... 19

2.1.2.1. Clay ............................................................................................................................................ 19

2.1.2.2. Sandy ......................................................................................................................................... 19

2.1.2.3. Rocky ......................................................................................................................................... 20

2.1.3. Excavation in Normal Soils ........................................................................................................ 20

2.1.4. Unstable Ground and Water in the Ditch ................................................................................... 21

2.1.5. Excavation in Rock .................................................................................................................... 21

2.1.6. Excavation in Sand .................................................................................................................... 23

2.1.7. Excavation through Wetlands .................................................................................................... 24

2.2. Vegetation ....................................................................................................................... 25

2.2.1. General Discussion on Vegetation Types for Pipeline Construction ......................................... 25

2.2.1.1. Tundra ........................................................................................................................................ 25

2.2.1.2. Temperate Broadleaf Forest ...................................................................................................... 26

2.2.1.3. Subtropical Rainforest ............................................................................................................... 26

2.2.1.4. Arid Desert ................................................................................................................................. 26

2.2.1.5. Dry Steppe ................................................................................................................................. 26

2.2.1.6. Savanna ..................................................................................................................................... 27

2.2.1.7. Tropical Rainforest ..................................................................................................................... 27

2.2.1.8. Alpine Tundra............................................................................................................................. 27

2.2.2. General Vegetation Clearing Methodology ................................................................................ 27

2.2.2.1. Typical Clearing Process ........................................................................................................... 28

2.2.2.2. Timber Disposal Process ........................................................................................................... 28

2.3. Water Table .................................................................................................................... 29

2.3.1.1. Groundwater Control Methods ................................................................................................... 29

2.3.1.2. Sumps and Ditches. ................................................................................................................... 29

2.3.1.3. Wellpoint Systems ..................................................................................................................... 29

2.3.1.4. Cofferdams. ............................................................................................................................... 30

2.4. Class Locations ............................................................................................................... 31

2.4.1.1. Pipeline Sizing Overview ........................................................................................................... 31



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2.4.1.2. Class Location Details ............................................................................................................... 31

2.4.1.3. Class Location Definition ........................................................................................................... 31

2.4.1.4. Population Density Index and Location Classification ............................................................... 33

2.4.1.5. Pipe Stress and Wall Thickness Calculations for Gas Transmission Pipelines per ASME Code B31.8 .......................................................................................................................................... 33

2.4.1.6. Allowable Pipe Stresses ............................................................................................................ 33

2.4.1.7. Wall Thickness Calculations ...................................................................................................... 35

2.4.1.8. Steel Pipe Design Formula ........................................................................................................ 36

2.4.1.9. Calculations for ASME Design Codes on Class Locations ....................................................... 37

2.5. Water Crossings and Marsh Lands ................................................................................. 38

2.6. Seismic Crossings .......................................................................................................... 40

2.7. Cultivated Land ............................................................................................................... 42

2.8. Extreme Terrain .............................................................................................................. 42

2.9. Double Jointing ............................................................................................................... 43

2.10. Connections .................................................................................................................. 43

2.10.1. Overview of Tie-ins by Hot Tap, Stopple, and By-pass ............................................................. 44

2.10.2. Restrictions ................................................................................................................................ 44

2.10.3. Typical Hot Tap Procedure for Pipe Replacement .................................................................... 45

2.10.3.1. Hot Tap Connections ............................................................................................................... 46

2.10.3.2. Fitting Types ............................................................................................................................ 47

2.10.3.3. Cutter Considerations .............................................................................................................. 47

2.10.3.4. Other Considerations .............................................................................................................. 47

2.10.3.5. Block Valve .............................................................................................................................. 48

2.10.3.6. Minimum Wall Thickness ......................................................................................................... 48

3.0 Assessments on Indexing and Ranges .............................................................................. 49

3.1. Assessment of Cost of Connection Multipliers................................................................. 49

3.2. Assessment of Topography Multipliers ............................................................................ 49

3.3. Assessment of Indexing Methodology and Criteria Used by CREG ................................. 50

3.4. Assessment and Opinion of Variables and Uncertainties ................................................ 51

3.5. Discussion on Interpolation of Variables Across Pipeline Diameters ............................... 53

3.6. Economy of Scale for Pipeline Diameter Variations......................................................... 53

3.7. Discussion on Interpolation of Pipeline Diameters and Lengths ...................................... 54

3.8. Economy of Scale for Pipeline Length Variations ............................................................ 55

3.9. Discussion on Cost Estimates, Tendering Overview and Pipeline Values ....................... 56

3.10. Assessment of Proportion of New Value ....................................................................... 57

4.0 Construction Cost Estimate Basis ...................................................................................... 59

4.1. General ........................................................................................................................... 59

4.2. Pipeline Base Case ......................................................................................................... 60

Appendix A – Variable Details for Report ................................................................................. 62

Appendix B – Base Case and Additional Diameter Costs per 100 meters; 10, 20, 50, 100,

and 200 Kilometers of Pipeline............................................................................................ 64

Appendix C – Design Pressure for Wall Thickness Calculations ........................................... 68

Appendix D – Variable Impacts on Base Case Spreadsheet ................................................... 69

Appendix E – Variable Impacts Across Diameters .................................................................. 70



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Appendix E1 – Variable Impacts Across 6-Inch Pipe .............................................................. 71

Appendix E2 – Variable Impacts Across 12-inch Pipe ............................................................ 72

Appendix E3 – Variable Impacts Across 18-Inch Pipe ............................................................ 73



Appendix F – Additional Variable Impacts Across Diameters ................................................ 76

Appendix F1 – Additional Variable Impacts Across 6-Inch Pipe ............................................ 77

Appendix F2 – Additional Variable Impacts Across 12-Inch Pipe .......................................... 78




Appendix G – Variable Graphs Across Selected Diameters ................................................... 82

Appendix H – Historical Data for Actual versus Estimate Pipeline Construction Costs ....... 92



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Change Log

REV SECTION CHANGE DESCRIPTION



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Disclaimer

This Report has been prepared by Greg Lamberson of International Construction Consulting, LLC (ICC) with all reasonable skill, customary care, and diligence within the terms of the agreement with Comisión de Regulación de Energía y Gas (CREG) and for the sole use of Comisión de Regulación de Energía y Gas (CREG). While reasonable care has been taken in the preparation of this Report, no warranty, express or implied is made in relation to the contents of this Report. Therefore, ICC assumes no liability for any loss resulting from errors, omissions, or misrepresentation made by others. The use of this Report by unauthorized third parties without written authorization from ICC should be at their own risk, and ICC should accept no duty of care to any such third party. The figures, tables, recommendations, opinions, statements, information, findings contained in this Report are based both on data available to the public as well as confidential/proprietary sources. Confidential/proprietary data may be used in the preparation of this Report and if so, will be referenced generally but not disclosed specifically. The figures, tables, recommendations, opinions, statements, information, findings contained in this Report are based on circumstances and facts as they existed at the time ICC performed the work. Any changes in such circumstances and facts upon which this Report is based may adversely affect any figures, tables, recommendations, opinions, statements, information, findings contained in this Report. Where field investigations have been carried out, these have been restricted to a level of detail required to achieve the stated objectives of the work referred to in the Agreement. The Author is an independent contractor with no ownership, partnership, nor relationship (apart from this contract) with Comisión de Regulación de Energía y Gas (CREG).



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Expert Qualifications

Greg Lamberson of International Construction Consulting, LLC is experienced in all phases of business, project, and construction management for upstream & midstream oil, gas, products, and energy-related projects. He is accomplished at working within complex, integrated work environments with multi-discipline and multi-cultural staffs to ISO, US, and various foreign standards, practices, procedures, and specifications in a variety of geopolitical climates on small, large, and mega-projects.

Mr. Lamberson’s background includes over 30 years experience on both domestic and international assignments, in the management, engineering, design, planning, construction, and start up & commissioning of upstream & midstream oil, gas, and energy related facilities, LNG plants, pipelines, coal-bed methane (CBM) extraction, fuel storage and distribution systems, including onshore, near-shore and offshore marine facilities and structures; economic analysis and strategic planning and execution of energy projects in North, Central, and South America, the Caribbean, the Middle East, Central Asia, China, Russia, the Far East, and Africa.

Mr. Lamberson is currently consulting for multi-national oil and gas companies in the upstream & midstream energy sector on a domestic and international basis. Areas of expertise include both technical (engineering and construction) and commercial (contracts, finance packages, etc.) aspects gained while working with integrated multi-national oil and gas companies, partnerships and joint ventures as a solution integrator and key source of expertise.

His skills and credentials include extensive construction and engineering experience; developing contracting strategies, project & construction management, contract negotiations, independent project assessments (including risk assessments; constructability reviews, construction readiness reviews, operations readiness reviews), partner and subcontractor selections, security, field development planning, project execution development and troubleshooting, feasibility studies, conceptual and detailed cost estimates, tender preparation and evaluations, and risk management. Mr. Lamberson’s education includes a BS, Industrial Engineering and Technology, East Central University, Oklahoma, USA, 1983; and an MBA, Robert Kennedy College, Switzerland, focus on international business, 2005. Mr. Lamberson has authored numerous articles, publications, and manuals including:

“Staffing Strategies for Major Capital Projects”, World Pipelines, June 2010 issue

“Managing Transitions on Major Capital Projects”, Asian Power, 2009.

“Developing Optimum Contracting Strategies for Major International Projects”, World Pipelines, March 2009 issue

“Project Management – Common Pitfalls & How to Avoid Them”, Energy Today magazine, a quarterly magazine covering the North American energy market, Spring 2009 issue.



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“Fundamentals of Gas Pipeline Metering Stations”, Pipeline & Gas Journal, co-written with Mr. Saeid Mokhatab, January 2009 issue.

“Managing Change – Manage Change on Major Projects”, World Pipelines, November 2008 issue

“Managing Execution Risks in Oil and Gas Processing Industry’ EPC Projects”, co-written with Mr. Saeid Mokhatab. To be published in a future issue of Hydrocarbon Processing, awaiting publications details.

“Basic Guide to Pipeline Compressor Stations”, Pipeline & Gas Journal, co-written with Mr. Saeid Mokhatab and Mr. Sidney Pereira dos Santos, June 2008.

“Pipeline Systems - Control and Integrity Management”, Journal of Pipeline Engineering, co-written with Mr. Saeid Mokhatab and Mr. Sidney Pereira dos Santos, December 2007, Vol. 6, No. 4 edition.

“Project Execution Risk: A Key Consideration for Upstream Energy Project Management”, World Oil, September 2007 issue; co-written with Mr. Saeid Mokhatab and Mr. D. Wood.

“A Constructive Approach - Constructability’s Role in Upstream Project Execution”, World Pipelines, June 2007 issue

Recognized contributor to Dr. Aurangzeb Khan, Assistant Professor, Dept. of Management Sciences, COMSATS Institute of Information Technology, Islamabad, Pakistan in providing material for the development of Project Management courses for post graduate students, 2006.

“Managing Execution Risk in Upstream Projects”, World Pipelines, December issue, 2006

Corporate Constructability Program. 2005, Developed and implemented a complete Constructability Program for a major international EPC contractor. Program is comprehensive covering all aspects of upstream EPC projects, including project-specific Constructability Plan template, checklists, charters, sample agendas, program maintenance & feedback mechanisms, dispute resolution, etc.

International Project Management System (IPMS), 2004, proprietary system for internal use as a guide for managing complex energy projects worldwide, from initial project assessments and feasibility studies to hook up, commissioning, and turn over. IPMS utilizes a phased approach that defines minimum deliverables required at specific phases along the project timeline. System also includes a prescriptive review process for passing into the next phase of project planning and execution.

Construction Managers Handbook (CMH), 2003, proprietary for internal use, provides guidance for the overall Construction Management aspects of the formation, organization, establishment, and management of project site work. The CMH guides the Construction



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Manager through the major segments of a construction project including mobilization, managing interfaces, transitions, construction implementation, and demobilization.

"Typical Hydrotest Water Intake and Discharge Mitigation Measure's", March 2002, published in ExxonMobil Global Share library system as an authoritative reference.

"Guidelines for Preparing a Construction Execution Plan", February 2002, published in ExxonMobil Global Share library system as an authoritative reference.

“Pipeline Construction”, Project Management Network Magazine, January 2002 (credited contributor to Ken Silverstein – author)

“Keys to Successful Execution of International Projects”, Project Management Institute, Troubled Projects, Fall 2001, Volume 1, Issue 3



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Executive Summary Greg Lamberson of International Construction Consulting, LLC was awarded the contract under the Terms of Reference to produce this expert report contrasting the cost differences of specifically identified Variables for gas pipeline construction projects with a base case of 4.500”. Mr. Lamberson selected 4.500” x 0.083” wt, X-65 pipe of 50 kilometers in length as the Base Case. Mr. Lamberson is an independent expert in the associated areas of pipeline design and construction. The purpose of this Report is to provide CREG with an overall costs for Variables that affect pipeline construction costs. The Author has included a discussion on the pipeline regulatory and design codes; pipeline estimating methodology; and how and why these Variables influence pipeline construction costs. The Report includes cost data comparisons for twelve (12) Variables, some with variations. The principle Variables requested for cost contrast by CREG are:

1) Soil Type: a. Clay b. Sandy soil c. Rocky

2) Vegetation: a. Tundra b. Temperate broadleaf forest c. Subtropical rainforest d. Arid desert e. Dry steppe f. Savanna g. Tropical rainforest h. Alpine tundra

3) Water Table: a. Typical water table requiring dam & pump type methodology b. High water table that requires dam & pump as well as a 500 meter section

that requires well points c. Cofferdam

4) Class Location1: a. Class 1 b. Class II c. Class III d. Class IV

5) Crossing Type: a. Wet crossing, consisting of a standard excavation & install crossing b. Horizontal Directional Drill (HDD) c. Aerial crossing

6) Seismic Crossing

1 It should be pointed out that the factors contained in Appendix E for Class locations are based on a pipeline system

with an MAOP of 1,200 PSI and the wall thicknesses calculated based on that MAOP are used to determine the additional pipe and installation costs.



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7) Cultivated Land 8) Extreme Terrain2

a. Terrain between 12% and 25% b. Terrain more than 25%

9) Double Joints 10) Connections

a. Hot tap, stopple, by-pass and tie-in to the existing service b. Hot tap, stopple and tie-in to the existing service c. Hot tap and tie-in to the existing service d. Cold cut and tie-in to the existing service

11) Economy of Scale for Pipeline Length 12) Economy of Scale for Pipeline Diameter 13) Congested pipe lay

The Base Case selected was a 4.500” diameter, 50-kilometer gas pipeline constructed in a generic international location and assuming a Class I location. From the base case, for each Variable, a cost run was developed and costed to indicate the percentage increase from the base cost. Details of each of the Variables are found in Appendix A. The base case3 makes several key assumptions, including:

• No double jointing of the pipe will be done

• Welding will be manual stick welding process

• Terrain will be relatively flat

• No rock excavation

• Limited major plant & equipment will be mobilized from outside the country

• Fusion bond epoxy (FBE) pipe coating and shrink sleeve joint coating

• $4.50 per gallon fuel

• Costs shown are construction/installation only, i.e. no permanent material costs are included4.

A total of thirty-five (35) cases were run to assess the Variable impacts on the Base Case. Breakdowns of the costs for the base case as well as the incremental costs from each Class location include:

• Total cost

• Total cost difference versus the Base Case

• Total cost per kilometer

• Multiplier per kilometer versus the Base Case

• Total cost per diameter-inch per meter

• Total cost delta contrasted with the Base Case in percentage

• Incremental cost per kilometer

• Incremental cost per diameter-inch per meter

2 The Author expanded the terrain cases as shown in Appendix A 3 Details of the Base Case assumptions can be found in Section 3 of this Report. 4 Permanent materials being defined as material typically provided by the Client and free-issued to the Contractor and includes line

pipe, valves and piping above 2”, launcher/receivers, transition bends.



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A supplementary ninety-six (96) cases were run, in addition to the costs for the Base Case (50 kms of 4.500”) and Variables. These included additional cases for diameter and length variations which are shown in Appendix B. The additional cases run include:

• 2.375 o 100 meters o 1 km o 3 kms o 5 kms o 10 kms o 15 kms o 20 kms

• 4.500” o 100 meters o 1 km o 5 kms o 10 kms o 20 kms o 100 kms o 200 kms

• 6.625” o 100 meters o 1 km o 5 kms o 10 kms o 20 kms o 50 kms o 100 kms o 200 kms


• 10.750” o 100 meters o 1 km o 5 kms o 10 kms o 20 kms o 50 kms o 100 kms



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o 200 kms








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In addition, as can be seen in Appendices E1 through E-5 and F-1 through F-5 an additional thirty-four (34) cases were run to assess Variable impacts of the following selected diameters in lengths of 50 kilometers:

• 6.625”

• 12.500”

• 18.000”

• 24.000”

• 30.000” The data contained in this Report is based on a typical pipeline construction project and does not represent any specific project, historically nor planned. The cost estimates and cost deltas contained in this Report are based on a proprietary cost estimate system developed by the Author that has been used for various pipeline construction contractors and energy companies to estimate lump sum costs for domestic and international pipeline construction projects.



