Kern River MAOP Petition

Petition for Special Permit to Increase the Maximum Allowable Operating Pressure of the Kern River Gas Transmission Company System

August 20, 2007

Kern River Gas Transmission Company Petition for MAOP Special Permit

TABLE OF CONTENTS

SPECIAL PERMIT APPLICATION SUMMARY...... 1 Scope of the Application...... 1 Table 1 – Summary of Special Permit Conditions ...... 3 Design, Manufacturing and Construction...... 4 Table 2 – Summary of Design, Manufacturing and Construction...... 4 Additional Integrity Activities Associated With This Petition ...... 5 Table 3 – Additional Integrity Activities...... 5 Schedule...... 5 BENEFITS OF THE MAOP SPECIAL PERMIT ...... 6 Benefits to Landowners and the Environment ...... 6 Benefits to Shippers and End Users...... 6 Benefits to PHMSA and the General Public ...... 6 Benefits to Kern River...... 6 OVERVIEW OF THE KERN RIVER GAS TRANSMISSION SYSTEM...... 7 Original Mainline – 1992...... 7 2001 California Action Project...... 7 2002 Expansion ...... 7 2003 System Expansion ...... 7 Figure 1 – Kern River System Map ...... 9 Technical Analysis ...... 10 Analysis of Threats ...... 10 Table 4 – Summary of Impacts of Threats at Higher Operating Stress Level and Mitigation Measures Throughout Life Cycle ...... 12 DESIGN BASIS...... 15 Table 5 – Kern River Design Basis ...... 15 MANAGING STABLE THREATS ...... 16 Line Pipe...... 16 Compressor Station Evaluation...... 18 Table 6 – Summary of Station Component Evaluation ...... 19 Meter Station Evaluation...... 20 Pipe Fittings, Valves and Flanges...... 20 SCADA and System Control...... 20 Table 7 – Example Unit and Station Control Scheme...... 21 Figure 2 – Depiction of Control Scheme...... 22 Welding...... 22 Construction...... 22 Pressure Testing...... 23 Table 8 - Summary of Estimated Operating Pressure Times Applicable Hydrotest Factor to Original Hydrotest Pressure for Next Potential Expansion of the Kern River System...... 24 Equipment ...... 25 MANAGING TIME-DEPENDENT THREATS...... 26 Internal Corrosion Control...... 26 Table 9 – Gas Quality Monitoring ...... 26

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External Corrosion Control...... 27 Figure 3 – Baseline ILI Anomalies Investigated in Confirmation Digs as Compared to Threshold Levels as Multiples of MAOP...... 29 Table 10 – Summary High Resolution MFL Tool Runs and Findings...... 31 Figure 4 – Comparison of Depths Called on ILI Logs versus Depths As Found...... 32 Figure 5 – Comparison of Lengths Called on ILI Logs versus Lengths As Found...... 33 Stress Corrosion Cracking (SCC) ...... 34 MANAGING TIME-INDEPENDENT THREATS ...... 35 Mechanical Damage...... 35 Weather and Outside Force...... 35 Incorrect Operations ...... 35 REFERENCED STANDARDS, SPECIFICATIONS AND PROCEDURES ...... 36

ii Kern River Gas Transmission Company Petition for MAOP Special Permit

SPECIAL PERMIT APPLICATION SUMMARY

Scope of the Application Kern River Gas Transmission Company (Kern River) has completed an evaluation of its existing pipeline system and pipeline appurtenances, including the associated compression, measurement and pressure regulation, and respectfully submits this petition to operate the system to a maximum allowable operating pressure (MAOP) of 1,333 pounds per square inch gauge (psig), representing 80% of the pipeline specified minimum yield strength (SMYS).1

Kern River has determined that the system can safely and reliably operate at this pressure. Under the provisions providing for special permits under 49 U.S.C. § 60118, Kern River requests relief from the following regulations: • 49 CFR § 192.111, Design factor (F) for steel pipe. • 49 CFR § 192.201, Required capacity of pressure relieving and limiting stations. • 49 CFR § 192.505, Strength test requirements for steel pipeline to operate at a hoop stress of 30% or more of SMYS. • 49 CFR § 192.619, Maximum allowable operating pressure: Steel or plastic pipelines.

The Kern River system originates in Lincoln County, Wyo., where it receives Rocky Mountain gas, traversing through southwestern Wyoming, and into Utah where it receives additional gas, passing through Utah and Nevada, interconnecting with the Mojave Pipeline across the California border in San Bernardino County, Calif. The pipeline system downstream of the inlet to the Daggett compressor station is jointly owned by Kern River and Mojave Pipeline Company, an El Paso Corporation company, and is referred to as the Common Facilities. The Kern River wholly-owned and operated facilities comprise 1,380 miles of pipeline. The Common Facilities comprise 300 miles of pipeline. The wholly-owned and operated system is the portion of the assets for which this petition applies.

Facilities on the pipeline system include: • Ten compressor stations, including 20 centrifugal and two reciprocating compressors, totaling 282,000 International Standards Organization (ISO) horsepower (hp) (62,000 ISO hp in original (1992) system, with 220,000 ISO hp added in three expansions from 2001 to 2003). • Forty-eight meter stations, including four that are bi-directional. • Six receipt laterals. • Seven delivery laterals.

1 Within this petition, there will be reference to operation at 80% SMYS. This means operation of Class 1 pipe at 80% SMYS, Class 2 pipe at 67% SMYS, Class 3 pipe at 56% SMYS, and compressor and meter stations at 56% SMYS.

1 Kern River Gas Transmission Company Petition for MAOP Special Permit

This petition to operate under a special permit is for the facilities beginning at the discharge of the Muddy Creek and Painter compressor stations, and the Anschutz meter station to the mainline including the Anschutz compressor station in southwest Wyoming, to the outlet side of the Daggett meter station (which is the interconnection between Kern River and the Common Facilities), in San Bernardino County, Calif.

Kern River is a wholly-owned subsidiary of MidAmerican Energy Holdings Company (a Berkshire Hathaway company), that was acquired on March 27, 2002. For the period January 1, 1996, through March 26, 2002, Kern River was an operating company within The Williams Companies (Williams). Prior to that, Kern River was owned by Williams and Tenneco, who formed a partnership in 1985 to design and build the Kern River system. The original mainline comprises 682 miles of 36-inch pipeline and was placed into service in February 1992. The system was looped with 635 miles of 36-inch pipeline that was placed into service in May 2003.

After reviewing the proceedings from the public meeting held by Pipeline and Hazardous Material Safety Administration (PHMSA) on March 21, 2006, and the requirements for MAOP Special Permits approved in July 2006, Kern River evaluated the demand for supply in the markets served by the system and concluded there was sufficient demand to consider operation at 80% SMYS. Kern River evaluated the technical feasibility and concluded the system can be operated at up to 80% SMYS if a life cycle management approach is utilized for the system.