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1.0 Pipeline Construction Overview

1.1. Introduction

Regulations governing interstate hazardous liquid and gas pipeline facilities are established and enforced on a federal level. For the purposes of this Report, CREG has requested the data contained herein be in accordance with the United States (USA) codes and regulations as they relate to pipeline design and construction, specifically ASME B31.8 for gas pipeline systems. This Report is based on the cost differences between each of the identified Variables and the base case, which is a 4-inch pipeline constructed in a Class 1 location under an ASME B31.8 designed pipeline system.

1.2. Terminology The pipeline right-of-way (ROW) on a property has a specified width within which the Company/Contractor has the right to construct and maintain one (or possibly more) pipelines with appurtenances. Payments are typically made to landowners for this right, and to landowners or tenants for all damages resulting from construction or maintenance both within and outside the defined width of a right-of-way. Construction forces commonly use the term “right-of-way” to describe the full construction working strip needed for construction of the line, very often a greater width than the actual right-of-way. The contractor should not encroach on lands outside the agreed working area. A pipeline spread is a single complete construction operation engaged in installing all or part of the line. Accordingly, a long line may be constructed by a single spread if time allows, or by two or more spreads (by the same or different contractors) proceeding concurrently on separate sections of the system. A pipe joint is a separate length of pipe, usually approximately 12 meters long, as shipped from the mill. A double-joint is made by welding two 12-meter joints together at a field double-jointing yard before the pipe is strung along the pipeline route. A field joint is a field-applied corrosion coating over the uncoated (cut-back) ends of plant-coated pipe at the weld joining two pipe joints.

1.3. Regulatory Background In the USA, regulations for hazardous liquid pipelines are covered in Title 49, Code of Federal Regulations, Part 195 (49 CFR 195), Transportation of Hazardous Liquids by Pipeline. Section 195.2 defines a hazardous liquid as petroleum, petroleum products, or anhydrous ammonia. Section 195.1(b) excludes onshore gathering lines in rural areas and onshore production facilities and flow lines. For gas pipelines, 49 CFR 191, covers annual reporting and incident reporting, and 49 CFR 192 deals with minimum federal safety standards for transportation of natural gas and other gas by pipeline.



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1.4. ASME Code B31.8 Incorporated by reference in 49 CFR 192 for natural and other gas, ASME Code B31.8, Gas Transmission and Distribution Piping Systems, applies to field gathering, transmission and distribution pipelines for natural gas. It covers the design, fabrication, installation, inspection, testing, and safety aspects of gas transmission and distribution system operation and maintenance. Code B31.8 does not apply to piping with metal temperatures above 450°F or below -20°F, vent piping operating at substantially atmospheric pressures, wellhead assemblies, or control valves and flow lines between wellhead and trap or separator.

1.5. Pipeline Construction Safety Construction contracts, practices, and procedures must incorporate safety requirements to protect:

Company and contractor personnel and equipment Pipeline facilities under construction Facilities of the Company and others lying within and adjacent to the pipeline

right-of-way and construction working area Landowners, tenants and property, livestock, and crops on lands the pipeline

crosses The public, their property and lands

Specific construction operations and hazards that are likely to need particular attention are:

Excavation sloping and shoring Blasting Radiation sources (welding and radiography) Grass and brush fires Work over water Crossing roads, pipelines, cables, overhead power, and telephone lines Parallel existing pipelines Testing and dewatering

Company and contractor operations must comply with federal, state and local regulations. Construction and service contractor compliance with these regulations is required by contract terms and conditions. It is a responsibility of the Company field organization to monitor and ensure the contractor’s compliance, but it is important that the proper contractual relationship be maintained in giving directives and instructions to contractors. Pipeline construction work is generally classified as a peculiar risk under the law. Industrial injuries can be severe and can expose the Company to significant liability. Recent court decisions (Jimenez, 1986) have held that an owner may be liable if a contractor’s employee is injured and the owner makes no effort to warn of the risk involved.



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Before construction activities begin the Company field construction organization should develop and subsequently maintain:

An accident-prevention program for the field organization, including appropriate safety and first-aid equipment, periodic safety meetings, and safety bulletins

List of doctors and hospitals, with names, addresses, and telephone numbers to be called in event of any injury—for both Company and contractor personnel

Arrangements for ambulance services and helicopter or air transport as appropriate

Fire-fighting procedures, with list of contacts for local fire-fighting agencies Contact and procedures with Underground Service Alert Center or equivalent

agency coordinating information on underground facilities List of contacts for companies and agencies controlling facilities such as

pipelines, power and telephone lines, highways, railroads, irrigation systems, and waterways

Procedures for dealing with damage to oil and gas pipelines and resulting spills Procedures for preparation and distribution of accident and incident reports to

the Company and regulatory authorities including notification to Company management in cases of serious incidents

Procedure for dealing with a bomb threat or similar event Early consultation with an environmental consulting company is recommended, with intermittent reviews during the construction period.

1.6. Engineering and Design Summary of Pipelines The key to successful engineering and design of pipeline systems is the use sound engineering judgment. A few examples where special consideration should be given are:

Extraordinary service conditions such as earthquake, high wind, other unusual dynamic loadings, or unusual superimposed dead loads

Cold climates that may require special materials to avoid brittle fractures High H2S concentrations that may place restrictions on valve trim and weld hardness

The use of standard design manuals that most companies have does not release the engineering team from their responsibility to use sound judgment in the selection of materials, fittings, valves, and other piping items to meet safety and economic considerations. Some examples of areas where variations could apply:

Use of lighter wall pipe for low pressure systems Use of higher yield strength materials when economics dictate Variation in corrosion allowance or selection of material for handling of

corrosive/erosive material

Special studies are needed to make final selection of pipe and coating for the length of the pipeline. The selection must meet Code B31.4 or B31.8 requirements, and will be influenced by economics and timely availability of materials.



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1.7. Pipeline Construction Overview from an Estimating Standpoint When an Estimator initially looks at a pipeline project, the first step is to determine the numbers of joints that can be welded by the pipe gang in a single day. Factors such as diameter and terrain come in to play. At this point, the wall thickness is of little importance in determining the number of joints that can be laid in a day, this becomes the daily spread production rate and is referred to in joints/day or footage/day. Once the daily lay rate is determined, then all other crews can be developed. All crews are resourced in order to meet the daily spread production rate. For example, if the daily spread production rate is determined to be 140 welds per day or 1,620 meters per day; the ROW, ditch, stringing, bending, welding, NDT, lowering-in, tie-ins, backfill, and cleanup crews must have the personnel, equipment and resources available to meet the required daily spread production rate. Regarding wall thickness impacts – wall thickness has little to do with the daily spread production rate as the overall production rate is determined by how many joints can be put into the line-up clamps and will receive a completed root & hot pass. Once the daily spread production rate is set, the requisite number of welders will be utilized. For example, on a 36” x .750” wall thickness pipe, the number of welders needed may be 16; however, if the wall thickness is .375” perhaps only 8 welders are needed to weld out the joints each day that have been fit up and have received a root pass. Once the estimated daily spread production rate is determined, all other crews are then resourced sufficiently to allow each crew to move along the pipeline ROW at the same general pace. The cost of the pipe generally represents 25% to 50% of the total line cost, and the use of a reliable cost will go a long way toward assuring a realistic total estimate. For mill run orders purchasing can usually obtain informal quotes from steel mills, based on total tonnage required. In calculating the tonnage of steel required, allowances are made for heavier wall pipe for river and highway crossings. In addition, allowances are made for waste and for the difference between the horizontal length of the line and its actual slope length. Even for lines laid through mountainous terrain, an allowance of 1% to 2% is usually adequate. For short producing field lines, both allowances combined (wastage and slope length) are about 5%.



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2.0 Construction-Related Variables Assessed Per the requirements set forth in the Terms of Reference (TOR), the Author was asked to assess specific Variables indentified by CREG and determine the cost impacts each would have on gas pipeline construction costs. The base cost for which the Variables will developed is a 50 kilometer, 4.500” x 0.083” wt, X-65 constructed in good conditions. This Section will describe the various Variables requested by CREG to be specifically assessed and provide some information on each in order to assist CREG when evaluating the cost impacts of each Variable or variation thereof. In some cases, the Variable variations may not have any cost impact from the Base Case. 2.1. Soil Type

CREG requested the following general soil types to be assessed:

Clay

Sandy

Rocky

2.1.1. Overview of Typical Standard Industry Soil Classifications The typical classifications of soil in the pipeline construction industry is derived from using five (5) general categorizations of soil and rock deposits, A through E4, as follows:

A. Stable Rock

A natural solid mineral matter that can be excavated with vertical sides and remain intact while exposed. It is usually identified by a rock name such as granite or sandstone. Determining whether a deposit is of this type may be difficult unless it is known whether cracks exist and whether or not the cracks run into or away from the excavation.

B. Type A Soils Cohesive soils with an unconfined compressive strength of 1.5 tons per square foot (tsf) (144 kPa) or greater. Examples of Type A cohesive soils are often: clay, silty clay, sandy clay, clay loam and, in some cases, silty clay loam and sandy clay loam. (No soil is Type A if it is fissured, is subject to vibration of any type, has previously been disturbed, is part of a sloped, layered system where the layers dip into the excavation on a slope of 4 horizontal to 1 vertical (4H:1V) or greater, or has seeping water.

C. Type B Soils Cohesive soils with an unconfined compressive strength greater than 0.5 tsf (48 kPa) but less than 1.5 tsf (144 kPa). Examples of Type B soils are: angular gravel; silt; silt loam; previously disturbed soils unless otherwise classified as Type C; soils that meet the unconfined compressive strength or cementation requirements of Type A soils but are fissured or subject to vibration; dry

4 These definitions are per the USA’s Occupational, Safety and Health Administration (OSHA) guidelines and have been widely adopted as international standards.



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unstable rock; and layered systems sloping into the trench at a slope less than 4H:1V (only if the material would be classified as a Type B soil).

D. Type C Soils Cohesive soils with an unconfined compressive strength of 0.5 tsf (48 kPa) or less. Other Type C soils include granular soils such as gravel, sand and loamy sand, submerged soil, soil from which water is freely seeping, and submerged rock that is not stable. Also included in this classification is material in a sloped, layered system where the layers dip into the excavation or have a slope of four horizontal to one vertical (4H:1V) or greater.

E. Layered Geological Strata Where soils are configured in layers, i.e., where a layered geologic structure exists, the soil must be classified based on the soil classification of the weakest soil layer. Each layer may be classified individually if a more stable layer lies below a less stable layer, i.e., where a Type C soil rests on top of stable rock.

In areas of agricultural land, or other areas as defined by project documents, the topsoil is stripped typically to a minimum depth of 150 mm and stored along the ROW on the side opposite to the working side. Topsoil, when required to be stripped for later use, is generally stored separately from subsoil. Each of the above general classifications presents differing issues to deal with from a pipeline construction standpoint. Section 2.1.2 below discuss the general soil types requested by CREG to be examined; and Sections 2.1.3 through 2.1.6 discussing specific issues as they relate to pipeline construction.

2.1.2. General Overview of Soil Types Selected by CREG for Assessment

2.1.2.1. Clay Clay soils tend to be heavy; however, for pipeline construction it presents no major obstacles. Clay soils have very good bearing and trenches through clay soils hold up very well. Clay soils are considered as the base case for this Report.

2.1.2.2. Sandy Sandy soil presents several challenges to pipeline construction. The trench walls are more unstable which typically leads to slightly different construction sequencing through the impacted areas. Normally through sandy areas, the pipe is laid first, and excavation and lowering-in is done afterward in close proximity so as not to have cave-ins of the trenching, which would require re-excavation and delay pipe installation. On the positive side, sandy soil is much easier to compact.



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2.1.2.3. Rocky Rock in solid beds or masses, in its original formation, encountered in ditching for the pipeline, requires ripping, utilizing rock buckets, or drilling and blasting for removal. A typical definition is “that which cannot be ripped with a D-8 equipped with a ripper shank or dug with a 330 Excavator equipped with a rock bucket”. Normally in rock excavation, the trench depth is less and often provides a minimum 60 cm of cover on top of the pipe.

2.1.3. Excavation in Normal Soils

In excavation through normal soils, the trench is advanced using a tracked excavator or a continuous trenching machine. The depth of the trench will be excavated to provide pipeline cover in accordance with the approved alignment sheets; typically, this will be 1-meter cover. The depth, width, and stability of the trench are checked as excavation progresses. In areas where safety of personnel or integrity of adjacent facilities is an issue, and where the soil type dictates, the trench is sloped back or benched to an appropriate angle, to prevent any material collapsing into the trench. Material excavated from the trench is stockpiled on the side of the ditch opposite to the work side, and sufficiently far back from the edge of the ditch to prevent overloading of the trench walls. See below for example:

When required, engineered trench boxes are also used, for example when performing a below grade tie-in in unstable soil. Below is an example of a trench box:



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The width of the trench is normally excavated to allow a minimum of 1120 mm at the bottom of the ditch. The bottom of the trench should be smooth with no rocks exceeding 25 mm in diameter and should match the pipeline profile. When necessary, the trench bottom is padded with fine-grained screened or imported material. The ditch, where personnel will enter, should have escape ramps, with slopes not exceeding 45 degrees, excavated every 500 to 1000 m (dependent upon the terrain) to provide an escape route for any personnel working in the ditch, as well as for any animals which may become trapped in the ditch. Additional space in the form of sloped bell-holes is provided in areas where tie-ins are to be installed. As mentioned, in some cases, engineered trench boxes must be used. Where ditch plugs are required, the sides of the ditch are widened to allow the plugs to be keyed in. On steeper slopes, hard plugs are often left in the ditch at identified locations. Typically, these locations include steep slopes and long slopes leading up to a major watercourse.

2.1.4. Unstable Ground and Water in the Ditch Situations may be encountered where soil conditions prevent maintenance of a stable trench wall. In those instances, it may be necessary to provide additional support in the form of lagging, sheet piling, or similar devices. Where personnel are required to work in the ditch, dewatering may be required. Pumping from a sump or well points may be necessary. When de-watering is required, the operation must comply with all safety and environmental requirements regarding the discharge of water from the ditch.

2.1.5. Excavation in Rock In areas of rock, once the grading is completed, typically a Caterpillar D10 bulldozer and/or a Caterpillar 345 backhoe are used to determine how much rock ditch trenching5 and rip ditch trenching will be encountered. Excess blasted rock that is unsuitable for use as backfill is normally hauled off-site to approved rock disposal area(s). Rip Ditch When the trench can be excavated through areas of rock, the ditch may be ripped using a D10, or equivalent machine, pulling a single shank ripper. Rock Ditch

5 Rock Ditch trenching can take the form of a specialized ditch machine for rock excavation or by traditional means of drilling, shooting,

and excavation of the trench.



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When the ditch area is unable to be ripped, rock blasting is carried out. Blasting operations are conducted by persons thoroughly familiar and licensed for such work. Normally the Contractor obtains blasting permits and provides notifications where required by regulatory authorities. Contractor prepares a Blasting Plan that will include at a minimum:

Explosives storage and transportation

Preparation and maintenance of a blast log

Plan of the blast hole spacing and depths and the location of the blast point in relation to alignment sheet stationing.

Type and strength of explosives, blasting caps and distribution of the delay periods used.

Total explosive loadings per round and per group of delays.

Prevailing weather conditions, including wind directions, approximate relative humidity, and cloud conditions at the time of the blast.

Date and exact firing time of blast.

Name of person in responsible charge of loading and firing, copy of state and federal licenses and blasting permit number, if required.

Often in areas where the blast could impact the surrounding location, blasting mats or padding are used. Rock excavation will have a considerable impact on ROW, trenching, and backfilling operations. This will involve managing explosives, drilling, shooting, rock excavation, rock disposal, hauling in of suitable fill and backfill material. The following outlines the basic requirements of handling rock. In areas of rock, once the grading is completed, typically a Caterpillar D-10 bulldozer and/or a Caterpillar 345 backhoe is used to verify how much rock can be ripped and how much will need to be blasted with excess blasted rock which is unsuitable for use as backfill to be disposed of in an approved rock disposal areas. Often a padding machine or machines are used which crush the rock to usable size to allow for use on backfilling after the pipe has been padded with a suitable material that does not damage the pipe coating. General Blasting Requirements This is not meant to be a comprehensive discussion on blasting operations, but only to provide a high level look at the basic steps required when rock is encountered. The Contractor will comply with good blasting practice and will develop a blasting plan to manage the work. A typical Blasting Plan is include:

Details of all permits and licenses, issuing authority, and validity period.

The location and length of the proposed area of blasting.

The charge pattern.



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The number of charges.

The type of explosives.

The sizes of charges.

The depths of drill holes.

The delays to be used.

Type and depth of stemming.

What notification has been issued.

Name of blaster.

2.1.6. Excavation in Sand Sand will present an issue predominately with trenching, lowering-in and tie-in operations due to the instability of the of the trench sides and they need for shoring and larger equipment to handle the pipe. Often trench boxes are required for tie-ins. Well points or other dewatering methods are commonly needed as water tables tend to be higher in sand. Sand is considered a Type C soil. Maximum allowable slopes for excavations less than 6 meters based on soil type and angle to the horizontal are as follows:

TABLE 1 - ALLOWABLE SLOPES6

Soil type Height/Depth ratio Slope angle

Stable Rock Vertical 90°

Type A ¾:1 53°

Type B 1:1 45°

Type C 1½:1 34°

Type A (short-term) ½:1 63°

(For a maximum excavation depth of 12 ft)

6 The slope angles represented are what are currently considered as Industry standards and are derived from the US Occupational

Safety and Health Administration (OSHA)



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FIGURE 1- SLOPE CONFIGURATIONS: EXCAVATIONS IN LAYERED SOILS.

As can be seen in the Table and Figure above, the amount of excavation is much greater with Type C soil than any other soil type. The additional knock-on effect, apart from additional excavation is an increase in the amount of backfilling that is required. Benching is also often required to assure trench wall stability. Benching increases costs due to the amount of additional time required to perform the benching work.

There are two basic types of benching, simple and multiple. The type of soil determines the horizontal to vertical ratio of the benched side. As a general rule, the bottom vertical height of the trench must not exceed 1.2 m for the first bench. Subsequent benches may be up to a maximum of 1.5 m vertical in Type A soil and 1.2 m in Type B soil to a total trench depth of 6.0 m. All subsequent benches must be below the maximum allowable slope for that soil type.

2.1.7. Excavation through Wetlands

Topsoil normally is not segregated in wetland areas. Dry wetland areas are excavated using normal methods to the extent possible. This may be a possibility in a seasonal wetland that is crossed during the dry season. For saturated wetlands, the ditch is excavated using tracked excavators working off swamp mats, board roads, timber riprap, or similar devices. Excavated spoil is stockpiled on the non-working side of the ROW.



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The extent of disturbance is restricted to that which is required for the excavation of the ditch. Traffic through the wetland is normally restricted to only those vehicles necessary to install the pipe, to the extent practical. Flooded wetlands are often excavated using either tracked excavators on mats or draglines working off barges or similar devices, or using marsh equipment excavators. Spoil, again, is stockpiled adjacent to the pipe ditch.

2.2. Vegetation

CREG requested the following general vegetation types to be assessed:

Tundra

Temperate Broadleaf Forest

Subtropical Rain Forest

Arid Desert

Dry Steppe

Savanna

Tropical Rainforest

Alpine Tundra

2.2.1. General Discussion on Vegetation Types for Pipeline Construction

2.2.1.1. Tundra Pipeline construction in Tundra presents design challenges for the installation of the pipeline. There are two options: 1) above ground on vertical support members (VSM), 2) buried with select fill due to the frost heaves that are commonly encountered in Tundra areas. Each installation method presents construction challenges. VSM’s are comprised of pipe supports each of which holds up the raised sections of pipeline. The VSM’s contain a sealed tube of ammonia. As the permafrost below the pipeline warms, the ammonia absorbs the heat and rises to a radiator on top of each stanchion. The ammonia is cooled by the outside air, condenses, and falls back to the bottom of the tube, where the process repeats itself and thus keeps the VSM’s stable throughout the winter and summer seasons. Additional construction impacts include trenching as typically rock type excavating equipment, such as Rocksaw trenchers are required to cut through the frozen soil. Cold temperatures indicative of tundra conditions presents issues for both equipment and personnel. Work efficiency is much lower due to the need to assure the safety and health of the workers by among other mitigations, increasing breaks and providing warm shelters in which to rest.



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2.2.1.2. Temperate Broadleaf Forest The difficulties these type areas present to pipeline construction is simply the clearing and disposal of brush, timber and tree roots. Some additional concerns are from an environmental (erosion and re-planting vegetation) and safety standpoint (due to wildlife, i.e. snakes, bees, poisonous animals).

2.2.1.3. Subtropical Rainforest Pipeline construction in subtropical rainforest does not present any more difficulties than that of a temperate broadleaf forest from a strict construction standpoint, with a couple of exceptions. Normally there is potentially more weather disruption as in sub-tropical rainforest areas, there are often periods of heavy rains, frequently a monsoon rainfall regime that can influence the overall pipeline construction schedule. Additionally a higher degree of environmental monitoring is required as sensitivities to the eco-systems are much greater.

2.2.1.4. Arid Desert Pipeline construction through arid desert terrain presents a variety of pipeline construction challenges. Some of these additional considerations include:

Logistics – often in desert environments access roads are sparse or non-existent. This extends the amount of time spent driving or requires additional camp locations be built.

Additional equipment is often needed for heavy truck towing in some areas

Constructing in sand and heat conditions presents equipment maintenance and repair issues

Potential of sand storms and lost days

High heat requires more breaks for workers

Moving and shifting sand presents ROW clearing and maintenance issues

Water for hydrotesting can be difficult to source and can require transportation, particularly if fresh water is required.

2.2.1.5. Dry Steppe Pipeline construction in a dry steppe region presents some similar issues to both desert and tundra conditions. Normally a dry steppe area has a dry climate that is too dry to support a forest, but not dry enough to be classified as a desert. The soil is typically of a high humus type and top soil removal is a consideration. Often extremes in temperature are found which does have a minor impact on construction.

http://en.wikipedia.org/wiki/Forest

http://en.wikipedia.org/wiki/Soil



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2.2.1.6. Savanna Pipeline construction activities in a savanna region have many of the same characteristics and issues as construction in a desert and dry steppe region.

2.2.1.7. Tropical Rainforest Pipeline construction activities in a tropical rainforest region have many of the same characteristics and issues as construction in a sub-tropical region with the possible exception of the risk of more sever rainfall and subsequent construction disruption. The principle cost driver and difference between sub-tropical, tropical, and a temperate broadleaf forest is the amount of weather disruption that will be expected.

2.2.1.8. Alpine Tundra Pipeline construction activities in Alpine Tundra present some unique challenges in pipeline construction. These areas are typically indicative of mountainous terrain with the presence or rocks and/or boulders. Cold temperatures also cause some construction issues, much as with tundra conditions.

2.2.2. General Vegetation Clearing Methodology Clearing of tress and vegetation typically begin in advance of pipeline ROW grading (bulk earth movement, stump removal, etc). Often the tree canopy along the ROW must be opened to allow wind and sun to accelerate moisture evaporation from the ROW following the cessation of the rains. When a high density of vegetation is encountered, it is a safety concern to maintain a consistent gap between the tree-felling and the clearing activity. Furthermore, it is often the first construction activity to permit the evaluation of local manpower and helps validate the projects socio-economic system based upon the performance of initial activities.

Tree felling activities is always limited to the area within the ROW limits available. All trees are typically cut (no limit of diameter or height) except in sensitive erosion or unsafe areas, which is normally determined in the project’s Environmental Management Plan (EMP). In addition, typically a tree buffer of 10 meters in width is left on each side of roads, railways, water bodies and cultural areas.

The method of tree-felling is by two basic methods: 1) manual (chainsaws) process; and 2) equipment, which involves the use of excavators or bulldozers equipped with special tree cutting attachments. Stump removal will be done by the ROW grading crew.



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Tree-felling is performed so that no trees will fall outside pipeline easement. Trees are not left leaning against standing trees along the edge of the pipeline easement or against trees left standing as part of buffer zones.

2.2.2.1. Typical Clearing Process Crew 1. The first crew is responsible for clearing the ROW by cutting brush with machetes. They typically stay approximately 1.0 km (One working day) ahead of crew number two. Crew 2. The second crew is responsible for cutting the trees within the land easement using manual or equipment method. All Trees to be felled should be cut as close as possible to ground level ensuring that the easement area is open and full fill Crew 3. The third crew, which is usually 300 m behind the second crew, and is responsible for removing boughs and branches from the felled trees and for cutting all trees, using chainsaws, into manageable lengths (to be transportable by two people). Crew 4. The fourth and last crew is responsible for storing cut timbers along the edge of the land easement, separate from the vegetal waste material (large timber which cannot be moved by hand will be left on the ROW where it had fallen and will be removed during ROW clearing and grading). They will also gather and store temporary waste vegetal material at the edge of the working area. When it is required, waste vegetal material should be left on the ground as an erosion preventive measure. Often, the timber is spread across the ROW after construction as it provides: a natural means of erosion control protection; promotion of vegetation growth; habitat for animals; a natural barrier to the use of the ROW by locals as a road.

2.2.2.2. Timber Disposal Process If it is necessary to dispose of some combustible non-hazardous solid waste via burning, the following procedures/precautions will be followed:

Burning will occur on the land easement away from any vegetation that could potentially be ignited by windborne embers or the fire itself. An area of bare ground will be preferentially utilized.

Burning will occur in locations where windborne smoke will not adversely impact nearby communities.

Burning will not occur when strong wind conditions exist.

All fires will be attended from the moment they are set to the moment they are extinguished.

The attendant(s) at a fire will have adequate firefighting resources on-hand.



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2.3. Water Table When ground water is encountered, various types of de-watering methods are utilized7. An important facet of dewatering an excavation is the relative risk of damage that may occur to the excavation, cofferdam, or foundation for a structure in event of failure of the dewatering system. The method of excavation and reuse of the excavated soil may also have a bearing on the need for dewatering. These factors, as well as the construction schedule, must be determined and evaluated before proceeding with the design of a dewatering system.

2.3.1.1. Groundwater Control Methods For commonly encountered water conditions during pipeline construction, methods for controlling groundwater are divided into two basic categories:

A. Interception and removal of groundwater from the site by pumping from sumps, wells, wellpoints, or drains. This type of control must include consideration of a filter to prevent migration of fines and possible development of piping in the soil being drained.

B. Isolation of the excavation from the inflow of groundwater by a sheet-pile cutoff, grout curtain, slurry cutoff wall, or by freezing (cofferdam).

2.3.1.2. Sumps and Ditches. An elementary dewatering procedure involves installation of ditches, French drains, and sumps within an excavation, from which water entering the excavation can be pumped. Often a 6” ditch pump or a series of ditch pumps are used to temporarily pump water from an excavation or pipeline trench to allow a tie-in to be done below ground. This method of dewatering generally should not be considered where the groundwater head must be lowered more than a few feet, as seepage into the excavation might impair the stability of excavation slopes nor have a detrimental effect on the integrity of the foundation soils. Filter blankets or drains may be included in a sump and ditch system to overcome minor raveling and facilitate collection of seepage. Disadvantages of a sump dewatering system are slowness in drainage of the slopes; potentially wet conditions during excavation and backfilling, which may impede construction and adversely affect the subgrade soil; space required in the bottom of the excavation for drains, ditches, sumps, and pumps; and the frequent lack of workmen who are skilled in the proper construction or operation of sumps.

2.3.1.3. Wellpoint Systems

Wellpoint systems are a commonly used dewatering method as they are applicable to a wide range of excavations and groundwater conditions.

7 Much of the information contained in this section was derived from the US Army Corp of Engineers Manual on Unified Facilities

Criteria (UFC) titled Dewatering and Groundwater Control UFC 3-220-05 dated 16 Jan 2005 which is considered a Best Practice in pipeline construction industry.



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A conventional wellpoint system consists of one or more stages of wellpoints having 3.8 cm or 5 cm diameter riser pipes, installed in a line or ring at spacings between about 0.9 and 3 meters, with the risers connected to a common header pumped with one or more wellpoint pumps. Wellpoints are small well screens composed of either brass or stainless steel mesh, slotted brass or plastic pipe, or trapezoidal-shaped wire wrapped on rods to form a screen. They generally range in size from 5 to 10 cms in diameter and 0.6 to 1.5 meters in length and are constructed with either closed ends or self-jetting tips. They may or may not be surrounded with a filter depending upon the type of soil drained. Wellpoint screens and riser pipes may be as large as 15.25 cms and as long as 7.6 meters in certain situations. A wellpoint pump uses a combined vacuum and a centrifugal pump connected to the header to produce a vacuum in the system and to pump out the water that drains to the wellpoints. One or more supplementary vacuum pumps may be added to the main pumps where additional air handling capacity is required or desirable. Generally, a stage of wellpoints (wellpoints connected to a header at a common elevation) is capable of lowering the groundwater table about 4.5 meters; lowering the groundwater more than 4.5 meters generally requires a multistage installation of wellpoints. A wellpoint system is usually the most practical method for dewatering where the site is accessible and where the excavation and water-bearing strata to be drained are not too deep. For large or deep excavations where the depth of excavation is more than 9 or 12 meters, or where artesian pressure in a deep aquifer must be reduced, it may be more practical to use eductor-type wellpoints or deep wells (discussed subsequently) with turbine or submersible pumps, using wellpoints as a supplementary method of dewatering if needed. Wellpoints are more suitable than deep wells where the submergence available for the well screens is small and close spacing is required to intercept seepage.

2.3.1.4. Cofferdams. A common method of excavating below the groundwater table in confined areas is to drive wood or steel sheet piling below subgrade elevation, install bracing, excavate the earth, and pump out any seepage that enters the cofferdammed area.

(1) Dewatering a sheeted excavation with sumps and ditches is subject

to the same limitations and serious disadvantages as for open excavations. However, the danger of hydraulic heave in the bottom of an excavation in sand may be reduced where the sheeting can be



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driven into an underlying impermeable stratum, thereby reducing the seepage into the bottom of the excavation.

(2) Excavations below the water table can sometimes be successfully made using sheeting and sump pumping. However, the sheeting and bracing must be designed for hydrostatic pressures and reduced toe support caused by upward seepage forces. Covering the bottom of the excavation with an inverted sand and gravel filter blanket will facilitate construction and pumping out seepage water.

2.4. Class Locations

2.4.1.1. Pipeline Sizing Overview To size a pipeline, one must identify the significant elements necessary to evaluate and compare alternatives, estimate costs, and perform an economic analysis of the alternatives. Cost differentials for alternative line sizes must include the following elements:

Annual throughput rates for the period selected as the analysis basis

Pipeline and compression/pumping facilities with capacity to handle the throughput rates

Compression/pumping energy to transport the stock at throughput rates

Alternative forecast throughputs often consist of a most-likely case, and less likely cases at lower and higher rates. Sensitivity analyses are made to determine the effects of the other cases—or a composite case—given the line size selected by the most-likely case analysis.

2.4.1.2. Class Location Details

When identifying and classifying locations per ASME B31.8 for the purpose of determining the Design Factor (see Table 1 on the next page) and the testing requirements, consideration should be given to the possibility of future development and the anticipated increase in population density that will occur after a line is constructed. If future development appears to be sufficient to change the class location, this should be taken into consideration in the design and testing requirements.

2.4.1.3. Class Location Definition (1) A “class location unit” is an onshore area that extends 200 meters

on either side of the centerline of any continuous 1.6 kilometer length of pipeline8.

(2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.

8 As defined by ASME B31.8



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(a) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows: (1) A Class 1 location is:

(i) An offshore area; or (ii) Any class location unit that has 10 or fewer

buildings intended for human occupancy.

(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.

(3) A Class 3 location is: (i) Any class location unit that has 46 or more

buildings intended for human occupancy; or (ii) An area where the pipeline lies within 90

meters of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.)

(4) A Class 4 location is any class location unit where

buildings with four or more stories above ground are prevalent.

(b) The length of Class locations 2, 3, and 4 are typically

adjusted as follows: (1) A Class 4 location ends 200 meters from the nearest

building with four or more stories above ground. (2) When a cluster of buildings intended for human

occupancy requires a Class 2 or 3 location, the class location ends 200 meters from the nearest building in the cluster.