The Kern River system is connected to numerous Rocky Mountain supply basins via receipt interconnects with Williams Field Services, Northwest Pipeline Corporation, Chevron USA, BP America Production Company, Merit Energy Company, Questar Pipeline Company, Colorado Interstate Gas Company, DCP Midstream, LP, Questar Overthrust Pipeline Company, Enterprise Gas Processing, LLC and Rendezvous Pipeline Company, LLC. The Kern River system provides natural gas transportation to growing markets in Utah, Nevada, California and Arizona while serving local distribution companies Southern California Gas Company, Pacific Gas & Electric Company, Southwest Gas Corporation and Questar Gas Company. Kern River also serves electric utilities Nevada Power Company, Los Angeles Department of Water & Power, Pacific Gas & Electric and San Diego Gas & Electric and numerous directly-connected power plants. The system design capacity is 1,731 million cubic feet per day (MMcf/d). Operation under this petition will provide for an additional capacity of up to 63 MMcf/d without adding any additional facilities.

The plan to operate the assets described above at 80% SMYS is the first part of a proposed expansion program. Kern River is currently designing additional pipeline and compression to be a part of the expansion. These new facilities will be covered by a separate MAOP special permit petition.

There are eight Class 2 areas on the system totaling approximately 7.38 miles. There are 24 Class 3 areas on the system totaling approximately 61.3 miles. There are 33 high consequence areas (HCAs) on the system comprising 83.6 miles.

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Portions of the Kern River system are already designed and tested to operate at the higher MAOP. The scope of facilities requiring a special permit is summarized below.

• The MAOP of the pipeline system will be 1,333 psig, resulting from use of the alternate design factors for the pipeline system, as depicted in Table 1. • Kern River seeks a special permit from the design factor requirements for Class 1, 2 and 3; currently there are no Class 4 areas on the system. • Kern River seeks a special permit to operate future facilities associated with this pipeline at the higher stress levels in Class 1, 2 and 3, i.e.- up to 80%, 67%, and 56% SMYS, respectively. • Kern River seeks a special permit to operate the Fillmore, Goodsprings, Veyo and Elberta compressor stations at 1,350 psig. • Kern River seeks a special permit to operate the discharge side of the Muddy Creek and Painter compressor stations, and the entire Anschutz compressor station at 1,350 psig. • Kern River seeks relief from the pressure test requirements for Coyote Creek compressor station (nitrogen test). • Kern River seeks a special permit to operate the 14-inch pipe within the Salt Lake compressor station at 1,350 psig (pressure tested for 1,250 psig operation). • Kern River seeks a special permit to operate interconnect meter stations at 1,350 psig. • Kern River seeks a special permit to operate three laterals designed for 1,200 psig at 1,333 psig, including Whitney Painter, Riverton and Centennial.

Table 1 shows the design factors for the various class location areas for this pipeline system.

Table 1 – Summary of Special Permit Conditions

Current Current 192 Kern River Proposed Future Class 192.111 Code Code Proposed Operation Location Changes Design Factor Allowable for Under Special Class Permit Changes Class 1 72% (1,200 - 80% (1,333 psig - psig MAOP) MAOP) Class 2 60% 72% 67% Per PHMSA Class special permit protocol Class 3 50% 60% 56% Per PHMSA Class special permit protocol Class 4 40% 50% 40% Per PHMSA Class special permit protocol Stations 50% 50% 56% N/A

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Design, Manufacturing and Construction The Kern River system from initial design to manufacturing of the line pipe and pipeline appurtenances, through construction and commissioning of the original mainline as well as the loop line, was based on modern design, manufacturing and construction practices. Table 2 provides a summary of key elements of the Kern River system.

Table 2 – Summary of Design, Manufacturing and Construction

Elements Purpose Status Specified high quality skelp/plate micro-alloyed, Ensure high quality Line pipe fine grain, low carbon, desulfurized, calcium manufacturing. in service. silicide-treated, fully killed, fine-grained, high- strength micro-alloyed steel per American Design-in damage Line pipe Petroleum Institute (API) 5L: resistance and in service. • Minimum average absorbed energy for three fracture resistance. full size Charpy V-Notch (CVN) specimens per heat for tests at 20 degrees Fahrenheit (F) and achieves greater than 86 foot- pounds all heat average. • D/t ratio of 84 (maximum) – 36-inch, 0.429- inch wall. • Fracture arrest in 5 joints, with 95% probability. • 95% minimum mill hydrotest for 10 seconds. • Fusion-bonded epoxy coating (non- shielding). • Abrasion resistant overlay coating on entire loop system. • Crossings and borings have additional concrete coating.

High level of quality control during construction: Ensure high quality Completed • Pipe transported per API 5LW and 5L1. construction. • Mechanized and stick welding on girth welds per API 1104. • Stick welding on tie-ins per API 1104. • 100% girth weld non-destructive examination (NDE) per API 1104. Designed to accommodate in line inspection (ILI) Additional assurance Completed tools. Geometry tool inspection prior to of as-built quality, on- commissioning. going integrity assessment.

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Additional Integrity Activities Associated With This Petition As a result of completing this assessment for increasing the MAOP of the system, Kern River has identified the additional integrity-related activities that will be performed to support this petition. These additional activities are shown in Table 3.

Table 3 – Additional Integrity Activities

Activity Purpose Timing Perform ILI at interval Integrity assessment Initial assessment completed, specified in Subpart O per Subpart O future assessment per Subpart O Implement external External corrosion 2007 and ongoing corrosion mitigation prevention measures Program implementation Compliance with the Implementation plan for operations and completion plans supplemental safety and maintenance, including criteria in this commissioning plan, 30 days prior application to placing the pipeline in service at the higher pressure Annual report to PHMSA Report performance Annually every year after initial for entire system and compliance with completion report. this application

Schedule Kern River proposes a schedule to commence operations at 1,333 psig by March 2008. The key milestones are shown below.

• Kern River MAOP special permit application filed August 2007 • Technical discussion and comment period August 2007 to January 2008 • Special permit grant date February 2008 • Begin pressure increase March 2008 • Commence operation at 80% SMYS March 2008

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BENEFITS OF THE MAOP SPECIAL PERMIT FOR THE KERN RIVER SYSTEM

Operation of the Kern River pipeline system at a higher pressure will benefit the environment and landowners through a significant reduction of facilities to be installed, shippers through a reduction in facility costs and end users of natural gas by providing additional capacity to markets in Utah, Nevada, Arizona and California.

Benefits to Landowners and the Environment If this petition is granted, the Kern River system will deliver up to an additional 63 MMcf/d without adding facilities. Additional increase in capacity with a future expansion will depend upon the specific design of the expansion. A pipeline designed and operated under existing regulations, at 72% of SMYS, would require additional compression and associated equipment and possibly additional land disturbance to house the facilities to achieve a comparable throughput capacity. Operation at the higher pressure results in lower fuel gas consumption and lower greenhouse gas emissions.

Benefits to Shippers and End Users Operation at the higher pressure will provide additional supply of natural gas to local markets in Utah, Nevada, Arizona and California. This pipeline will provide natural gas from the Rocky Mountain supply basins, which have in recent times been recognized as significant sources of domestic reserves, yet constrained by existing pipeline takeaway capacity. During initial operation and for some period of time until the full capacity of the system is utilized, customers may benefit through the reduction of fuel gas consumption. Implementation of this permit will allow future expansions of Kern River’s pipeline system to be more economical.