Table 1 - Class Location/Design Factor

Class Location Design Factor

1 0.72

2 0.60

3 0.50

4 0.40



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2.4.1.4. Population Density Index and Location Classification Code B31.8 relates calculations for allowable design pressures to damage resulting from the failure of a gas pipeline, and classifies locations by population density. For each mile (1.6 kilometers) of the pipeline, Section 840.2(a) of Code B31.8 defines a zone 400 meters wide (centered on the pipeline) and 1.6 kilometers. Within each zone, buildings intended for human occupancy are counted, with each separate dwelling unit in a multiple-dwelling-unit building counted as a separate building. The number of buildings contained within each portion of land classifies each zone: Class 1. 10 or fewer buildings; for example, wasteland, deserts,

mountains, grazing land, farmland, sparsely populated areas, and offshore

Class 2. More than 10 but less than 46 buildings; for example, fringe areas around cities and towns, industrial areas, and ranch or country estates

Class 3. 46 or more buildings (except where a Class 4 location prevails); for example, suburban housing developments, shopping centers, residential areas, industrial areas, and other populated areas not meeting Class 4

Class 4. Areas where multistory buildings are prevalent, traffic is heavy, and where there may be numerous other utilities underground. Multistory is defined as four or more floors above ground, including the first or ground floor

A Class 2 or 3 location that consists of a cluster of buildings may be terminated one eighth mile (200 meters) from the nearest building in the cluster. Section 192.5(f) of 49 CFR 192 further provides that Class 4 locations end one-eighth mile (200 meters) from the nearest building with four or more stories. Section 840.3 of Code B31.8 advances additional criteria that take into account the possible consequences of failure near a concentration of people, such as in a church, school, multiple dwelling unit, hospital or organized recreational area. In establishing location classes consideration must also be given to the possibility of future developments.

2.4.1.5. Pipe Stress and Wall Thickness Calculations for Gas Transmission

Pipelines per ASME Code B31.8 The organization and some aspects of the design procedure in Code B31.8 differ from Code B31.4. See especially Code B31.8 Chapter IV, Design, Installation, and Testing, Sections 840 and 841.

2.4.1.6. Allowable Pipe Stresses

The Codes establish the allowable stress value S for new pipe as:

S = 0.72 E SMYS (Eq. 400-7)

where:



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0.72 = Design factor based on nominal wall thickness tn. In setting

this design factor, the code committee gave due consideration to and made allowance for the underthickness tolerance and maximum allowable depth of imperfections provided for in the specifications approved by the Code

E = Weld joint factor. For pipe normally considered for new lines, E = 1.00

SMYS = Specified minimum yield strength, psi Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the Specified Minimum Yield Strength (SMYS), in no case where the Code refers to SMYS should a higher value be used in establishing the allowable stress value. Tables are available that tabulates allowable stress values for pipe of various specifications, manufacturing methods, and grades, based on the above, for use with piping systems within the scope of the design Code. The Code covers:

Allowable stresses for used (reclaimed) pipe, pipe of unknown origin, and cold-worked pipe that has subsequently been heated to 600°F or higher;

Limits allowable stress values in shear and bearing;

Limits tensile and compressive stress values for pipe and other steel materials when used in structural supports and restraints; and

Covers allowable stress values due to sustained loads and thermal expansion for the following stresses:

o Internal pressure stresses. The calculated stresses due

to internal pressure should not exceed the applicable allowable stress value S.

o External pressure stresses. Stresses due to external pressure are considered safe when the wall thickness of the piping components meets the requirements.

o Allowable expansion stresses (as for heated oil lines). The allowable stress values for the equivalent tensile stress for restrained lines should not exceed 90% SMYS of the pipe. The allowable stress range, SA, for unrestrained lines should not exceed 72% of SMYS of the pipe.

o Additive longitudinal stresses. The sum of the longitudinal stresses due to pressure, weight, and other sustained external loadings should not exceed 75% of the allowable stress value specified for SA under “allowable expansion stresses.”



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o Additive circumferential stresses. The sum of the circumferential stresses from both internal design pressure and external load in pipe installed without casing under railroads and highways should not exceed the applicable allowable stress value S determined by the Code.

2.4.1.7. Wall Thickness Calculations

The basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value is give by:

(Eq. 400-8)

where: t = pressure design wall thickness, in. Pi = internal design gage pressure, psi D = nominal outside diameter, in. S = allowable stress value, psi, (per Section 402.3.1(a) of Code

B31.4) The nominal wall thickness tn of straight sections of steel line pipe should be equal to or greater than the sum of the pressure design wall thickness, and allowances for threading and grooving, corrosion, and prudent protective measures:

tn ³ t + A

(Eq. 400-9)

where

A = sum of allowances for: Threading and grooving (zero for welded line) Corrosion (zero if the line is protected against internal and external

corrosion). For stocks where corrosion (or slurry erosion) is expected, a corrosion allowance must be provided, and a materials and engineering analysis to determine the amount of corrosion allowance is recommended

Increase in wall thickness as a reasonable protective measure to prevent damage from unusual external conditions at river crossings, offshore and inland coastal water areas, bridges, areas of heavy traffic, long self-supported spans, and unstable ground, or from



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vibration, the weight of special attachments, or abnormal thermal conditions.

The nominal wall thickness should not be less than the minimum required by prudence to resist damage and maintain roundness during handling and welding. The appropriate minimum should be evaluated for the particular installation conditions. As a rough guide, the following is suggested:

0.188 inch wall for sizes up to and including NPS 12 0.219 inch wall for NPS 14 through 24 A maximum D/tn ratio of 120 for pipe over NPS 24

These represent minimums for reasonable cross-country pipeline laying conditions. Consideration must also be given to buckling of double-jointed lengths of pipe and to fatigue stresses if extensive cyclical loading is possible during transport from the mill to the job site. The latter problem is discussed in API Recommended Practices RP 5L1, Railroad Transportation of Line Pipe; RP 5L5, Marine Transportation of Line Pipe; and RP 5L6, Transportation of Line Pipe on Inland Waterways.

2.4.1.8. Steel Pipe Design Formula Section 841.11 of ASME B31.8 gives the hoop stress formula (Equation 400-10) relating internal design pressure, pipe wall thickness, pipe diameter, and factors applied to the specified minimum yield strength (SMYS) to establish a pipe stress value.

(Eq. 400-9)

where: P = design pressure, psig D = nominal outside diameter, in. T = nominal wall thickness, in. S = specified minimum yield strength (SMYS), psi, stipulated in the

Specifications to the manufacturer F = construction type design factor per Code B31.8 Table 841.1A,

ranging from 0.72 to 0.40, for four construction types, determined from Tables 841.15A, .15B, and .15C, and Sections 841.122 and 841.123. In setting the values for F, due consideration has been given and allowance has been made for the various underthickness tolerances provided for in the specifications approved by Code B31.8

E = longitudinal joint factor per Code B31.8 Table 841.1B. For pipe normally considered for new lines, E=1.0



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T = temperature derating factor per Code B31.8 Table 841.1C. For temperatures of 250°For less, T=1.0

Although mill tests for particular runs of pipe may indicate actual minimum yield strength values higher than the SMYS, in no case where Code B31.8 refers to SMYS should a higher value be used in establishing the allowable stress value (see Section 841.121(f) of Code B31.8). Code B31.8 Section 841.121(d) warns that the minimum thickness, t, required for pressure containment by Equation 400-10 may not be adequate to withstand transporting and handling during construction, the weight of water during testing, and soil loading and other secondary loads during operation, or to meet welding requirements. Code B31.8 Section 816 requires pipe with a D/t ratio of 70 or more to be loaded in accordance with API RP 5L1 for rail transport, API RP 5L5 for marine, or API RP 5L6 for inland waterway. If it is impossible to establish that transporting has been done in accordance with the appropriate recommended practice, special hydrostatic testing must be done. Code B31.8 makes no specific reference to internal corrosion allowance, but Section 863 in Chapter VI, Corrosion Control, discusses internal corrosion control in general.

Code B31.8 Section 841.121(b) limits the design pressure P for pipe not furnished to specifications listed in the Code or for which the SMYS was not determined in accordance with Section 811.253 of the Code. Section 841.121(e) covers allowable stress for cold-worked pipe that has subsequently been heated to 900°F for any period of time or over 600°F for more than one hour. Section 841.13 of the Code B31.8 covers protection of pipelines from hazards such as washouts, floods, unstable soil, landslides, installation in areas normally underwater or subject to flooding, submarine crossings, spans, and trestle and bridge crossings.

2.4.1.9. Calculations for ASME Design Codes on Class Locations A preliminary determination of pipe wall thickness(es) is necessary since the cost of pipe is based on tonnage, a function of diameter and wall thickness. The basic pipe hoop stress formula relating internal pressure, pipe wall thickness, pipe diameter and stress value is:

(Eq. 400-4)



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where:

t = pressure design wall thickness, in. Pi = internal design gage pressure, psig D = outside diameter, in. S = allowable stress value, psi

The Code establishes the allowable stress value S and contains Tables to tabulate allowable stress values for pipe of various specifications, manufacturing methods and grades. As a preliminary design basis for line sizing, API Specification 5L Grade X60 pipe is suggested, for which S = 0.72 x 60,000 = 43,200 psi. For gas lines, assuming no corrosion allowance, the nominal wall thickness tn equals the pressure design wall thickness t. The hoop stress formula then becomes:

(Eq. 400-5)

Pipe wall thicknesses commonly manufactured are given in API SPEC 5L, Section 6, Table 6.2. Wall thickness calculations for the base case as well as each of the additional pipeline diameters assessed can be found in Appendix C.

2.5. Water Crossings and Marsh Lands

Pipeline waterbody crossing techniques can generally be divided into four main categories:

(a) Wet Crossings, which typically involve construction activities that are in direct contact with the live waterbody.

(b) Dry Crossings, which involve the use of measures to isolate trench excavation and pipe placement activities from the live waterbody or open water.

(c) Non-Buried Crossings, which involve attaching the pipeline to a structure to suspend the pipe across the watercourses or involve the laying of the weighted pipeline on the bottom of the watercourse.

(d) Trenchless Crossings, which involve the drilling or tunneling of the pipeline under the waterbody with the most common form being directional drilling. Detailed information regarding the horizontal directional drilling technique can be found in the following two publications: (1) Installations of Pipelines by



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Horizontal Directional Drilling (1995); and, (2) Drilling Fluids in Pipeline Installations by Horizontal Directional Drilling (1994).

The selection of the method and the equipment to be used is dependent upon a number of variables. The following sections describe each of the methods; as well, the advantages and disadvantages are identified from both the construction and environmental standpoints. The appropriate uses for each technique are outlined. The objective in selecting a crossing technique is to choose the most environmentally appropriate and cost effective method. Impacts to water quality and habitat are to be minimized by:

Use of the appropriate crossing technique.

Timing construction to avoid environmentally sensitive periods.

Completing the crossing in the shortest possible time frame.

Implementing erosion and sediment control measures.

Stabilizing and restoring the site as quickly as possible.

The two types of waster body crossings quantified in this Report are Wet Crossings and Trenchless Crossings, in this case Horizontal Directional Drilling (HDD). Wet Crossings For saturated wetlands, the ditch should be excavated using tracked excavators working off of swamp mats, board roads, timber riprap, or similar devices. Excavated spoil should be stockpiled on the non-working side of the ROW. Pipe will contain buoyancy control by either means of continuous concrete weight coating9 or set-on type weights. The extent of disturbance will be restricted to that which is required for the excavation of the ditch. Traffic through the wetland is normally restricted to only those equipment/vehicles necessary to install the pipe, to the extent practical. Flooded wetlands often have to be excavated using either tracked excavators or draglines working off barges or similar devices, or using marsh equipment excavators. Spoil is generally piled adjacent to the pipe ditch and then backfilled with the same type of equipment. HDD Installation of a pipeline by horizontal directional drilling (HDD) is a two-stage process. The first stage consists of drilling a small diameter pilot hole along a designed directional path. The second stage involves enlarging this pilot hole to a diameter that will accommodate the pipeline, and then pulling the pipeline back into the enlarged hole. The following diagrams explain the general process:

Drilling of the pilot pass along the planned trajectory

9 For the costs shown in Variables 3a, 3b, 3c, and 5a in Appendix D, continuous concrete weight coating was used.



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Widening of the pilot pass to a diameter exceeding that of the pipe

Installation of the pipe

Regardless of the techniques selected for the crossing, there will be a considerable increase in environmental oversight & mitigation measures required. Aerial Crossings Installation of a pipeline by aerial crossing means the pipeline will be suspended over an obstacle. The pipe will be installed above ground and will be supported at a minimum at each end and often will have interim supports depending on the size of the pipe and the length of the crossing.

2.6. Seismic Crossings Seismic crossings have significant design and material requirements due to the high degree of risk imposed. Material and design costs were not included in this cost variable exercise as only construction costs were to be included.



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Below is a general discussion of the types and reasons for impacts in construction costs that seismic conditions may have on construction costs.

(a) Pipeline Burial Depths at Fault Crossings Pipelines crossings at faults are typically trenched and buried. Burial depths should be calculated, but are not normally extreme.

(b) Trench Configurations at Fault Crossings Two trench configurations are normally utilized at fault crossings: a 'trapezoidal trench' configuration at the center of the fault crossing; and a 'sand padded trench' configuration at each side of the fault crossing. Trench configurations are part of the seismic study and typically one may substitute the 'trapezoidal trench' in place of the 'sand padded' trench configuration resulting in only one fault crossing trench configuration; but it is not advisable to substitute 'sand padded' in place of 'trapezoidal' trench configuration. The minimum length of trapezoidal trench, centered at the fault location, is calculated and may run from 150m to upwards of 1,000m each side from the centerline of the fault.

(c) Trapezoidal Trench Configuration The trapezoidal trench cross section typically has sidewall slopes less than 1:2 vertical to horizontal and a minimum trench bottom width of 2.75m. Trench backfill material is to be select backfill.

A typical trapezoidal configuration is shown below:

(d) Sand Padded Trench Configuration The sand padded trench is typically constructed as per the figure below.

2.75 m min.

5.7 m for = 35

45-/2

Native Soil

0.3 m Cap, Trench Spoil or Equivalent

5.7 m for = 35

Select GranularBackfill

0.15 m min.



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(e) Select Backfill Requirements Select backfill is typically a loose granular material such as well-graded loose to moderately dense sand, or equivalent, to provide a minimum internal angle of friction of 35 degrees or less. 100% of the backfill material aggregate should be less than 30mm diameter. Crushed rock is normally not allowed to be used. Backfill is normally moderately compacted to a relative density of less than 66%.

(f) Pipeline Wall Thickness at Fault Crossings Seismic crossings typically require an engineering study that normally requires a different strength of steel and wall thicknesses used over the entire length of special fault crossing construction.

2.7. Cultivated Land

Pipeline construction through cultivated lands presents several considerations for pipeline construction companies. Those considerations are primarily:

Extra depth of burial is typically required in order to allow for the installation of the pipeline below drainage systems that are often present or to assure the pipeline is at a sufficient depth to avoid damage from farm equipment. This requires additional trenching and additional backfilling costs.

Top soiling the width of the ROW is typically required in order to replace the existing topsoil. This requires additional ROW work in carefully removing the topsoil to one side and protecting it during construction and the replacement after construction has an impact on the cleanup crew costs.

2.8. Extreme Terrain

Extreme terrain present numerous safety and construction challenges. Additional ROW work is required to get the terrain into as suitable condition for construction as possible. The sequential work itself is much slower through extreme terrain, increasing as the terrain difficulties increase and may include utilizing winches and cables to allow equipment to work on the slopes.



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2.9. Double Jointing Double jointing is a misunderstood concept in the pipeline industry. A number of factors go into the decision as to whether double jointing is a prudent decision to make for a project. These factors include:

Economics. Double jointing does increase the daily lay production of the welding crew. However, it also requires additional resources in all other crews, i.e. ROW, trenching, stringing, etc. Additionally, specialized equipment is needed, in addition to the double joint rack required to physically double joint the pipe

Terrain. Some terrains are not suitable to double jointing, such as mountainous terrain. Handling of the double jointed in difficult terrains will often offset the faster lay capabilities.

Experience is a key factor is determining the viability of double jointing from a terrain standpoint. Once the decision is made that it is physically prudent to use the double jointing concept, then it is a matter of simple economics. In this Report, it is assumed the entire length of 50 kilometers is suitable for double jointing. It should be noted, for the Base Case, double jointing does not provide a cost savings. This is not a surprising result as smaller diameter pipe typically is not a good candidate for double jointing. The larger the diameter and the longer the pipeline the more cost effective double jointing becomes if the terrain is conducive. How double jointing impacts costs across pipeline diameters is indicated in Appendix E, Variable 9a.

2.10. Connections When making a tie-in to an existing pipeline where the pipeline will remain “in-service” during the tie-in, a hot tap utilizing a stopple and a by-pass is typically used. See Section 2.10.1 through 2.10.3 for a brief overview of the process. Other connections considered as cost variables include:

1) Hot tap, stopple no by-pass. Same as described in Sections 2.10.1 through 2.10.3 with no by-pass installed. This method requires a full shutdown of the pipeline system.

2) Hot tap (see Figure 1 below from TD Williamson) 3) Cold cut. This method is simply the use of a cold cutting machine,

normally for smaller diameter it is used manually, for larger diameter (over 16”) normally a mechanized cold cutter is used. This method requires a full shutdown of the pipeline system.

Figure 1: Hot Tap Overview



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2.10.1. Overview of Tie-ins by Hot Tap, Stopple, and By-pass

Sections 2.10.2 through 2.10.3 describe a hot tap, stopple, by-pass tie-in based on API 2201.