Benefits to PHMSA and the General Public The increased rigor and diligence applied at each stage of the life cycle will provide for a safer pipeline for every threat over every foot of the pipeline system. Kern River conducted a comprehensive and systematic evaluation of each of the threats to pipeline integrity and security when operating at higher pressures. Kern River also evaluated each section of the existing 49 CFR regulations and evaluated where operation at higher pressure will impact requirements of the regulations. Kern River has and will implement measures to address the impact of operation at the higher pressures for each impacted regulatory provision.

Benefits to Kern River Operation at higher pressures will enable Kern River to achieve an increase in overall system capacity.

6 Kern River Gas Transmission Company Petition for MAOP Special Permit OVERVIEW OF THE KERN RIVER GAS TRANSMISSION SYSTEM

Original Mainline – 1992 The original mainline pipeline system included approximately 682 miles of 36-inch pipeline originating with an interconnect at Northwest Pipeline’s mainline near Opal, Wyo., approximately 60 miles north of the Utah/Wyoming border, to the interconnection with the Common Facilities near Daggett, in San Bernardino County, Calif.

The original mainline system included three compressor stations with a total of 50,400 ISO hp. The stations were configured as follows:

• The Muddy Creek compressor station, with 25,200 ISO hp, located at milepost 0 at the interconnection with Northwest Pipeline near Opal, Wyo. • The Fillmore compressor station, with 12,600 ISO hp, located approximately at milepost 276.7 in central Utah. • The Goodsprings compressor station, with 12,600 ISO hp, located at milepost 565.9 in southern Nevada.

The mainline system, as originally constructed, was capable of delivering 700 MMcf/d to the point of interconnection with the Common Facilities. The MAOP of the original mainline was 1,200 psig. The system was placed into service in February 1992.

2001 California Action Project Two compressor stations were added in 2001 to address acute gas supply shortages in California. The capacity additions were made by adding compressor stations at Elberta (7,150 ISO hp) at milepost 191.60 in Utah County, Utah, and at Veyo (15,000 ISO hp), at milepost 406.50 in Washington County, Utah.

2002 Expansion A compressor unit was added at the Muddy Creek compressor station with 13,000 ISO rated hp in addition to other system modifications.

2003 System Expansion A system expansion was completed in 2003. The expansion included 635 miles of 36- inch pipeline to loop approximately 92% of Kern River’s existing mainline and the Opal lateral from Wyoming, through Utah and Nevada, to California. The additions also included:

• Three new mainline compressor stations - the Coyote Creek compressor station at milepost 60.10 in Uinta County, Wyo., the Salt Lake compressor station at milepost 132.02 in Salt Lake County, Utah, and the Dry Lake compressor station at milepost 500.10 in Clark County, Nev. • Turbine-driven compressor unit additions, upgrades and/or modifications at four existing compressor stations - the Muddy Creek compressor station in Lincoln County, Wyo., the Fillmore compressor station in Millard County, Utah, the Veyo

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compressor station in Washington County, Utah, and the Goodsprings compressor station in Clark County, Nev. • Replacement of the turbine-driven compressor units at the existing Elberta compressor station in Utah County, Utah. • An approximately 0.8 mile extension of the existing 12-inch Anschutz lateral to establish an additional mainline tie-in point on the suction side of the proposed Coyote Creek compressor station. • Upgrades and modifications of the Opal meter station in Lincoln County, Wyo., and the PG&E-Daggett meter station in San Bernardino County, Calif. • Various mainline block valves, launcher/receiver facilities and other appurtenances.

The compression additions, upgrades, replacements and modifications resulted in a total system horsepower of 282,000 ISO hp. The additional compression and pipeline loops more than doubled Kern River's existing summer design day capacity, increasing it to approximately 1,731 MMcf/d.

Figure 1, on the next page, is a map of the Kern River system.

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Figure 1 – Kern River System Map

9 Kern River Gas Transmission Company Petition for MAOP Special Permit TECHNICAL ANALYSIS

Analysis of Threats An analysis of the threats applicable to Kern River was conducted as an initial step in the evaluation of the feasibility of operating at higher stress levels. This included identifying and evaluating the impacts of operating at higher stress levels for each threat. Measures to mitigate the impacts were defined by considering the practices applied through implementation of the company’s Operations and Maintenance Manual (O&M Manual) and Integrity Management Plan for High Consequence Areas, as well as the technical guidance developed by PHMSA for consideration in MAOP special permits. Table 4 provides a summary of the threat analysis and demonstrates how each threat is managed throughout the pipeline life cycle. Table 4 shows the breadth and depth of specific measures that Kern River has and is applying throughout the life cycle of the pipeline system to address the variety of threats when operating at the higher stress levels. It is the collective application of these measures across all of the threats that provide an equal and most likely a greater level of safety than with the current operation at 72% of SMYS. In addition, the table indicates whether additional studies are necessary to ensure safe operation up to 80% of SMYS.

The stable threats are managed by:

• Installing quality pipe that meet the rigors of the pipe material specifications including American Petroleum Institute (API) 5L. • Developing and adhering to comprehensive material and construction specifications. • Implementing appropriate inspection and other manufacturing and construction controls. • Transporting the pipe per specifications. • Using qualified welders performing welding to qualified procedures. • Performing NDE of 100% of the girth welds. • Performing a pre-service pressure test. • Commissioning of facilities at 80% SMYS using a commissioning plan.

The time-dependent threats are managed by:

• Applying non-shielding fusion-bonded epoxy (FBE) coating. • Installing a properly designed cathodic protection system and ensuring that the system is properly maintained. • Performing a close interval survey in HCAs within one year of placing the pipeline in service at the higher pressure and on the remainder of the system within four years of placing the pipeline in service at the higher pressure. • Performing an ILI baseline inspection using a high resolution magnetic flux leakage (MFL) tool. • Monitoring and controlling gas quality. • Operating at temperatures below the coating specification temperature.

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• Inspecting exposed pipe for evidence of corrosion and stress corrosion cracking where coating is disbonded or otherwise damaged.

The time-independent threats are managed by:

• Developing and following a fracture control plan per API 5L requirements. • Demonstrating puncture resistance to at least 65 tons. • Designing pipe to withstand anticipated external loads. • Having a comprehensive damage prevention program, including observation of all known excavations that cross or expose the pipe. • Conducting a baseline geometry tool inspection prior to placing the pipeline in service, also in conjunction with high resolution MFL runs. • Operating the pipeline in accordance with comprehensive procedures. • Maintaining a qualified work force. • Employing a supervisory control and data acquisition (SCADA) system with appropriate data gathering, analysis and alarms.

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Table 4 – Summary of Impacts of Threats at Higher Operating Stress Level and Mitigation Measures Throughout Life Cycle

Threat Outcome and Impacts of Design, Materials Specification and Construction Including Operations and Maintenance Comments Operation at Higher Stress Manufacturing Transportation Levels Stable Manufacturing- Defective pipe • Materials specification per API 5L • Induction bends per Kern • Maintain operating Specification of materials related Defective seam weld at the time of manufacturing, River Construction pressures within MAOP per API 5L provides for mill • Smaller critical defect size including Appendix F, SR-15, 17 Specifications certificates and traceability, tolerance and 18. • Transportation of pipe per non-destructive inspection • Mill hydrostatic test per API 5L at API 5L1 for rail and weldability the time of manufacture transportation and API • QA/QC during manufacturing 5LW for transportation by (full body and circumference plate barge and marine vessels. inspection) • D/t < 100 Welding and Defective girth weld • Carbon equivalent (IIW) content • Qualify welding • Monitor for outside forces Specification of materials as fabrication-related Defective fabrication weld per pipe specifications which were procedures that may compromise girth per API 5L provides Wrinkle bend 0.43%, based on MSS SP-75. • Qualify welders weld integrity weldability Buckle • Prepare for welding • Smaller critical defect size • Field bends per company tolerance specifications • 100% inspection of girth welds • Pre-service hydrostatic test Equipment and • Gasket/O-ring failure • Design to appropriate pressure • QA/QC of as received • Station commissioning plan Station design factor of 0.56 fittings-related • Control/relief equipment rating or pressure containing code fittings and components for piping malfunction (ANSI, ASME, etc.) • 100% inspection of welded • Seal/pump packing failure • Purchasing control of product connections • Station equipment, fittings or specifications • Flanged fitting tightening piping failure • Analysis and mitigation of thermal per company specifications • Potential for increased and mechanical stresses in design thermal stresses on station • Overpressure protection set to piping maximum of 104% MAOP. • Potential for increased mechanical stresses on station piping

Table 4 – Page 1 of 3

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Table 4 – Summary of Impacts of Threats at Higher Operating Stress Level and Mitigation Measures Throughout Life Cycle

Threat Outcome and Impacts of Design, Materials Specification and Construction Including Operations and Maintenance Comments Operation at Higher Stress Manufacturing Transportation Levels Time-Dependent External corrosion Wall loss • FBE coated pipe (non-shielding) • Mitigation of AC/DC • Baseline high resolution • Reduces allowable defect size • Cathodic protection and interference during MFL and geometry tool • Changes the repair thresholds monitoring of system construction runs completed • Reduces response time for • Specified backfill materials to • Coatings used on bored • Close interval surveys repairs help ensure minimization of sections were abrasive within four years of special • Reduces re-inspection interval coating damage resistant permit issuance and data for active corrosion • Coating applied per NACE and • Coating inspection and analyzed in conjunction operator standards repair with ILI • Post-construction hydro- • Remote monitoring of test rectifiers • Post-construction • Electrical isolation geometry tool run • Interference testing • Atmospheric corrosion prevention

Internal corrosion Wall loss • Review anticipated quality of • Maintained pipe during • Baseline high resolution • Reduces allowable defect size receipts construction to minimize MFL and geometry tool • Changes the repair threshold • Identify low spots from elevation the introduction of water runs completed • Reduces response time for profile and debris • Monitor and ensure repairs • Review anticipated flow patterns • Cleaning pig runs conformance with gas • Reduces re-inspection interval and identify potential null points • Loop line dried to minus quality per FERC tariff for active corrosion • Mainline and loop line are 40 degree F dewpoint • Internal inspection of pipe internally coated; line pipe, does when cut not include girth welds • Cleaning pig runs (as needed) Stress corrosion Localized cracking • FBE coated pipe with surface • Coating inspection and • Above-ground surveys to cracking • Ensures that coating is not pretreatment (non-shielding) repair evaluate coating condition susceptible to creating • Liquid epoxy coating on the tie-in • Post-construction hydro- • Temperature alarms and environment conducive to SCC welds. FBE spray powder coating test shut down • Potentially higher compressor on girth welds • Post-construction • Magnetic particle station discharge temperatures • Specified backfill materials to geometry tool run inspection of areas with ensure adequate cathodic disbonded coating protection

Table 4 – Page 2 of 3

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Table 4 – Summary of Impacts of Threats at Higher Operating Stress Level and Mitigation Measures Throughout Life Cycle

Threat Outcome and Impacts of Design, Materials Specification and Construction Including Operations and Maintenance Comments Operation at Higher Stress Manufacturing Transportation Levels Time-Independent Mechanical damage, Dents • Fracture control plan per API 5L, • Construction specification • IMP – Mechanical first, second and third Fatigue cracking Appendix F, SR-5, 6 and 19 to include bedding, Damage Prevention party • Greater stresses on dents • Puncture resistance to 65 tons sandbags and backfill to Program (including • Increased potential for • Fatigue analysis per GRI report by preclude dents during pipe 192.935(b)(i-iv) fatigue Kiefner Associates (GRI-04/0178) laying • Multi-channel geometry tool baseline • Marking per PHMSA requirements, recognizing local ordinances and environmental restrictions • Increased patrols –aerial or foot patrols Weather-related and Damage to pipe by induced • Design to consider the load and the • IMP – Weather and outside force strains environment outside force per Damage to pipe by external Preventive and Mitigative loads Measures Procedure • Marginal impact Incorrect operations • Operator error • Automated operation • Operator qualification per • No substantive impact • Redundant controls and shutdowns 192, Subpart N • Internal audits of procedure use and work practices • QA/QC Infrastructure • Human intervention • PHMSA advisory • Automation and SCADA Automated mainline valves in security • No substantive impact • Operator’s infrastructure security • Remotely operated block Salt Lake City and Las Vegas plan valves along the pipeline areas in highly populated areas

Table 4 – Page 3 of 3

14 Kern River Gas Transmission Company Petition for MAOP Special Permit DESIGN BASIS

The pipe design was confirmed for operation at up to 80% of SMYS in Class 1 locations, 67% of SMYS in Class 2 locations, and 56% in Class 3 locations. There are no Class 4 locations on the pipeline system. Road and rail crossings, compressor and meter stations were designed per 49 CFR 192. As such, Kern River is seeking relief for the crossings and stations under this petition for a special permit. Table 5 below shows a summary of the design pressures for the pipeline.

Remotely operated valves (ROVs) are installed at the interconnect points and mainline valves in highly populated areas. The mainline valves have power operators for rapid closure with backup manual hydraulic pumps for closure by manual means. Additional remote operation of valves will be installed at MP 103A, 157A and B, 164A and B, and 457A and B to complete installation of ROVs adjacent to all HCAs. Compressor units and associated station valves are remotely monitored and operated at the gas control center as well as locally.

Table 5 - Kern River Design Basis

Class 1 Class 1 Class 2 Class 2 Class 3 Class 3 Part of System MAOP Diameter D/t SMYS Wall %SMYS Wall %SMYS Wall %SMYS

Line Pipe 1,333 36 83.9 70.0 0.429 80% 0.515 67% 0.618 55%

Railroad Crossing 1,333 36 69.9 70.0 0.515 66.6% 0.618 55.5% N/A N/A

Highway Crossing 1,333 36 69.9 70.0 0.515 66.6% 0.618 55.5% N/A N/A

Compressor Pipe 1,350 42 48.0 60.0 0.875 54.0% N/A N/A N/A N/A 1,350 42 42.0 60.0 1.000 47.3% N/A N/A N/A N/A 1,350 36 48.0 60.0 0.750 54.0% N/A N/A N/A N/A 1,350 30 36.9 60.0 0.812 41.6% N/A N/A N/A N/A 1,350 24 48.0 60.0 0.500 54.0% N/A N/A N/A N/A 1,350 20 40.0 52.0 0.500 51.9%

Vessels 1,350 N/A N/A N/A N/A 50.0% N/A N/A N/A N/A

Compressor Units1,350+N/AN/AN/AN/A37.0%N/AN/AN/AN/A

OPP Pipeline 1,386 N/A N/A N/A N/A 83.2% N/A N/A N/A N/A

OPP Units 1,386 N/A N/A N/A N/A N/A N/A N/A N/A N/A

Over Pressure Protection (OPP)

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MANAGING STABLE THREATS

Line Pipe The line pipe was manufactured in accordance with the Tenneco Pipe Specification for the original mainline and the Williams Pipe Specification for the loop line. Both specifications incorporate the API standard 5L, Product Specification Level 2 (PSL2).2 The pipe met, at a minimum, the supplemental requirements (SR) for maximum operating pressures and minimum operating temperatures. The 1990 edition of the standard was used for the original mainline pipe specification and the 2000 edition was used for the expansion pipe specification. The diameter, wall thickness, MAOP and percent SMYS are shown in Table 5 above.