2.10.2. Restrictions A hot tap should not be made under the following conditions: 1) Piping that contain acids, ammonia, chlorine, or chlorine compounds which

could decompose from the heat of welding

2) Piping that contain hydrogen above 100C (212F) 3) Piping that are clad, lined, or overlaid with any of the following:

a) Glass b) Lead c) Refractory d) Cement e) Plastic or alloy metal

4) Piping that is jacketed 5) Piping that requires Post Weld Heat Treatment (PWHT) according to applicable

codes and standards 6) Piping in hydrofluoric acid service 7) Piping in caustic service where concentration and temperature require PWHT,

or where steam-out of caustic lines/equipment is performed during shutdowns/start-ups—regardless of concentration, hot taps in caustic lines



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should be temporary, pending PWHT or replacement during the maintenance outage.

8) All air- lines where lubricating oil may have entered the system, resulting in a hazardous atmosphere

9) Pressure vessels and heat exchangers

2.10.3. Typical Hot Tap Procedure for Pipe Replacement The following is the basic process when using a hot tap procedure for the replacement of a pipe section: 1) A stopple fitting with a Lock-O-Ring or approved equivalent flange is welded on

each end of the section to be isolated. 2) Bypass fittings with Lock-O-Ring or approved equivalent flanges and

equalization connections are welded to the line. (The equalization connections should also be used for venting, purging, and testing purposes.)

3) At each fitting, the following should occur: a) An isolating valve and a tapping machine are installed b) A tap is made through the valve into the line

4) The cutter is withdrawn after each tap, the valve is closed, and the tapping machine is removed.

5) The bypass line is installed, and the bypass valves are opened. 6) The seals of the stopple plugging machines should be inspected for defects

before installing the machines. The outside diameter of the sealing element must be correct for the inside diameter of the line to be hot tapped.

7) Stopple plugging machines are mounted on stopple fittings, and the plugging heads are lowered into sealing position.

8) The isolated section is vented, drained, and purged with an inert gas during cutting operations to remove this section.

9) The new pipe section is then welded to the line under continuous purge. a) The pressure is equalized. b) The plugging heads are retracted. c) The valves at the stopple connections are closed. d) The plugging machines are removed.

10) The bypass valves are closed, and the bypass line is removed. 11) Lock-O-Ring or approved equivalent plugs are installed in the stopple and

bypass fittings with a tapping machine. 12) All equipment is then removed, the valves are recovered, and blind flanges are

installed at stopple and bypass fittings.

Figure 2: Hot Tap Application Involving the Removal of a Section of Pipe



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SECTION TO BE REPLACED

STOPPLE

CONNECTIONSTEP 1 STOPPLE

CONNECTION

TEMPORARY

BYPASS CONNECTION

TEMPORART BYPASS

LINE STOPPLE

See Paragraph

5.5 for Stopple.

LINE STOPPLE

STEP 2

1. Remove bypass and install Lock-O-Ring plug.

2. Remove valve and install blind.

1. Remove bypass and install Lock-O-Ring plug.


NEW SECTION TO PIPE

STEP 3

1. Remove stopple and install Lock-O-Ring plug.


1. Remove stopple and install Lock-O-Ring plug.


TEMPORARY

BYPASS CONNECTION

A procedure such as shown above should be in place that will provide guidance for the safe design, material and equipment selection, installation, welding, testing, and removal to allow for replacing or removing a pipe section to permit work on the pipe section without interrupting flow (refer to Figure 2 above). A couple of related notes: 1) The bypass may be smaller than line size and a flow calculation can be made

to determine the minimum permissible size. 2) This method is usually limited to lines operating at temperatures not exceeding

82C (180F) because of the elastomeric sealing element of the stopple.

2.10.3.1. Hot Tap Connections Hot tap connections for piping additions for gas pipelines are designed in accordance with ASME B31.8 to accommodate the loads exerted by the new piping, including pipe movement.



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Hot tap connections and reinforcing pads (if required) should be no less than 75 mm (3 in.) from a welded seam (weld-toe to weld-toe). Hot tap connections should be at 90 degrees to the pipe, except 45 degree connections may be made into flare lines provided the following is true: 1) Design calculations are made for the connection to determine the extent

of reinforcement needed 2) The weights of the valve and tapping assembly are considered

2.10.3.2. Fitting Types

1) The acceptable types of hot tap fittings include both the weld-on type and bolt-on (mechanical) type. The weld-on type should be used, except for lines where welding is not permitted or on lines requiring PWHT. The mechanical type is considered temporary and if used, should be replaced at the next planned shutdown.

2) The mechanical type consists of a split-sleeve bolted around the pipe. Packing and gaskets suitable for the temperature and fluid service are required.

3) The weld-on type fittings consist of the full encirclement split-tee type. However, full encirclement types may also be used.

4) Full encirclement split tees, available from companies such as T.D. Williamson and IPSCO (International Piping Services Company), are required for full size hot taps and line stopple connections. This type of fitting is also recommended for one line size reducing taps.

5) Pipe-to-pipe reinforced (or unreinforced) connections and branch outlet fittings (O-lets) are preferred in steam and corrosive services. Full size connections are not recommended. If process conditions require a full size connection, the fitting should be replaced at the next planned shutdown.

2.10.3.3. Cutter Considerations

It is necessary to ascertain that the nozzle length plus the isolating valve length and thicknesses of the gaskets do not exceed the maximum travel of the cutter. The cutter size is specified so as to: 1) Avoid interference with the weld areas and the inside diameter of the

hot tap connection 2) Minimize the inside "lip," which may cause excessive turbulence near

the piping/storage tank-to-nozzle junction area

2.10.3.4. Other Considerations Other considerations include: 1) Potential problems with metal cuttings contaminating the product stream

should be considered. 2) When tapping a line, the preferred location is on top of the pipe, so that

metal cuttings will fall into the pipe and be washed away. 3) Avoid hot tapping upstream of control valves, instruments, and rotating

equipment unless filters or traps protect such equipment.



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4) Verify that the tapping machine (including packing and elastomers) will not be affected adversely by the fluid in the pipe.

2.10.3.5. Block Valve A full port gate or ball valve should be used as a block valve for the tapping machine. 1) The valve should be of adequate pressure rating for the intended

service and should be shop pressure tested (shell) and leak tested (seat/closure) prior to the installation. The valve pressure/ temperature rating should not be less than that of the existing piping system.

2) When the valve is to be left in place after completion of the hot tap, the following should be suitable for the intended service, pressure, and temperature: a) Valve body b) Trim c) Packing materials

2.10.3.6. Minimum Wall Thickness

It is required to inspect and test the condition of the piping prior to hot tapping. By ultrasonic testing, it is ensured that the pipe is free from laminations and that the thickness is adequate for safe welding. The minimum thickness depends upon the following: 1) The material being welded 2) The operating temperature and pressure during welding 3) The welding procedure 4) The product inside the pipe

Generally, the thickness should be no less than 5 mm (0.20 in.) and at least the thickness calculated for the hot and corroded condition.



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3.0 Assessments on Indexing and Ranges The following sections contain an assessment of the indexing criteria used by CREG as well as an analysis and opinion on the ranges established by CREG to collect uncertainties on valuation which are not covered by the multipliers. Further, an analysis and opinion on the proportion (i.e. 60%) of the new value acknowledged by CREG pertaining to the period when an asset meets the regulatory term of 20 years and continues being in operation for 20 more years is contained in Section 3.5. With the understanding that the asset was built according to required standards and taking into consideration that the operator performed proper maintenance. It was also considered that the compensation methodology for the transportation activity is incentives-based.

3.1. Assessment of Cost of Connection Multipliers The connection installation details are contained in Section 2.10. The same basic equipment and materials are used regardless of the pipe size, chiefly these are: fittings, ball valves, check valves, stopples, pipe, reinforcing saddles, coating materials, and flanges. All of these components are pipeline diameter specific. As can be seen in Appendix E, Variables 10a through 10d, the connection costs are relatively linear across pipeline diameters. Connection costs are well suited to interpolation.

3.2. Assessment of Topography Multipliers It is the opinion of the Author that additional categories of topography be included. Gradation of slopes does have a significant impact on pipeline construction and should be defined in finer increments. Except in exceptional instances, extreme topography can be significantly minimized by suitable route selection to avoid extreme areas whenever possible. While CREG’s methodology for calculating the topography impacts is quite good, the Author has provided a distinct breakdown that will provide some cross checking with CREG’s methodology with the following ranges:

0% - 5% (this is the type of terrain considered in the Base Case)

5% - 10%

10% - 15%

15% - 20%

20% - 25%

25%+ Multiplier breakdowns are shown in Appendices F1 through F6. As can be seen in Appendices F, topography tends to be linear and able to be interpolated across pipeline diameters.



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Also note that multipliers do not vary a great degree across diameters primarily due to the fact that while extreme terrain does impact pipe installation production to a degree, the main cost impact is for the ROW and clean-up crews. The approach taken by CREG for the quantification of varying degrees of terrain difficulty is a solid approach and does allow for multiple terrain factors within a single pipeline, much more so than a normal pipeline cost estimator would develop. In the Author’s opinion, the uncertainties are reasonably captured in the equations developed by CREG.

3.3. Assessment of Indexing Methodology and Criteria Used by CREG The Author has reviewed CREG’s methodology as described in Section 1.3.1.1 of the Tender documents. CREG’s methodology for indexing pipeline costs by using a base cost and multipliers for various Variables is a solid approach to estimating differing sizes, lengths, and route challenges. As stated, CREG’s methodology for estimating various topography impacts is an excellent tool. Apart from actually estimating each individual pipeline scenario, this approach is the best the Author has assessed. Utilizing a mix of known pipeline construction costs as well as some estimated costs, cost multipliers, and inflation indexes, the result is an accurate reflection of future pipeline construction costs. The Author provides the following suggestions, recommendations, and information to be considered or make some minor modifications of the methodology:

1. A caution needs to added regarding the use of double jointing. A determination must be made to define if double jointing is feasible. The following are the basic criteria:

a. Terrain. Difficult terrain makes the use of double jointing problematic due to the logistical issues of handling 24 meter lengths of pipe.

b. Length, Diameter, and Wall Thickness. As pipelines grow in length, diameter, and wall thickness, double jointing tends to be more economically attractive.

c. Availability of double jointing racks. Depending on the contractors chosen, they may or may not have access to a suitable double joint rack. If not, it may be cost prohibitive to secure the use of a double jointing rack from another company, typically a competitor.

2. The Author provides Appendix G that shows some historical comparisons between estimated costs versus actual costs of pipelines constructed. This information is from Oil & Gas Journal’s data base of pipeline costs.

The Author believes the cost multipliers contained in Appendix F and G provide a sufficiently broad range of multipliers across diameters in order to interpolate for any pipe diameter that may be encountered.



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As can be seen by the selected graphs in Appendix H, the cost multiplier curves are either linear or follow a predictable path and, in the Author’s opinion are well within the +/- 5% that would indicate a very close cost estimate. The 10km case uncovers an anomaly in that lengths less than 10 kms, those in the 3, 4, 5 km range can be performed with less equipment and personnel and done so in what is commonly referred to as “poor-boy” approach, where production is not critical or may not be achievable with the resources available. Once pipeline lengths get to the 10km and above range, pipeline contractors typically “gear up” more so they can increase production. The additional costs of equipment and personnel is factored in, but there is less distance to spread those costs. The Author wants to point out that every pipeline is different, while they follow some typical trends, it is impossible to say precisely what a contractor’s execution strategy is going to be. There is no “magical” length at which all contractors follow the same course. What the Author has purposed to do is include cost factors with the most common approaches to pipeline construction. That is not to say contractors will always follow what the norm is. And on smaller diameters and/or shorter lengths of pipe, the predictability of contractors becomes much more unsure. That is due to the fact that these cases are more suitable to small contractors who do not have the resources of larger contractors and often take a more bespoke approach to execution approaches and costs. As it is impossible to guess how small contractors will perform, the Author has assumed an approach more toward how a larger contractor may approach the work. Predictable cost models such as CREG’s can be developed and they can be fine-tuned to a reasonable degree of accuracy. However, in smaller diameters and/or shorter lengths, the definition of “reasonable” becomes much harder to define. See Section 3.10 for more information.

3.4. Assessment and Opinion of Variables and Uncertainties Additional Variables to Consider CREG have captured the vast majority of the Variables that impact construction costs. The Author has identified or agreed the following that should be modified, included, or added:

Fuel costs (CREG request per Section 3.1l of the Tender documents) No other Variables, other than those already considered by CREG were identified by the Author has having a potentially significant cost impact to pipeline construction costs. Uncertainties Not Covered by Multipliers When pipeline projects are costed, whether it is by oil and gas operating companies or construction contractors; both entities seek to identify as many of the known and quantifiable risks as possible and assign costs to those. Understanding from previous experience that there will be some issues that arise that were not predicted, a



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contingency factor is utilized to cover those un-foreseen risks that do arise on every project. Contingency and allowances to a certain degree are the only methods known to the Author to cover project and construction uncertainties. Contingency is added to more closely estimate the final cost of the work. In contrast to allowances, contingency covers largely unknown and undeveloped scope, and minor variations or fluctuations in the marketplace. The unknown or undeveloped scope is a consequence of the level of engineering and design that has been done. Very early in a project, very little engineering may be complete and there may be a significant number of items contributing to the final cost that have not yet been identified. As engineering and designs mature, the amount and impact the “unidentified” items is reduced. The challenge is setting the contingency in accord with the risks posed by the risks and at a level to afford an equal chance of overrunning or under-running the total capital cost estimate, which is considered P50. Contingency should account for:

Risks that an estimator reasonably judges may occur on a project such as design changes (design evolution), minor variations in material and equipment prices, and normal execution-related issues such as material shipping delays, rework, and other inefficiencies.

Contingency should not account for:

Unanticipated and unforeseeable events that are beyond an estimator’s capability to predict reasonably including situations like unusually inclement weather, civil unrest, hyperinflation, unexpectedly large currency fluctuations, and most importantly, discretionary changes to the project objectives.

For economic evaluations, it is important to identify and recognize the total cost uncertainty, regardless if the risks considered “fit” the definition of contingency or not. When it is appropriate to include risks related to weather, civil unrest, or other factors not included in contingency, the additional risks should be included as project reserves. The distinction between contingency and reserves may be important for discussions with construction contractors, who may not be aware of provisions made for reserves, but for the economic evaluation, the total cost expectations and uncertainty is what is important. There are several methods for determining the amount of contingency needed, each with advantages and disadvantages. These include estimator judgment, percentages based upon the level of engineering detail and Class of estimate, Monte Carlo analysis, or a parametric statistical approach.

Based on past and current practices of EPC Contractors and Owner companies, for standard projects that are not complex, will each place a 10% contingency on the work scope. This is due to the fact that at the time of construction start, most of the unknowns have been identified and quantified. See Section 4.1 for Contingency used in the costing for this Report.



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Owner companies, in addition to Contingency also typically place Allowances on their overall costs. Allowances are included to address risks in known areas or simply known unknowns. For example, knowing that wastage and scrap occur in pipe installation, an estimator includes an allowance of additional piping materials in the estimate over and above the exact distance to be piped.

Experience has shown that allowances are necessary and expected to be fully spent. Typical allowances for pipeline projects include the following:

Allowance Type Estimate Cost Element(s) % Allowance Design WBS Activities 5%

Material Take-Off (MTO) WBS Activities 5%

Waste and Trim WBS Activities 2%

Weather/Work Stoppage WBS Activities 10%

Routing WBS Activities 2%

Underground WBS Activities 5%

A caution on Allowances for this Report - allowances will impact the overall project from the Owner perspective, but will not impact the direct pipeline construction activities and costs.

3.5. Discussion on Interpolation of Variables Across Pipeline Diameters In the Authors opinion, pipeline diameter changes along similar lengths; for example interpolating the costs of 50 kms of 28” by using a cost graph range for 50 kms of 20”, 24”, 30”, and 36”). The actual construction costs for 28” would fall accurately within the cost graph.

3.6. Economy of Scale for Pipeline Diameter Variations Pipeline diameter cost variations are for the most part linear. The caveat is the transition from a 10” pipe to a 12” pipeline. The primary differences that make the 10”/12” comparison slightly skewed stems from the following factors:

A 10” pipeline does not require pneumatically driven inside line up clamps. Mechanical external clamps are used. 12” pipelines do use internal line up clamps. The inside line up clamps require more expensive to own/operate and require additional personnel; the upside is it allows for higher production.

A 10” pipeline may or may not use two welders on the root pass; a 12” pipeline requires two welders. Subsequent passes on the 12” require two welders (one welder per side). With the additional welder comes additional support, i.e. helper, welding machine, welding supplies.