The skelp/plate was micro-alloyed, fine grain, fully killed steel with calcium treatment. The micro-alloy was demonstrated by the presence of titanium, vanadium and niobium. The 0.02% or less of aluminum demonstrated fine-grained steel. The aluminum level and silicon at 0.2% or less demonstrates that the material was fully killed. Calcium treatment was demonstrated by the trace levels of calcium; approximately 0.005%. The pipe steel was a low-carbon, high-strength, and low-alloy material. Pipe carbon content was 0.12% maximum for X70 pipe per company specification for double submerged arc-weld (DSA) welded pipe. Pipe carbon equivalent was 0.4% maximum per the mill’s manufacturing procedure specification.

The pipe was manufactured in accordance with Appendix F of API 5L in order to control the overall fracture toughness properties to enable the pipe to resist and arrest fracture. The pipe fracture toughness testing in accordance with API 5L, the American Society of Mechanical Engineers B31.8 Standard (ASME B31.8) and other specifications and standards address the steel pipe toughness properties needed to resist crack initiation, crack propagation and to ensure crack arrest during a pipeline failure caused by a fracture. Kern River has implemented an overall fracture control plan addressing steel pipe properties necessary to resist crack initiation and crack propagation and to arrest a fracture within eight pipe joints with a 99% occurrence probability or within five pipe joints with a 95% occurrence probability.

Fracture toughness testing on the pipe as manufactured included Charpy impact tests which met, at a minimum, the following:

• SR5A- Shear Area: Test results at 20 degrees F achieved at least 85% minimum average shear area for all X-70 heats,3 with a minimum result of 80% shear area for any single test to address ductile fracture and arrest. • SR5B- Absorbed Energy CVN test results at 20 degrees F require minimum average absorbed energy for three specimens from a heat achieving an all heat average

2 The PSL 2 did not exist in 1991, the time of the design and material specification for the original mainline. The Tenneco Pipe Specification meets the essential requirements of the current PSL 2 specification. 3 The original mainline facture control tests were conducted at 32 degrees F.

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exceeding 86 foot-pounds as required by SR19.1(b) of API 5L. The toughness levels address resistance to fracture initiation and secure ductile fracture arrest limiting the fracture propagation. The all-heat average Charpy value exceeded the values as calculated using the American Iron and Steel Institutes equation at 20 degrees F.

The fracture initiation, propagation and arrest plan accounts for the entire range of pipeline operating temperatures, pressures and gas compositions planned for the pipeline diameter, grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions associated with the waiver area. Brittle to ductile transition temperature curves were developed for each slab source material to demonstrate that the base material was neither brittle nor prone to brittle fracture. An adjustment to the required toughness has been made to account for the non-conservative empirical methods for higher toughness, higher grade, and larger diameter pipe. The test results and the original design basis for fracture control are summarized in a fracture control plan.

A mill quality assurance plan was developed and used to ensure conformance with the company-specified quality of the plate and pipe. Kern River had a comprehensive mill inspection program to check for inclusions and defects that could have affected the pipe quality. The quality assurance plan also included ultrasonic testing. Plate thickness was controlled in accordance with API 5L tolerance of minus 8%, or plus 19.5% of specified wall thickness.

Pipe was inspected at the mill by a third-party inspection service in accordance with Pipe Mills’ Quality Assurance Plan, API 5L and the company’s pipe specifications. Mill inspection reports were made daily and reviewed by a metallurgist. The pipe seam tests met the requirements of API 5L. Pipe hardness was tested using a Rockwell tester specified per American Society for Testing and Materials per the company pipe specification. The hardness testing was done for at least one length of pipe for each heat. The hardness testing included at least three readings from each heat affected zone, three readings in the weld metal, and two readings in each section of the base pipe, for a total of 13 readings.

Mill pressure testing was at a minimum of 95% SMYS. The pressure was held for a minimum of 10 seconds. Mill testing was witnessed and documented by a third-party inspector.

The pipe is puncture resistant to a minimum of 65 tons. This determination is based on PRCI Research (“Reliability-Based Prevention of Mechanical Damage to Pipelines,” PRCI-244- 9729, August 2000) for 36-inch, X70 pipe that is 0.429 wall or greater.

The pipeline was designed to allow for in-line inspection, referred to as pigging. This pigging includes operational pigging as well as in-line inspection.

Uncased crossing of highways and railroads were designed in accordance with the Kern River Engineering Design Manual. This standard is based on Appendix G-15 of the Gas Piping Technology Committee (GPTC) Guide for Gas Transmission and Distribution Piping Systems and considered both live (vehicular) and dead (soil) loads.

17 Kern River Gas Transmission Company Petition for MAOP Special Permit

Compressor Station Evaluation Kern River conducted an evaluation of the compressor station equipment and piping to determine the rating of each component, to ensure that the station can be operated safely and reliably at pressures up to 1,350 psig. The results of the evaluation are described below and summarized in Table 6.

The evaluation began with an analysis of the original design basis for each component, including valves, valve actuators, fittings, flanges, gaskets and bolting, compression, pig traps and associated piping, pressure regulators and meters. The analysis revealed that many of the components were rated for service at the increased pressure. Components not meeting the requirements for design at the higher pressure were evaluated for possible re-rating under applicable pressure vessel or other code, and where re-rating was infeasible, the component will be replaced.

Pressure vessels at Goodsprings and Fillmore compressor stations and most meter stations are rated to 1,250 psig. These vessels will either be up-rated to 1,350 psig, replaced with a new vessel rated to 1,350 psig, or process control will be implemented to ensure that the station inlet pressures do not exceed the design basis of 1,250 psig. This will be accomplished through monitoring gradients coupled with alarms and unit shutdown/bypass logic.

The components, the findings of the evaluation and actions to be taken are summarized in Table 6, on the following page.

18 Kern River Gas Transmission Company Petition for MAOP Special Permit

Table 6 – Summary of Station Component Evaluation

Compressor Station Summary of Ratings and Specifications For High Pressure Gas Piping and Equipment Coyote Muddy Creek Painter Anchutz Salt Lake Elberta Fillmore Veyo Dry Lake Goodsprings Component or Creek Compressor Compressor Compressor Compressor Compressor Compressor Compressor Compressor Compressor Equipment Compressor Station(1) Station Station Station (3) Station(4) Station(1) Station(5) Station Station(1) Station(2) 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 Valves (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 1,480 Flanges (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) (ANSI 600) 1,250/1,350 1,350 psig 1,350 psig 1,350 psig 1,350 psig 1,350 psig 1,250 psig Not Not Not psig ASME Filter Separators ASME Sec ASME Sec ASME Sec ASME Sec ASME Sec ASME Sec Applicable Applicable Applicable Sec VIII Div VIII Div 1 VIII Div 1 VIII Div 1 VIII Div 1 VIII Div 1 VIII Div 1 1 1,750 & 2,250 & 1,500 psig 2,000 psig 1,350 psig 1,600 psig 1,600 psig 1,600 psig 1,500 psig 1,600 psig Compressor 1,600 psig 1,750 psig MWP MWP MWP MWP MWP MWP MWP MWP MWP MWP 1,250/1,350 1,250/1,350 1,250 psig 1,350 psig 1,350 psig psig ASME Not Not Not Not Not psig ASME Coolers ASME Sec ASME Sec ASME Sec Sec VIII Applicable Applicable Applicable Applicable Applicable Sec VIII VIII Div 1 VIII Div 1 VIII Div 1 Div 1 Div 1 MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; MSS-SP75; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; ASTM-105; Fittings ASTM ASTM ASTM ASTM ASTM ASTM ASTM ASTM ASTM ASTM A234WPB A234WPB A234WPB A234WPB A234WPB A234WPB A234WPB A234WPB A234WPB A234WPB

1,250/1,350 1,250/1,350 1,250 psig 1,350 psig 1,350 psig psig Not Not Not Not Not psig Extrusions MSS-SP75 MSS-SP75 MSS-SP75 MSS-SP75 Applicable Applicable Applicable Applicable Applicable MSS-SP75 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8

1,200/1,250 1,200/1,250 1,200/1,250 1,200/1,250 1,200/1,250 1,250 psig 1,250 psig 1,250 psig 1,250 psig 1,250 psig psig psig psig psig psig Launchers/Receivers ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D API 6D

1,450/1,500 1,450/1,500 1,450/1,500 1,450/1,500 1,450/1,500 Valve Operators 1,440/1,450/ 1,440 psig 1,440 psig 1,440/1,450/ 1,440/1,450/ psig psig psig psig psig 1,500 psig 1500 psig 1,500 psig Not Not 1,250 psig Not Not Not Not Not Not Not Bottles Applicable Applicable MWP Applicable Applicable Applicable Applicable Applicable Applicable Applicable API 5L API 5L API 5L API 5L API 5L API 5L API 5L API 5L API 5L API 5L Pipe ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106 ASTM A106

ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 ASME B31.8 Appendix F Appendix F Appendix F Appendix F Appendix F Appendix F Appendix F Appendix F Appendix F Appendix F Branch Connections Section Section Section Section Section Section Section Section Section Section 831.42 831.42 831.42 831.42 831.42 831.42 831.42 831.42 831.42 831.42

Denotes standard requirements not met at 1,350 psig Foot notes: (1) The three original mainline compressor stations (Muddy Creek, Fillmore & Goodsprings) were designed and tested to a 1,250 psig MAOP. The additions to these compressor stations during the recent expansion were all designed to a 1,350 psig MAOP. The only exception for the expansion was that the two inlet filter separators added at the Goodsprings compressor station have a maximum working pressure (MWP) of 1,250 psig. (2) The Coyote Creek compressor station is located at high elevation in southwest Wyoming. Since the strength test of the high pressure piping was scheduled during the winter months, it was decided to complete this test using nitrogen. Because of the limitations for using a gas test, the actual test was able to meet the requirements of a 1,250 psig design but not a 1,350 psig design. (3) In 2005 there was a section of 14 inch pipe tested for a modification to relocate a check valve. The pipe was tested for a specified range of 1,875 to . 2,025 psig. The actual test range was 1,984 to 2,015 psig. The test would have to be 2,025 psig for a 1,350 psig MAOP. (4) To help with a California gas emergency, temporary compression was installed prior to the recent expansion. When the station was re-built for the expansion, a small portion of the header system (42 inch) was left in place that had been designed and tested for a 1,250 psig MAOP. (5) To help with a California gas emergency, temporary compression was installed prior to the recent expansion. When the station was re-built for the expansion, a large portion of the header system (42 inch) and one of the compressor units with its unit piping was left in place that had been designed and tested for a 1,250 psig MAOP.

19 Kern River Gas Transmission Company Petition for MAOP Special Permit

Meter Station Evaluation Kern River conducted an evaluation of the meter station equipment to determine the rating of each component, to ensure the station can be operated safely and reliably at pressures up to 1,350 psig.

The evaluation began with an analysis of the original design basis for each component, including valves, valve actuators, fittings, flanges, gaskets and bolting and associated piping, pressure regulators and meters. The analysis revealed that many of the components were rated for service at the increased pressure. Components not meeting the requirements for design at the higher pressure were evaluated for possible re-rating under applicable pressure vessel or other code, and where re-rating is infeasible, the component will be replaced.

Thirty-two of the 48 meter stations on the Kern River system are included in the scope of the permit application to up-rate the MAOP of these meter stations to 1,350 psig. The detailed review of the design and testing of these meter stations indicate that a majority of the piping material would meet an increased MAOP of 1,350 psig. All of the hydrostatic testing was based on a meter station design pressure range from 1,200 to 1,250 psig. Nine of the meter stations have ASME code vessels with a maximum working pressure (MWP) less than 1,350 psig and will need to be up-rated, replaced or use pressure limiting controls to protect the equipment. Detailed results of this analysis are available at the Kern River office.

Pipe Fittings, Valves and Flanges Pipe fittings, valves and flanges were designed and purchased in accordance with company Engineering Design Specifications. In all cases, the valves and flanges were ANSI Class 600 and have an allowable operating pressure of 1,480 psig. Small pipe fittings were manufactured in accordance with ASME B16.9 and large fittings with MSS SP-75; and company Engineering Design Specifications. Valves were manufactured in accordance with API 6D and company Engineering Design Specifications. High test flanges were manufactured in accordance with MSS SP-44 and normal flanges in accordance with ASME B16.5: and company Engineering Design Specifications. These materials were pressure tested in accordance with the applicable standards.

SCADA and System Control Kern River’s pipeline system was originally designed to be a fully automated system. Real time data is exchanged between the controlling devices at field facilities and the SCADA system at regular intervals. Alarms are annunciated in the SCADA system and are acknowledged and acted upon by Kern River personnel as needed. The alarms are generally configured to warn the operating personnel that a parameter such as pressure, temperature, flow rate, etc. is nearing a critical value. In the event action is not taken or the action taken does not keep the parameter from reaching the critical limit, automatic shutdowns will go into effect to assure the operating limits are maintained. A number of the key alarms and shutdowns for compressor station controls are summarized in Table 7.