Depending on the amount of pipe bending required, a 10” pipeline may or may not use a hydraulic bending machine; a 12” pipeline must use a hydraulic bending machine, with a mandrel and bending dies. The hydraulic bending machine requires additional equipment and personnel.



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An added anomaly that must be factored is the fact that smaller diameter pipelines tend to be tendered more competitively as there are more contractors with the resources to tender, therefore the smaller the diameter and the shorter the length, the more competitive the bidding becomes. Lastly, smaller diameter, shorter length pipelines allow for more crews to multi-task and therefore certain crews, for example bending and lowering-in among others can be combined to allow for a more competitive tender to be provided. These market force factors have been reflected in Appendix B.

3.7. Discussion on Interpolation of Pipeline Diameters and Lengths Developing economies of scale for pipeline length does have some complications when considering it on a theoretical level. The issue arises in the transition from lower length to longer length pipelines (such as from 20km to 50+ km) and at what point man-camps will be required. Man-camps have a large cost impact on the overall pipeline costs and must be justified economically in order to substantiate their use. Making the decision to utilize camps is complicated and includes the following factors:

Driving time. This may be more than simply distance if it is remote and mountainous or with poor logistics infrastructure. The rule of thumb is you will want the maximum driving distance to be 1 hour per day.

The amount of existing infrastructure along the pipeline route that could house personnel, such as villages and towns in proximity to the pipeline.

The number of personnel needing housing is a consideration; the longer the pipeline length and the larger the pipeline diameter the more personnel required. The fewer personnel needed for pipeline construction makes it easier to secure alternative housing in nearby towns.

All pipelines less than 50kms were costed without man-camps being utilized. As pipelines grow in both length and diameter, the fewer companies that are available with the resources and equipment to install them and therefore bid costs tend to increase on a cost/meter basis. The Author has purposed to reflect these market force anomalies in the costs estimates contained in Appendix B. The costs for 100-meter installation of all pipe diameters was developed based on the philosophy of an operating company utilizing small, existing maintenance and service contracts. A small crew with supervision, labor, equipment, and materials was developed. Labor and equipment costs commensurate with a maintenance and service agreement were used to determine final installed cost of each 100-meter pipeline section installed.



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Pipeline length by diameter is subject to interpolation to a reasonably accurate degree. Although pipelines in 10km length do behave a little differently than the shorter or the longer lengths in each diameter, they do so along a predictable path. The primary reason is pipelines with length in the 3, 4, 5 km range can be performed with less equipment and personnel and done so in what is commonly referred to as “poor-boy” approach, where production is not critical or may not be achievable with the resources available. Once pipeline lengths get to the 10km and above range, pipeline contractors typically “gear up” more so they can increase production. The additional costs of equipment and personnel is included, but there is less distance in 10 kms to spread those costs. The Author wants to point out that every pipeline is different, while they follow some typical trends, it is impossible to say precisely what a contractor’s execution strategy is going to be. What the Author has purposed to do is include cost factors with the most common approaches to pipeline construction. That is not to say contractors will always follow what the norm is. And on smaller diameters and/or shorter lengths of pipe, the predictability of contractors becomes much more unsure. That is because these cases are more suitable to small contractors who do not have the resources of larger contractors and often take a more bespoke approach to execution approaches and costs. As it is impossible to guess how small contractors will perform, the Author has assumed an approach more toward how a larger contractor may approach the work. Predictable cost models such as CREG’s can be developed and they can be fine-tuned to a reasonable degree of accuracy. However, in smaller diameters and/or shorter lengths, estimating these costs becomes more difficult. Additionally, as pointed out, the Author has chosen, in his opinion where to make the distinction between a major spread and a “poor-boy” spread which is 10kms. In actuality the decision depends on contractors and for some it may be 5kms, others it could be 20kms. Much of it also depends on the schedule laid out by the client – if it is an aggressive schedule, more resources will be used; if the schedule is “open”, less resources can be used. In summary, if 5 contractors were asked to develop cost estimates, they would all differ, experience tells the Author that the differences between 5 contractors developing cost estimates for the exact same project can differ as much as 20%.

3.8. Economy of Scale for Pipeline Length Variations See discussion in Section 3.7. The narrative applies to economy of scale for pipeline lengths.



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3.9. Discussion on Cost Estimates, Tendering Overview and Pipeline Values The Author would like to further explain the nuances of the cost estimating approach taken in this Report. The methodology approach used by CREG is unique to a regulatory agency and is a useful tool in applying tariff rates to the gas pipeline infrastructure. However, this approach is not utilized by oil and gas operating companies nor by pipeline construction contractors. In order to arrive at an estimated value of a pipeline, there are two basic approaches:

1. Data Base Approach. Utilize existing data bases of information, such as Oil & Gas Journal and develop value matrices based on the data available and interpolation of that data for values not specifically addressed in the cost data base. The primary problem with this approach is the data bases are broad in nature and provide only a basic level of information for a limited number of pipeline diameters and lengths. Much of the costs that do not easily fit into the categories of “Labor” and Materials” and is therefore placed into a “Miscellaneous” category. Most projects are different in many ways and have different problems and issues, including technical, commercial, contractual, regional, corporate, contractors, etc. Therefore, it is impossible to fully achieve an accurate breakdown of the “Miscellaneous” category. What typically happens is the data bases do not have a broad listing of all pipeline diameters and lengths and therefore interpolation is used extensively and nice, uniform graphs are produced based on the costs interpolated.

2. Direct, Individual Estimating Approach. Oil and Gas operating companies and pipeline construction contractors use the direct estimating approach for each project. In this method, they identify all of the major costs, capture minor costs by historical information or known percentages. In this approach, each estimate is unique and all major costs for the particular project are identified.

This is the Author’s approach. The problem comes in that as each estimate is unique, when looking at an individual project in terms of a data base of costs, there can be anomalies. When operating companies go out for a pipeline tender, they will often tender to 4-6 contractors. Never will the cost estimates be the same.



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Each are unique and it is not uncommon to have a +/- 10% spread in the costs. Each contractor will look at the same scope of work, but each will approach it in their unique way and therefore on the exact scope of work, cost estimates will vary, sometimes considerably. The Author’s approach is to develop each cost estimate individually and not utilize data bases to develop costs. The Author acknowledges that sometimes individual cost estimates do not correspond to the data base of costs.

The question remains, what is the real cost of each pipeline system? It is not an easy question to answer. By combining data bases and cost estimates, one can drill down to a reasonably accurate range of values for a pipeline system. It is not possible to have a single cost per meter or cost per diameter-meter to reflect all pipelines in that diameter/length range but only to get to a reasonable estimate of the pipeline system costs. In the Author’s opinion, a +/-5% is the best outcome that can be achieved. Each individual estimate is based on the individual estimator’s unique opinion and experience. Oil and Gas companies consider +/- 20% being accurate enough for making project development decisions. The only way to determine the true cost of each pipeline system is the actual final cost.

3.10. Assessment of Proportion of New Value The typical life expectancy of a pipeline system built per applicable design codes and maintained properly is approximately 40 years. The Author does not have access to the detailed analysis that CREG used to determine the 60% new value once the asset has reached it’s ½ life (or 20 years). Tariff principles typically allow a choice of three basic methodologies for determining how pipeline systems are treated for discounting:

Replacement cost of asset. Where the total revenue is set to recover costs with those costs to be calculated on the basis of a return (rate of return) on the value of the assets that form the pipeline system (capital base), depreciation on the capital base (depreciation) and the operating, maintenance and other non-capital costs (non-capital costs) incurred in operating the pipeline system.

Internal rate of return (IRR). Where the total revenue is set to provide an acceptable IRR for the pipeline system on the basis of forecast costs and sales.

Net present value (NPV). Where the total revenue is set to deliver a NPV for the pipeline system (on the basis of forecast costs and sales) equal to zero, using an acceptable discount rate.



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The Author is moderately familiar with the basic steps in how CREG determines asset values which correspond to the replacement cost of asset method, and includes:

1. Determine the capital expenditures required to put the asset into service. The methodology that CREG has developed, as stated in Section 3.3, is a very solid approach.

2. Determine operating costs of the asset over the useful life 3. Determine a depreciations method (typically straight line depreciation is

used) The replacement cost of asset method is based on the current year cost of rebuilding the same diameter pipeline with the same length, terrain, vegetation, crossing, connections, etc. as the end of life pipeline contains and then discounting it based on a particular point in its life cycle. The replacement cost is then depreciated to arrive at a discount that reflects the existing pipeline system has generated revenues which provides pipeline owner with a return of capital in addition to a commercial return on capital. This method also recognizes that the remaining life of the pipeline system is less than that of a new pipeline replacement system and should therefore have an appropriately discounted valuation. The question posed by CREG – is the 60% for a 20 year life of the pipeline system a reasonable amount of discount for the pipeline system replacement cost estimate? The Author does not have access to CREG’s methods for discounting to reach the asset’s value after 20 years, but a typical approach of determining a pipeline asset value is to discount the pipeline system at a rate of 2.5% per year of life or a total of 50% of the cost of new pipeline system construction in today's market. The goal is to assign a value to the initial pipeline system capital base that is a fair value to both the pipeline operator and CREG. For the initial pipeline system capital base value of the existing pipeline system to be fair to both the operator and CREG, it needs to reflect a discounted value based on the historic depreciation which has been recovered by the owners. The Author does not have enough information to argue that 2% per year of life or a total of 60% after 20 years of the cost of new pipeline construction in today's market is unrealistic. However, considering the pipeline valuation is considered on an incentive basis, the 60% discount used by CREG is a reasonable approach and does provide the operating companies with an incentive.



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4.0 Construction Cost Estimate Basis The general assumptions and common basis of the cost estimates that were used to develop the spreadsheets in Appendix B and Appendix D are shown below.

4.1. General The estimate is based on first quarter 2014 cost. Major material costs normally provided by a construction contractor are based on current quotations or historical cost data with freight allowance to construction site. Line pipe costs as well as other major permanent materials are included. All pipe was assumed to be purchased and coated from international pipe mills. Pipe in diameters greater than 10.500” was assumed to be X65 and pipe 10.500” and under was assumed to be X60. Pipe cost per ton were based on current pricing indices10 from pipe mills throughout Europe and the Middle East, including:

US

Italy

Turkey

India

Spain The indices are represented in the chart below.

The above chart is are shown as Ex-works and therefore does not include VAT and taxes. $800/ton was used as a basis. 20% VAT was included to bring the total cost per

10 Indices were utilized from a paid subscription from SteelOrbis, who is a worldwide steel tracking company who provides current and

historical data on steel prices, including line pipe.



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ton used in the estimates at $960/ton. Customs, taxes, and duties for importation into Colombia are covered in the estimate, but not included in the per ton pipe costs. Material and labor quantities estimated for the project were determined by using a typical terrain that consists of very gentle terrain with no rock blasting. A very minor amount of vegetation clearing was included. Labor rates are considered “generic” and are representative of industry values typical for expatriate, national, and other country nationals (OCN’s) on international pipeline construction projects. The estimate is based on the pipeline spread working 7 days a week, 10 hours per day. All support costs have been included based on historical project costs and include:

Permanent Materials & Procurement

Permanent Materials Freight & Handling

Engineering

Communications (SCADA & Telecomms)

Client Costs (Includes PMT & CMT)

Parent Co. Costs

Allowances

Contingency of 10% overall

AFUDC The Contractor factors & costs included in the estimates consist of:

Profit of 15%

10% completion bonus for workers

Joint length of 38’ on average

15% allotted to weather delays

Fuel at $4.50/gallon (this is for a combination of gasoline & diesel)

Contractor supply of: o Joint coating materials o Piping 2” & under o Civil materials, i.e. rebar, forms, concrete

Company supply of all other permanent materials, including valves, actuators, and line pipe.

Standard drying costs to a -25C dew point

4.2. Pipeline Base Case The proposed pipeline is comprised of 50 kilometers of 4.500” x 0.083” wall thickness, X-65 pipe11 installed in a generic international location.

11 4,500” does refer to the outside diameter (OD) as defined by API 5L. The internal diameter (ID) is: OD – wall thickness = ID. 4.500” pipe is commonly referred to as “4 inch” pipe as a shortened term. The same can be said for 6”, 8”, 10” and 12”. Above 12” pipe, per API 5L, the OD is even, for example the OD of “16 inch pipe” is 16.000”.



Assessments


The 4” and 8” pipelines were assumed to be done by National contractors. All other pipeline diameter assessments were assumed to be performed by large regional or international contractors and all pipelines considered the following basis. The pipeline was assumed to be designed according to ASME B31.8 for ANSI Class 600 at 1,200 PSI. The pipeline sizes selected, along with the calculated wall thicknesses for the various class locations are contained in Appendix C. These wall thicknesses are included in Variables for class locations and include construction-only costs for pipe handling, welding time, and welding consumables. Line pipe was assumed to be coated with 14-16 mils FBE. Pipe was assumed to be delivered to a centrally located pipe laydown area by Company. Costs for load out from that pipe yard, haul, and string are included in the estimate. The estimate includes the installation of two mainline valves (MLV’s) and launcher/receivers at each end. Very light brush was assumed, but no medium or heavy trees/vegetation were considered in the Base Case. Pipeline installation costs were developed using crew build-ups for a typical spread, which includes mobilization, equipment, expendable materials, profit and overhead. Environmental items such as dust control, silt fencing, and erosion control fabric are also included in the construction cost. Costs for environmental monitoring has been included, however, no costs for environmental baseline preparation or right-of-way easement costs are included in this estimate. A basic cathodic protection (CP) system was assumed with contractor installing only, all design & materials were assumed to be provided by Company. Installation of Company-provided pipeline markers is included. Line pack costs are not included in the estimates. Construction costs are based on a typical 30-meter wide construction right-of-way.



Assessments


Appendix A – Variable Details for Report

The following variables were chosen by CREG as potential changeable conditions and have been requested to be assessed as to each of their respective impacts on gas pipeline construction costs. Each of the Variables has been integrated into the Base Case in increments as noted in Appendix B in order to assess the overall cost impacts that each Variable will have in comparison to the global base case pipeline construction costs. Variable 1 Soil Type: For the basis of this Report, there have been three (3) each Soil sub-Variables developed:

a. Clay b. Sandy soil c. Rocky

Variable 2 Vegetation: For the basis of this Report, there have been eight (8) each Vegetation sub-Variables developed:

a. Tundra b. Temperate broadleaf forest c. Subtropical rainforest d. Arid desert e. Dry steppe f. Savanna g. Tropical rainforest h. Alpine tundra

Variable 3 Water Table: For the basis of this Report, there have been three (3) each Water Table Variables developed:

a. Typical water table requiring dam & pump type methodology b. High water table that requires dam & pump as well as a 500 meter section that

requires well points c. Cofferdam

Variable 4 Class Location: For the basis of this Report, there have been four (4) Variable classes defined by ASME B31.8 based on an MAOP of 1,200 PSI developed:

a. Class 1 b. Class II c. Class III d. Class IV

Variable 5 Crossing Type:



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For the basis of this Report, there have been two (2) each Water crossing Variables developed: a. Wet crossing, consisting of a standard excavation & install crossing b. Horizontal Directional Drill (HDD) c. Aerial crossing

Variable 6

Seismic crossing – a seismic crossing of 20 meters in impacted length was assumed with the construction details contained in Section 2.6. Variable 7 Cultivated Land – a pipeline crossing land that is considered as cultivated which assumes some mitigations as outlined in Section 2.7. Variable 8 Extreme terrain – for this Report, there are 5 types of extreme terrain considered:

a. Terrain of 5%-10% b. Terrain of 10%-15% c. Terrain of 15-20% d. Terrain of 20%-25% e. Terrain more than 25%

Variable 9 Double Joints – for this Report the entire length was assumed to be conducive to double jointing Variable 10

Connections – for this Report, it was assumed there would be two each connections, one at each end of the pipeline that would include:

• Hot tap, stopple, by-pass and tie-in to the existing service

• Hot tap, stopple and tie-in to the existing service

• Hot tap and tie-in to the existing service

• Cold cut and tie-in to the existing service Variable 11

Pipeline Lengths. Pipeline length variations were captured in Appendix B Variable 11a

Congested pipe lay Variable 12 Pipeline Diameter. Pipeline diameter variations were captured in Appendix B



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Appendix B – Base Case and Additional Diameter Costs per 100 meters; 10, 20, 50, 100, and 200 Kilometers of Pipeline

Appendix B – Base Costs for 100 kms of PipelineComisión de Regulación de Energía y Gas (CREG) Greg Lamberson

Description Total Cost Total Cost/Km Total Cost/Dia-

Inch

Total Cost/Dia-

in/Meter

2-inch (2.375)

Variable Case-100 meters 40,131$ 401,310$ 16,897$ 168.97$

Variable Case-1 km 307,000$ 307,000$ 129,263$ 129.26$

Variable Case-2 kms 472,000$ 236,000$ 198,737$ 99.37$



Variable Case-10 kms 1,133,000$ 113,300$ 477,053$ 47.71$



4-inch (4.500) *






Base Case-50 kms 8,009,000$ 160,180$ 1,779,778$ 35.60$

Variable Case-100 kms 10,705,000$ 107,050$ 2,378,889$ 23.79$


6-inch (6.625)









8-inch (8.625)









10-inch (10.750)







Expert Report: Pipeline Variable Assessments; NIT-900-034.993-1

Base Costs per 50 Kilometers of 4-Inch Pipeline Built in Good Conditions



Inch

Total Cost/Dia-

in/Meter





12-inch (12.750)









14-inch (14.000)

Variable Case-100 meters 88,748$ 887,480$ 6,339.14$ 63.39$

Variable Case-1 kms 594,000$ 594,000$ 42,428.57$ 42.43$

Variable Case-5 kms 2,320,000$ 464,000$ 165,714.29$ 33.14$



Variable Case-50 kms 18,537,000$ 370,740$ 1,324,071.43$ 26.48$



16-inch (16.000)









18-inch (18.000)

Variable Case-100 meters 103,799$ 1,037,990$ 5,767$ 57.67$








20-inch (20.000)







Inch

Total Cost/Dia-

in/Meter







24-inch (24.000)









30-inch (30.000)









36-inch (36.000)



Variable Case-5 kms 5,107,000$ 1,021,400$ 141,861$ 28.37$






The additional diameters and lengths were evaluated directly in order to provide a basis for developing economy of scale factors.

All other diameters and lengths used a similar estimate basis as the 4" Case, i.e. Class I location, good terrain, no major obstacles or construction issues.

Appendix C – Design Pressure for Wall Thickness Calculations


0.72 0.60 0.50 0.40 D/t

2.375 0.083 65,000 2.03 3,271 2,725 2,271 1,817 28.6

2.375 0.083 65,000 2.03 3,271 2,725 2,271 1,817 28.6

2.375 0.083 65,000 2.03 3,271 2,725 2,271 1,817 28.6

2.375 0.083 65,000 2.03 3,271 2,725 2,271 1,817 28.6

4.500 0.083 65,000 3.92 1,726 1,438 1,198 959 54.2

4.500 0.083 65,000 3.92 1,726 1,438 1,198 959 54.2

4.500 0.125 65,000 5.85 2,600 2,166 1,805 1,444 36.0

4.500 0.125 65,000 5.85 2,600 2,166 1,805 1,444 36.0

6.625 0.109 65,000 7.59 1,539 1,283 1,069 855 60.8

6.625 0.109 65,000 7.59 1,539 1,283 1,069 855 60.8

6.625 0.125 65,000 8.69 1,766 1,471 1,226 981 53.0

6.625 0.172 65,000 11.87 2,430 2,025 1,687 1,350 38.5

8.625 0.125 65,000 11.36 1,356 1,130 942 753 69.0

8.625 0.156 65,000 14.12 1,692 1,410 1,175 940 55.3

8.625 0.188 65,000 16.96 2,040 1,700 1,416 1,133 45.9

8.625 0.203 65,000 18.28 2,202 1,835 1,529 1,223 42.5

10.750 0.156 65,000 17.67 1,358 1,131 943 754 68.9

10.750 0.188 65,000 21.23 1,636 1,364 1,136 909 57.2

10.750 0.203 65,000 22.89 1,767 1,472 1,227 981 53.0

10.750 0.250 65,000 28.06 2,176 1,813 1,511 1,209 43.0

12.750 0.172 65,000 23.13 1,262 1,052 876 701 74.1

12.750 0.203 65,000 27.23 1,490 1,241 1,034 827 62.8

12.750 0.250 65,000 33.41 1,835 1,529 1,274 1,019 51.0

12.750 0.312 65,000 41.48 2,290 1,908 1,590 1,272 40.9

14.000 0.188 65,000 27.76 1,256 1,047 872 698 74.5

14.000 0.219 65,000 32.26 1,464 1,220 1,016 813 63.9

14.000 0.281 65,000 41.21 1,878 1,565 1,304 1,043 49.8

14.000 0.344 65,000 50.22 2,299 1,916 1,597 1,277 40.7

16.000 0.219 65,000 36.95 1,281 1,067 889 711 73.1

16.000 0.250 65,000 42.09 1,462 1,218 1,015 812 64.0

16.000 0.312 65,000 52.32 1,825 1,521 1,267 1,014 51.3

16.000 0.375 65,000 62.64 2,193 1,828 1,523 1,218 42.7

18.000 0.250 65,000 47.44 1,300 1,083 902 722 72.0

18.000 0.281 65,000 53.23 1,461 1,217 1,014 811 64.1

18.000 0.344 65,000 64.93 1,788 1,490 1,242 993 52.3

18.000 0.438 65,000 82.23 2,277 1,898 1,581 1,265 41.1

20.000 0.281 65,000 59.23 1,315 1,095 913 730 71.2

20.000 0.312 65,000 65.66 1,460 1,216 1,014 811 64.1

20.000 0.375 65,000 78.67 1,755 1,462 1,218 975 53.3

20.000 0.469 65,000 97.92 2,194 1,829 1,524 1,219 42.6

24.000 0.312 65,000 79.01 1,216 1,014 845 676 76.9

24.000 0.375 65,000 94.71 1,462 1,218 1,015 812 64.0

24.000 0.469 65,000 117.98 1,829 1,524 1 ,270 1,016 51.2

24.000 0.562 65,000 140.81 2,191 1,826 1 ,522 1,217 42.7

30.000 0.406 65,000 128.44 1,266 1,055 879 703 73.9

30.000 0.469 65,000 148.06 1,463 1,219 1 ,016 812 64.0

30.000 0.562 65,000 176.86 1,753 1,461 1 ,217 974 53.4

30.000 0.750 65,000 234.51 2,340 1,950 1 ,625 1,300 40.0

36.000 0.469 65,000 178.14 1,219 1,016 846 677 76.8

36.000 0.562 65,000 212.90 1,461 1,217 1 ,014 811 64.1

36.000 0.688 65,000 259.71 1,788 1,490 1 ,242 993 52.3

36.000 0.875 65,000 328.55 2,275 1,895 1 ,579 1,263 41.1

Report 1502012-CREG-ICC-001 October 201469 of 95



MAOP @ DESIGN FACTOR

NOTE:

The wall thicknesses selected for each pipe diameter above adhere to the standard API 5L Pipe wall thickness guidelines meeting the minimum design

requirements of an ANSI Class 600 pipeline system.

1,200 psig Case

OD" WT" GRADE lb/ft



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Appendix D – Variable Impacts on Base Case Spreadsheet The following spreadsheet contains what the impacts of each of the variables shown in Appendix A will have on the base case.

Appendix D – Cost Delta Table for Variable Impacts


Description Total Cost Total Cost

Difference vs Base

Total

Cost/Km

Multiplier/Km

Versus Base

Case

Total

Cost/Dia-

in/Meter

Total Cost

Delta vs Base

Case in %

Incremental

Cost/Km

Incremental

Cost/Dia-

in/Meter 4-inch (4.500) x 50 kms w/5 Kms of Each Variable

1

Base Case 8,009,000$ -$ 160,180$ NA 35.60$ NA NA NA

Variable 1a-Clay Soil2 8,009,000$ -$ 160,180$ 1.000 35.60$ 0.00% -$ -$

Variable 1b-Sandy Soil 8,226,000$ 217,000$ 164,520$ 1.027 36.56$ 2.71% 4,340$ 0.96$

Variable 1c-Rocky Soil 8,562,000$ 553,000$ 171,240$ 1.069 38.05$ 6.90% 11,060$ 2.46$

Variable 2a-Tundra Vegetation3 8,842,000$ 833,000$ 176,840$ 1.104 39.30$ 10.40% 16,660$ 3.70$

Variable 2b-Temperate Broadleaf Forest Vegetation 8,210,000$ 201,000$ 164,200$ 1.025 36.49$ 2.51% 4,020$ 0.89$

Variable 2c-Subtropial Rainforest Vegetation 8,578,000$ 569,000$ 171,560$ 1.071 38.12$ 7.10% 11,380$ 2.53$

Variable 2d-Arid Desert Vegetation4 8,009,000$ -$ 160,180$ 1.000 35.60$ 0.00% -$ -$

Variable 2e-Dry Steppe Vegetation4 8,009,000$ -$ 160,180$ 1.000 35.60$ 0.00% -$ -$

Variable 2f-Savanna Vegetation4 8,050,000$ 41,000$ 161,000$ 1.005 35.78$ 0.51% 820$ 0.18$

Variable 2g-Tropical Rainforest Vegetation 8,947,000$ 938,000$ 178,940$ 1.117 39.76$ 11.71% 18,760$ 4.17$

Variable 2h-Alpine Tundra Vegetation3 8,338,000$ 329,000$ 166,760$ 1.041 37.06$ 4.11% 6,580$ 1.46$

Variable 3a-Water Table-Sumps & Ditches 8,514,000$ 505,000$ 170,280$ 1.063 37.84$ 6.31% 10,100$ 2.24$

Variable 3b-Water Table-Well Point System 8,762,000$ 753,000$ 175,240$ 1.094 38.94$ 9.40% 15,060$ 3.35$

Variable 3c-Water Table-Cofferdams 8,610,000$ 601,000$ 172,200$ 1.075 38.27$ 7.50% 12,020$ 2.67$

Variable 4a-10 km of Class I 5 8,009,000$ -$ 160,180$ 1.000 35.60$ 0.00% -$ -$

Variable 4b-10 km of Class II 6 8,009,000$ -$ 160,180$ 1.000 35.60$ 0.00% -$ -$

Variable 4c-10 km of Class III 8,186,000$ 177,000$ 163,720$ 1.022 36.38$ 2.21% 3,540$ 0.79$

Variable 4d-10 km of Class IV 7 8,186,000$ 177,000$ 163,720$ 1.022 36.38$ 2.21% 3,540$ 0.79$

Variable 5a-Wet Crossings (1 ea 45m crossing) 8,058,000$ 49,000$ 161,160$ 1.006 35.81$ 0.61% 980$ 0.22$

Variable 5b-HDD (1 ea 300m crossing) 8,770,000$ 761,000$ 175,400$ 1.095 38.98$ 9.50% 15,220$ 3.38$

Variable 5c-Aerial Crossing (1 ea 30m crossing) 8,066,000$ 57,000$ 161,320$ 1.007 35.85$ 0.71% 1,140$ 0.25$

Variable 6a-Seismic Crossing (1 ea 45m crossing) 8,146,000$ 137,000$ 162,920$ 1.017 36.20$ 1.71% 2,740$ 0.61$

Variable 7a-Cultivated land 8,130,000$ 121,000$ 162,600$ 1.015 36.13$ 1.51% 2,420$ 0.54$

Variable 8a-Terrain of 5%-10% (1 km) 8,130,000$ 121,000$ 162,600$ 1.015 36.13$ 1.51% 2,420$ 0.54$

Variable 8b-Terrain of 10%-15% (1 km) 8,226,000$ 217,000$ 164,520$ 1.027 36.56$ 2.71% 4,340$ 0.96$

Variable 8c-Terrain of 15%-20% (1 km) 8,322,000$ 313,000$ 166,440$ 1.039 36.99$ 3.91% 6,260$ 1.39$

Variable 8d-Terrain of 20%-25% (1 km) 8,458,000$ 449,000$ 169,160$ 1.056 37.59$ 5.61% 8,980$ 2.00$

Variable 8e-Terrain of 25%+ (1 km) 8,498,000$ 489,000$ 169,960$ 1.061 37.77$ 6.11% 9,780$ 2.17$

Variable 9a-Double Joints 8,082,000$ 73,000$ 161,640$ 1.009 35.92$ 0.91% 1,460$ 0.32$

Variable 10a-Connections (2 ea) Hot tap, stopple, by-pass 8 8,178,000$ 169,000$ 163,560$ 1.021 36.35$ 2.11% 3,380$ 0.75$

Variable 10b-Connections (2 ea) Hot tap, stopple, no by-pass 8,130,000$ 121,000$ 162,600$ 1.015 36.13$ 1.51% 2,420$ 0.54$

Variable 10c-Connections (2 ea) Hot tap 8,090,000$ 81,000$ 161,800$ 1.010 35.96$ 1.01% 1,620$ 0.36$

Variable 10d-Connections (2 ea) cold cut 8,018,000$ 9,000$ 160,360$ 1.001 35.64$ 0.11% 180$ 0.04$

Variable 11a-Congested area construction (5km) 8,474,000$ 465,000$ 169,480$ 1.058 37.66$ 5.81% 9,300$ 2.07$

Variable 13a-Fuel Costs ($1/gal or $0.26/liter change +/-) 8,298,000$ 289,000$ 165,960$ 1.036 36.88$ 3.61% 5,780$ 1.28$

NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item

2 Clay type soil was considered as the Base Case

3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report

for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included light, standard clearing; the type of clearing for desert and dry steppe is

slightly easier to perform but only by a very small margin.5 Class I location was considered as the base case.

6 For 4", Class II locations use the same wall thickness as Class I (see Appendix C) for calculations indicating the wall thicknesses and design pressures.

7 For 4", Class IV locations use the same wall thickness as Class III (see Appendix C) for calculations indicating the wall thicknesses and design pressures.

8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.





Assessments


Appendix E – Variable Impacts Across Diameters

Appendix E-1 – Cost Delta Table for Variable Impacts for 6-Inch



Difference vs Base Total Cost/Km

Multiplier/Km Versus Base Case

Total Cost/Dia-in/Meter

Total Cost Delta vs

Base Case in %

Incremental Cost/Km

Incremental Cost/Dia-in/Meter

6-inch (6.625) x 50 kms w/5 Kms of Each Variable 1




Variable 1c-Rocky Soil 10,773,000$ 696,000$ 215,460$ 1.069 32.52$ 6.91% 13,920$ 2.10$

Variable 2a-Tundra Vegetation3 11,136,000$ 1,059,000$ 222,720$ 1.105 33.62$ 10.51% 21,180$ 3.20$


Variable 2c-Subtropial Rainforest Vegetation 10,793,000$ 716,000$ 215,860$ 1.071 32.58$ 7.11% 14,320$ 2.16$



Variable 2f-Savanna Vegetation4 10,128,000$ 51,000$ 202,560$ 1.005 30.58$ 0.51% 1,020$ 0.15$

Variable 2g-Tropical Rainforest Vegetation 11,257,000$ 1,180,000$ 225,140$ 1.117 33.98$ 11.71% 23,600$ 3.56$



Variable 3b-Water Table-Well Point System 11,045,000$ 968,000$ 220,900$ 1.096 33.34$ 9.61% 19,360$ 2.92$

Variable 3c-Water Table-Cofferdams 10,864,000$ 787,000$ 217,280$ 1.078 32.80$ 7.81% 15,740$ 2.38$


Variable 4b-10 km of Class II 6 10,077,000$ -$ 201,540$ 1.000 30.42$ 0.00% -$ -$


Variable 4d-10 km of Class IV 10,360,000$ 283,000$ 207,200$ 1.028 31.28$ 2.81% 5,660$ 0.85$

Variable 5a-Wet Crossings (1 ea 45m crossing) 10,269,000$ 192,000$ 205,380$ 1.019 31.00$ 1.91% 3,840$ 0.58$

Variable 5b-HDD (1 ea 300m crossing) 11,105,000$ 1,028,000$ 222,100$ 1.102 33.52$ 10.20% 20,560$ 3.10$




Variable 8-Terrain - See Appendix F-1

Variable 9a-Double Joints 10,168,000$ 91,000$ 203,360$ 1.009 30.70$ 0.90% 1,820$ 0.27$





Variable 11a-Congested area construction (5km) 10,773,000$ 696,000$ 215,460$ 1.069 32.52$ 6.91% 13,920$ 2.10$

NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item2 Clay type soil was considered as the Base Case3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report

for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included very light, standard clearing; the type of clearing for desert and dry steppe is

slightly easier to perform but only by a very small margin.5 Class I location was considered as the base case.6 For Class II locations use the same wall thickness as Class I (see Appendix C) for calculations indicating the wall thicknesses and design pressures.8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.