20 Kern River Gas Transmission Company Petition for MAOP Special Permit

Table 7 – Example Unit and Station Control Scheme

Alarm Or Alarm Description Event Area Event Trigger Shutdown Fire detect - UV/IR Shutdown Station Field device Heat detect Shutdown Station Field device Station power gas low pressure Shutdown Station Field device Control system low battery voltage Shutdown Station Field device Vent valve cracked Shutdown Station Field device ESD pull buttons - 7 locations Shutdown Station Operator owner throughout the plant Discharge valve closed Shutdown Station Field device Filter/separator hi hi level (most Shutdown Station Field device stations) Filter/separator hi hi level (most Alarm Station Field device stations) Station discharge temperature hi hi Shutdown Station Field device Station discharge temperature hi Alarm Station Field device Discharge valve failed to open Shutdown Station Field device Suction pressure hi hi Shutdown Station Field device Suction pressure hi Alarm Station Field device Suction pressure lo lo Shutdown Station Field device Suction pressure lo Alarm Station Field device Discharge pressure hi hi Shutdown Station Field device Discharge pressure hi Alarm Station Field device Discharge pressure lo lo Shutdown Station Field device Discharge pressure lo Alarm Station Field device 20% lel gas detection, compressor Alarm Station Field device building 40% lel gas detection, compressor Shutdown Station Field device building Watchdogs, hardwired backup Control system Shutdown Station system internal Watchdogs, various monitoring of Control system Alarm Station actions and communications internal

There are pressure relief valves in the Kern River system at Muddy Creek, Fillmore, Veyo and Goodsprings compressor stations. Pressure is controlled at the other stations by compressor controls and pressure switches. The unit programmable logic controllers will maintain the gas pressure up to 1,333 psig on the pipeline and have overpressure shutdowns that will be set at or below 1,386 psig (104% of the pipeline MAOP).

Shown below in Figure 2 is a diagram of the Elberta compressor station. This diagram shows some of the information available to the operating personnel at the station and in gas control.

21 Kern River Gas Transmission Company Petition for MAOP Special Permit

Figure 2 – Depiction of Control Scheme at the Elberta Compressor Station

Welding The line pipe was welded in accordance with company Construction Specification for mechanized welding and with stick welding. Welders were qualified in accordance with company specification. These specifications included requirements to follow API 1104.

All stick welds (100%) were non-destructively tested according to Kern River’s Construction Specifications and API 1104. All mechanized welds (100%) were tested according to a Kern River non-destructive testing procedure for ultrasonic inspection that followed API 1104. All weld repairs were completed according to Kern River Construction Specifications and API 1104. Double jointing of pipe at the pipe mills was completed according to Kern River Construction Specifications and API 1104. A third-party inspected each step of the double- jointing welding process. The welding procedures used for both stick and automated welding had been previously qualified by Kern River.

Construction Pipe was transported in accordance with Kern River Construction Specifications. These specification are in accordance with API 5L1 for railroad transportation and API 5LW for marine transportation. The pipeline was buried in accordance with Kern River Construction Specifications with a minimum of 36 inches of cover.

22 Kern River Gas Transmission Company Petition for MAOP Special Permit

Field bending of pipe was in accordance with Kern River Construction Specification. The bends were made cold and only long radius smooth machine bends were permitted. No bending of circumferential welds was allowed.

Pipe damaged during construction was repaired or replaced in accordance with Kern River Construction Specification. Each imperfection or damage that impaired the serviceability of a length of steel pipe was repaired or removed.

The original line was coated with a minimum of 14 mils of FBE corrosion coating. The loop line was coated with a two-layer system consisting of a minimum of 12 mils of FBE and 8 mils of abrasion-resistant overlay FBE. Additional concrete coating was installed at highways, railroads, rivers and most streams, canals and wetlands in both open cut and horizontal directionally drilled and bored installations.

The installation of pipelines parallel to power lines used specific engineering designs from studies conducted on the system to address alternating current (AC) mitigation for safety during construction, operation and maintenance.

Quality assurance and quality control was provided through the use of the Kern River Construction Specifications. The specifications included quality control through company and third-party inspection. The specifications included quality assurance throughout the construction process and documentation to confirm that each construction step is completed properly. The construction steps included in the specifications were:

• Pipe hauling and stringing. • Field bending. • Welding. • Non-destructive examination of girth welds. • Field applied coating. • Coating integrity tests. • Lowering the pipeline into the ditch. • Padding and backfilling.

Pressure Testing The pipeline system was pressure tested after construction in accordance with company Construction Specifications and 49 CFR 192, Subpart J. There were no test failures during construction of any of the Kern River facilities.

Approximately 46% of the mainline and 61% of the loop line mileage was tested to 100% SMYS or greater. Approximately 90% of the mainline and 95% of the loop line was tested to 94% or greater. The minimum test pressure was 90% SMYS, with one exception. The exception is a 0.57 mile segment on the loop line in a Class 1 area where the test pressure was between 87% and 90% SMYS.

23 Kern River Gas Transmission Company Petition for MAOP Special Permit

The broad range of test pressures achieved is a result of the topography. The pipeline system traverses through very significant terrain changes with elevations ranging from 847 feet to 8,591 feet above sea level, making pressure testing within a narrow range more difficult than in flat terrain. Kern River analyzed the margin between the pressure test as conducted and the operating pressure along the system, under a hypothetical 250 MMcf/d design case at 1,333 psig for a potential future expansion. The purpose of this was to evaluate to what extent a margin of 1.25 times the new MAOP was achieved for Class 1 pipe, and 1.5 times the new MAOP in Class 2 and 3. Virtually all of the line pipe will be operated with the applicable margin of safety as shown below in Table 8:

Table 8 - Summary of Estimated Operating Pressure Times Applicable Hydrotest Factor to Original Hydrotest Pressure for Next Potential Expansion of the Kern River System

Compressor Distance Pressure is Length that the Operating Applicable Test Station Mainline or Greater than Current Pressure Times Applicable Factor Based on Discharge Loop Line 1200 PSIG MAOP Test Factor is Greater than the Class Location Side (Miles) Hydro Test Pressure (Miles)

Muddy Creek Mainline 23.0 1.25 0.0 Muddy Creek Loop Line 23.0 1.25 0.0 Coyote Creek Mainline 0.0 1.25 0.0 Coyote Creek Loop Line 0.0 1.25 0.0 Salt Lake Mainline 39.0 1.25 & 1.50 4.4 Salt Lake Loop Line 39.0 1.25 & 1.50 4.5 Elberta Mainline 22.8 1.25 0.1 Elberta Loop Line 22.8 1.25 0.0 Fillmore Mainline 25.1 1.25 0.2 Fillmore Loop Line 25.1 1.25 0.7 Veyo Mainline 41.8 1.25 0.5 Veyo Loop Line 41.8 1.25 0.0 Dry Lake Mainline 0.0 1.25 0.0 Dry Lake Loop Line 0.0 1.25 0.0 Goodsprings Mainline 15.0 1.25 1.0 Goodsprings Loop Line 15.0 1.25 1.3 Totals 333.4 12.6

Note: Even though Kern River would plan to implement an approved MAOP petition immediately, Kern River also intends to pursue customer interest in a system expansion that would further take advantage of the benefits of a higher MAOP. The above analysis is based on a 250 MMcf/d expansion of the Kern River system. Larger expansions where the compressor stations discharges would furher increase toward the new MAOP would result in more pipeline miles being operated higher than the original hydrotest pressure times the applicable factor for the class location.

24 Kern River Gas Transmission Company Petition for MAOP Special Permit

Equipment Equipment was designed in accordance with company Engineering Design Specifications. Compressor station equipment was designed to withstand thermal and mechanical stresses.

The company maintains a SCADA system to monitor operating conditions and control the operation of the pipeline. Necessary changes to procedures will be implemented prior to placing the pipeline in service at the new MAOP.