Base Costs per 50 Kilometers of 6-Inch Pipeline Built in Good ConditionsExpert Report: Pipeline Variable Assessments; NIT-900-034.993-1





Multiplier/Km Versus Base

Case


Total Cost Delta vs Base

Case in %

Incremental Cost/Km






Variable 1c-Rocky Soil 16,120,000$ 1,055,000$ 322,400$ 1.070 25.79$ 7.00% 21,100$ 1.69$



Variable 2c-Subtropial Rainforest Vegetation 16,135,000$ 1,070,000$ 322,700$ 1.071 25.82$ 7.10% 21,400$ 1.71$







Variable 3b-Water Table-Well Point System 16,527,000$ 1,462,000$ 330,540$ 1.097 26.44$ 9.70% 29,240$ 2.34$

Variable 3c-Water Table-Cofferdams 16,286,000$ 1,221,000$ 325,720$ 1.081 26.06$ 8.10% 24,420$ 1.95$


Variable 4b-10 km of Class II 15,186,000$ 121,000$ 303,720$ 1.008 24.30$ 0.80% 2,420$ 0.19$



Variable 5a-Wet Crossings (1 ea 45m crossing) 15,593,000$ 528,000$ 311,860$ 1.035 24.95$ 3.50% 10,560$ 0.84$






Variable 9a-Double Joints 14,614,000$ (451,000)$ 292,280$ 0.970 23.38$ -2.99% (9,020)$ (0.72)$





Variable 11a-Congested area construction (5km) 16,934,000$ 1,869,000$ 338,680$ 1.124 27.09$ 12.41% 37,380$ 2.99$

NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item2 Clay type soil was considered as the Base Case3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report

for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included very light, standard clearing; the type of clearing for desert and dry steppe is

slightly easier to perform but only by a very small margin.5 Class I location was considered as the base case.8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.









Case in %

Incremental Cost/Km















Variable 3a-Water Table-Sumps & Ditches 25,116,000$ 1,533,000$ 502,320$ 1.065 27.91$ 6.50% 30,660$ 1.70$







Variable 5a-Wet Crossings (1 ea 45m crossing) 25,281,000$ 1,698,000$ 505,620$ 1.072 28.09$ 7.20% 33,960$ 1.89$



Variable 6a-Seismic Crossing (1 ea 45m crossing) 24,692,000$ 1,109,000$ 493,840$ 1.047 27.44$ 4.70% 22,180$ 1.23$



Variable 9a-Double Joints 22,357,000$ (1,226,000)$ 447,140$ 0.948 24.84$ -5.20% (24,520)$ (1.36)$

Variable 10a-Connections (2 ea) Hot tap, stopple, by-pass 8 24,668,000$ 1,085,000$ 493,360$ 1.046 27.41$ 4.60% 21,700$ 1.21$





NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item2 Clay type soil was considered as the Base Case3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included light, standard clearing; the type of clearing for desert and dry steppe is slightly easier to perform but only by a very small margin.8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.

Expert Report: Pipeline Variable Assessments; NIT-900-034.993-1Base Costs per 50 Kilometers of 18-Inch Pipeline Built in Good Conditions








Case in %

Incremental Cost/Km





Variable 1b-Sandy Soil 36,050,000$ 1,152,000$ 721,000$ 1.033 30.04$ 3.30% 23,040$ 0.96$









Variable 2h-Alpine Tundra Vegetation3 36,399,000$ 1,501,000$ 727,980$ 1.043 30.33$ 4.30% 30,020$ 1.25$






Variable 4c-10 km of Class III 35,980,000$ 1,082,000$ 719,600$ 1.031 29.98$ 3.10% 21,640$ 0.90$

Variable 4d-10 km of Class IV 36,434,000$ 1,536,000$ 728,680$ 1.044 30.36$ 4.40% 30,720$ 1.28$



Variable 5c-Aerial Crossing (1 ea 30m crossing) 36,225,000$ 1,327,000$ 724,500$ 1.038 30.19$ 3.80% 26,540$ 1.11$






Variable 10b-Connections (2 ea) Hot tap, stopple, no by-pass 35,911,000$ 1,013,000$ 718,220$ 1.029 29.93$ 2.90% 20,260$ 0.84$


Variable 10d-Connections (2 ea) cold cut 34,968,000$ 70,000$ 699,360$ 1.002 29.14$ 0.20% 1,400$ 0.06$


NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item2 Clay type soil was considered as the Base Case3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included very light, standard clearing; the type of clearing for desert and dry steppe is slightly easier to perform but only by a very small margin.5 Class I location was considered as the base case.8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.









Case in %

Incremental Cost/Km





Variable 1b-Sandy Soil 42,736,000$ 1,525,000$ 854,720$ 1.037 28.49$ 3.70% 30,500$ 1.02$



Variable 2b-Temperate Broadleaf Forest Vegetation 42,324,000$ 1,113,000$ 846,480$ 1.027 28.22$ 2.70% 22,260$ 0.74$






Variable 2h-Alpine Tundra Vegetation3 42,894,000$ 1,683,000$ 857,880$ 1.041 28.60$ 4.08% 33,660$ 1.12$






Variable 4c-10 km of Class III 42,654,000$ 1,443,000$ 853,080$ 1.035 28.44$ 3.50% 28,860$ 0.96$

Variable 4d-10 km of Class IV 43,190,000$ 1,979,000$ 863,800$ 1.048 28.79$ 4.80% 39,580$ 1.32$



Variable 5c-Aerial Crossing (1 ea 30m crossing) 43,231,000$ 2,020,000$ 864,620$ 1.049 28.82$ 4.90% 40,400$ 1.35$






Variable 10b-Connections (2 ea) Hot tap, stopple, no by-pass 42,654,000$ 1,443,000$ 853,080$ 1.035 28.44$ 3.50% 28,860$ 0.96$


Variable 10d-Connections (2 ea) cold cut 41,335,000$ 124,000$ 826,700$ 1.003 27.56$ 0.30% 2,480$ 0.08$

Variable 11a-Congested area construction (5km) 52,957,000$ 11,746,000$ 1,059,140$ 1.285 35.30$ 28.50% 234,920$ 7.83$

NOTES:1 Each of the above Variables is based on 5 kilometers of each Variable within the Base Case of 50 kilometers total for comparison unless defined otherwise for each line item2 Clay type soil was considered as the Base Case3 Although the request was made to assess vegetation in Alpine Tundra and Tundra areas, the associated overall pipeline construction costs are impacted due to specialized construction methods required. See Section 2.2.1.1 of this Report for further details.4 Desert, dry steppe, and savannah areas can contain quantities of rock, however, in the cases considered, no rock was assumed. The Base Case included light, standard clearing; the type of clearing for desert and dry steppe is slightly easier to perform but only by a very small margin.5 Class I location was considered as the base case.8 For "Connections", it is assumed there would be 2 each tie-ins for each pipeline (one at each end) to be made for replacement & re-introduction to service.




Assessments


Appendix F – Additional Variable Impacts Across Diameters

Appendix F-1 – Cost Delta Table for Additional Variable Impacts for 6-Inch


Description Total Cost

Total Cost

Difference vs

Base

Total Cost/Km Multiplier/Km

Versus Base Case

Total Cost/Dia-

in/Meter

Total Cost

Delta vs Base

Case in %

Incremental

Cost/Km

Incremental

Cost/Dia-

in/Meter

6-inch (6.625) x 50 kms













Difference vs Base

Total Cost/Km Multiplier/Km Versus

Base Case Total Cost/Dia-

in/Meter

Total Cost Delta vs Base Case in

%

Incremental Cost/Km


12-inch (12.750) x 50 kms












Difference vs Base

Total Cost/Km Multiplier/Km Versus Base

Case



%

Incremental Cost/Km


18-inch (18.000) x 50 kms


Variable 13a-Fuel Costs ($1/gal or $0.26/liter change +/-) 24,762,000$ 1,179,000$ 495,240$ 1.050 27.51$ 5.00% 23,580$ 1.31$




Variable 8d-Terrain of 20%-25% (1 km) 24,975,000$ 1,392,000$ 499,500$ 1.059 27.75$ 5.90% 27,840$ 1.55$

Variable 8e-Terrain of 25%+ (1 km) 25,093,000$ 1,510,000$ 501,860$ 1.064 27.88$ 6.40% 30,200$ 1.68$





Difference vs Base


Versus Base Case Total Cost/Dia-

in/Meter


%

Incremental Cost/Km


24-inch (24.000) x 50 kms




Variable 8b-Terrain of 10%-15% (1 km) 36,015,000$ 1,117,000$ 720,300$ 1.032 30.01$ 3.20% 22,340$ 0.93$

Variable 8c-Terrain of 15%-20% (1 km) 36,434,000$ 1,536,000$ 728,680$ 1.044 30.36$ 4.40% 30,720$ 1.28$







Difference vs Base


Versus Base Case Total Cost/Dia-

in/Meter


%

Incremental Cost/Km


30-inch (30.000) x 50 kms




Variable 8b-Terrain of 10%-15% (1 km) 42,571,000$ 1,360,000$ 851,420$ 1.033 28.38$ 3.30% 27,200$ 0.91$

Variable 8c-Terrain of 15%-20% (1 km) 43,066,000$ 1,855,000$ 861,320$ 1.045 28.71$ 4.50% 37,100$ 1.24$






Assessments


Appendix G – Variable Graphs Across Selected Diameters

4” 12” 18” 24” 30”

4” 12” 18” 24” 30”

12” 18” 24” 30”

4” 12” 18”24”

30”

4”

4” 12” 18” 24” 30”

4” 12” 18” 24” 30”

4” 12” 18” 24” 30”

4” 12” 18” 24” 30”



Assessments


Appendix H – Historical Data for Actual versus Estimate Pipeline Construction Costs The following data was taken from Oil & Gas Journal and may be useful to CREG for informational purposes only.

US pipeline costs: estimated vs. actual, 2011-20121

Onshore pipelines

Costs, $

Length, R.O.W. & Delta

Size, in. Location miles Materials Labor Misc.2

damages Total $/mile $/dia-in/ft $/dia-in/mtr Est vs Act

16 Illinois (lat.)3

8.65

Estimated 3,771,000$ 4,609,000$ 8,984,000$ 1,051,000$ 18,415,000$ 2,128,902$ 25.20$ 82.68$

Actual 4,406,400$ 5,961,600$ 6,030,000$ 2,002,000$ 18,400,000$ 2,127,168$ 25.18$ 82.61$ $

16 Arkansas (lat.) 8.40 -$

Estimated 3,315,538$ 9,861,699$ 15,695,716$ 3,764,516$ 32,637,469$ 3,885,413$ 45.99$ 150.89$

Actual 3,868,951$ 8,087,371$ 8,877,033$ 2,580,489$ 23,413,844$ 2,787,362$ 32.99$ 108.25$ $

20 Pennsylvania /R/ 18.20 -$

Estimated 5,451,977$ 16,886,006$ 9,072,641$ 863,600$ 32,274,224$ 1,773,309$ 16.79$ 55.09$

Actual 5,624,581$ 17,754,229$ 8,697,586$ 1,712,602$ 33,788,998$ 1,856,538$ 17.58$ 57.68$

20 Pennsylvania-New 17.00

Estimated 8,176,800$ 25,402,300$ 20,846,300$ 2,330,900$ 56,756,300$ 3,338,606$ 31.62$ 103.73$

Actual 5,401,294$ 29,574,954$ 13,467,759$ 4,934,659$ 53,378,666$ 3,139,922$ 29.73$ 97.55$

20 Oregon /R/ 7.75

Estimated 3,375,382$ 9,549,484$ 4,282,511$ -- 17,207,377$ 2,220,307$ 21.03$ 68.98$

Actual 3,155,340$ 9,593,556$ 7,954,830$ -- 20,703,726$ 2,671,449$ 25.30$ 83.00$

20 Pennsylvania 2.00

Estimated 602,914$ 2,064,612$ 892,229$ 80,000$ 3,639,755$ 1,819,878$ 17.23$ 56.54$

Actual 464,664$ 1,206,025$ 1,565,389$ 65,285$ 3,301,363$ 1,650,682$ 15.63$ 51.28$

24 Utah 24.60

Estimated 9,088,000$ 649,500$ 35,918,765$ 443,600$ 46,099,865$ 1,873,978$ 14.79$ 48.52$

Actual 8,561,800$ 1,420,300$ 35,929,800$ 264,400$ 46,176,300$ 1,877,085$ 14.81$ 48.60$

24 Pennsylvania 15.00

Estimated 6,165,091$ 16,919,196$ 10,010,385$ 1,192,597$ 34,287,269$ 2,285,818$ 18.04$ 59.18$

Actual 7,062,600$ 19,819,056$ 11,387,314$ 1,948,032$ 40,217,002$ 2,681,133$ 21.16$ 69.42$

24 New York 1.36

Estimated 701,887$ 1,665,935$ 1,241,429$ 85,000$ 3,694,251$ 2,716,361$ 21.44$ 70.33$

Actual 1,126,082$ 1,684,833$ 1,138,748$ 86,868$ 4,036,531$ 2,968,038$ 23.42$ 76.84$

30 Pennsylvania-New 127.00

Estimated 98,489,988$ 205,000,000$ 123,603,371$ 20,597,995$ 447,691,354$ 3,525,129$ 22.25$ 73.01$

Actual 86,773,190$ 311,943,580$ 131,232,565$ 20,719,500$ 550,668,835$ 4,335,975$ 27.37$ 89.81$

30, 36 Texas (L) 5.30

Estimated 12,691,172$ 12,313,286$ 4,684,611$ 5,000$ 29,694,069$ 5,602,655$ 32.15$ 105.49$

Actual 11,752,446$ 17,100,141$ 2,029,160$ 30,855$ 30,912,602$ 5,832,566$ 33.47$ 109.82$

42 Wyoming-Oregon 682.70

Estimated 1,160,863,620$ 1,231,828,772$ 761,141,158$ 48,733,484$ 3,202,567,034$ 4,691,031$ 21.15$ 69.40$

90.70%

99.92%

71.74%

104.69%

94.05%

120.32%

100.17%

117.29%

109.27%

123.00%

104.10%

107 24%

US pipeline costs: estimated vs. actual, 2011-20121

Onshore pipelines

Costs, $

Length, R.O.W. & Delta

Size, in. Location miles Materials Labor Misc.2

damages Total $/mile $/dia-in/ft $/dia-in/mtr Est vs Act

Actual 1,152,171,091$ 1,385,824,894$ 844,691,990$ 51,640,807$ 3,434,328,782$ 5,030,509$ 22.68$ 74.42$

20-42 Alabama-Florida4

483.00

Estimated 585,420,601$ 764,591,011$ 578,816,442$ 139,934,823$ 2,068,762,877$ 4,283,153$ 26.17$ 85.85$

Actual 576,807,749$ 899,464,588$ 451,847,555$ 180,015,691$ 2,108,135,583$ 4,364,670$ 26.67$ 87.49$

42 Texas-Louisiana 174.00

Estimated 187,842,235$ 414,584,297$ 177,081,471$ 49,980,134$ 829,488,137$ 4,767,173$ 21.50$ 70.53$

Actual 167,732,918$ 316,411,168$ 110,583,985$ 46,248,718$ 640,976,789$ 3,683,775$ 16.61$ 54.50$

42 Arkansas-Mississip 120.50

Estimated 216,744,151$ 252,018,490$ 104,044,141$ 19,985,684$ 592,792,466$ 4,919,440$ 22.18$ 72.78$

Actual 173,535,400$ 230,559,482$ 65,306,686$ 20,241,648$ 489,643,216$ 4,063,429$ 18.32$ 60.12$

42 Arkansas 64.70

Estimated 115,656,838$ 134,479,576$ 55,534,998$ 10,664,560$ 316,335,972$ 4,889,273$ 22.05$ 72.33$

Actual 93,442,139$ 124,147,414$ 35,165,139$ 10,899,349$ 263,654,041$ 4,075,024$ 18.38$ 60.29$

42 Louisiana (L) 20.60

Estimated 33,128,510$ 51,544,148$ 32,903,628$ 5,790,765$ 123,367,051$ 5,988,692$ 27.01$ 88.60$

Actual 22,828,941$ 37,352,139$ 15,031,001$ 3,079,379$ 78,291,460$ 3,800,556$ 17.14$ 56.23$

Total land, miles 1,780.76

Estimated 2,451,485,704$ 3,153,967,312$ 1,944,753,796$ 305,503,658$ 7,855,710,470$ 4,411,437$ 22.30$ 73.17$

Actual 2,324,715,586$ 3,417,905,330$ 1,750,936,540$ 346,470,282$ 7,840,027,738$ 4,402,630$ 22.26$ 73.03$

1Actual cost data must be filed within 6 months following final hydrostatic test of pipeline. Not all projects

proposed (estimated costs) are built (actual costs). L = loop, lat. = lateral, R = replacement.2Generally includes surveys, engr., supvervision, interest, freight, taxes, administration and overheads, contingencies,

allowances for funds used during construction (afudc), and regulatory fees.3 Materials and labor not separated in final cost filing. Costs shown are estimates using prevailing material-labor ratio.

4 Detailed final costs were not filed. Costs shown are estimates derived from ratios in initial filing. Alabama-Florida project includes loops, laterals, and mainline construction.

Source: US FERC; for completed-project costs filed between July 1, 2011, and June 30, 2012, under CFR Section 157.20(c)(4).

99.80%

107.24%

101.90%

77.27%

82.60%

83.35%

63.46%

expert report: pipeline variable assessments; nit- 900...

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