Automation will be added to seven existing mainline valves. With this addition, all mainline valves in and adjacent to HCAs will be automated. The automated valves can be operated by gas control or locally. Volume bottles are installed at all of the automatic valves to provide operation in the event the pipeline pressure is too low.

Remote control valves were installed at all receipt points as well as at all delivery and interconnect points. These valves can be remotely operated from gas control or operated locally.

25 Kern River Gas Transmission Company Petition for MAOP Special Permit

MANAGING TIME-DEPENDENT THREATS

Internal Corrosion Control The quality of gas received will be in accordance with Kern River’s Tariff, currently Tariff Sheet Number 84, which specifies maximum limits of:

• Seven pounds water vapor per million cubic feet. • 3% CO2 • 0.25 grains H2S per 100 cubic feet of gas. • Hydrocarbon dew point of 15 Degrees F. • 0.2% O2. • 4% total inerts, (CO2 and N2),.

Hydrocarbons and H2S are continuously monitored at all receipt points. Water vapor is monitored at receipt points where historical experience indicated a potential for water being present in the gas. The composition of the blended gas stream is continuously monitored at several mainline locations. If the gas quality exceeds the acceptance criteria shown in Table 9, below, an alarm is sent to gas control through the SCADA system. In the event of these exceedances, company personnel will work with the upstream parties to achieve compliance with the gas quality requirements of the tariff. In the event that compliance cannot be achieved, the company will shut in the receipt point.

The mainline and loop line are internally coated with a liquid epoxy flow liner coating. The specified mil thickness of this coating was 1.5 mils. However the nature of the solids in this product resulted in this coating being 2-3 mil thick.

Table 9 – Gas Quality Monitoring

Gas Monitoring Constituent Type of Eqiuipment Frequency Acceptance Criteria

HC Dew Point Chromatograph Continuous 15° F

H2S Sulfur Analyzer Continuous 0.25 grains 100 cubic foot

CO2 Chromatograph Continuous 3% by volume

H2O Monitor Continuous 7 lbs per 1 million cubic foot

26 Kern River Gas Transmission Company Petition for MAOP Special Permit

External Corrosion Control Pipe was cleaned before application of coating per company Engineering Design Specifications.

External coating for below ground pipe was with mill-applied fusion-bonded epoxy coating per company specifications for plant-applied coating at 14 to 23 mils. Coating was inspected by a third party. The Kern River Construction Specifications addressed temperature control, adhesion, moisture permeation, bending, coating imperfections and coating repair.

The manufacturer of all external coatings was 3M. The mainline was coated with a minimum of 14 mils of 3M 206N FBE. The loop line was coated with a two-layer system of a minimum of 12 mils of 3M 6233 FBE followed by a minimum of 8 mils of 3M 6152 abrasion-resistant overlay FBE. The coating specifications have a temperature rating of 149 degrees F on the mainline, and 230 degrees F on the loop line.

All girth weld coatings were field-applied with the same FBE powder coatings and at the same thickness as the respective pipe involved. These coatings were applied per company Construction Specification, which addressed temperature control, adhesion, moisture permeation, bending, coating imperfections and coating repair. In addition, this specification addressed holiday detection and coating repair. Repairs to the coating on both pipe and girth welds were done with either melt sticks or two-part liquid epoxy.

Coating of aboveground pipe was applied per company Construction Specification. This specification covered coating system selection, surface preparation, and coating application.

Concrete coating was installed at highways, railroads, rivers and most streams, canals and wetlands in both open cut and horizontal directionally drilled and bored installations.

An interference current survey is performed and checked annually and as new foreign lines are installed. These surveys are in accordance with company procedures and NACE RP0177- 2000.

Cathodic protection was placed into service within one year of the commencement of operations of the mainline. Cathodic protection for the expansion was tied into the existing system and was activated as the expansion was constructed.

A close interval survey will be completed in HCAs within one year of placing the pipeline in service at the higher pressure and on the remainder of the system within four years of placing the pipeline in service at the higher pressure. This survey will be in accordance with the company O&M Manual.

Between 2004 and 2007, a baseline ILI with a high resolution MFL tool was run through the piggable portions of the system (99.7% of the entire pipeline system). There are approximately 4.05 miles of pipe included in this petition that will be assessed by a technology other than ILI. These include short sections on the Anschutz, Harry Allen,

27 Kern River Gas Transmission Company Petition for MAOP Special Permit

Riverton, Centennial and Reid Gardner laterals. It is anticipated that these will be assessed using direct assessment following the procedures set forth in the company’s Integrity Management Plan.

The results of the baseline ILI are summarized in Table 10, below. In general, the ILI runs confirm that the pipe is in excellent condition. Verification digs from 2004 through 2006 have shown that many anomalies called out by the tool are mid-wall, mill-related anomalies. Mill anomalies including mid-wall anomalies are not an integrity threat since they have survived the post construction pressure test.

Approximately 88% of the anomalies called external are less than 10% in depth. Through 2006 there had been only two actionable anomalies. One was classified as an “immediate” in a non-HCA. It was called as a 65% external anomaly and upon excavation was verified as a mid-wall mill anomaly not associated with corrosion. Inactive external corrosion related wall loss has been identified during the digs; the worst being 45%. A Clock Spring was applied at this location. The other actionable anomaly was classified as a “scheduled” in a non-HCA. It was called as a 59% external anomaly, and was verified as 35% external inactive corrosion. A Clock Spring was installed.

Indications on the ILI logs selected for verification and actionable anomaly digs are depicted on Figure 3, relative to the new MAOP. The indications were placed on the figure using length, depth and predicted burst pressure as calculated by ASME Modified B31G. All short- length anomalies, called as pitting or general corrosion, had predicted burst pressures greater than the 1.39 MAOP, meaning that the anomalies would have survived a Subpart J hydrotest to 100% SMYS. The longer anomalies, called as cluster corrosion, were all less than 20% in depth. All of the clusters had predicted burst pressures greater than 1.25 MAOP.

28 Kern River Gas Transmission Company Petition for MAOP Special Permit

Figure 3 – Baseline ILI Anomalies Investigated in Confirmation Digs as Compared to Threshold Levels as Multiples of MAOP

100% 90% 80% 70% 60% 50% 40%

Depth (%) (%) Depth 30% 20% 10% 0% 0 5 10 15 20 Length (inches)

1333 MAOP 1466 1.1 MAOP 1666 1.25MAOP 1853 1.39MAOP 2248 1878 1899 1687 1760 2271 1898 1896 1894 1902 1744 1511 1298 1824 1828 1747 1706 1846 1828

Key - The triangles are 2004, the diamonds are 2005 and the squares are 2006. A solid entry is one where a corrosion anomaly was found. An open entry is one where the anomaly was either not confirmed or was determined to be a mid-wall anomaly.

Of the 20 digs on metal loss anomalies, made from 2004 through 2006, there was no visible feature or the results of ultrasonic testing were inconclusive for nine of the anomalies called by the ILI tool. The locations where there was no visible feature or where the results were inconclusive are believed to be mid-wall anomalies; these anomalies are not associated with internal or external corrosion.

Internal or external features were identified with 11 of the digs. In all external cases the corrosion was determined to be inactive. Analysis indicates that all internal anomalies are mill related. In all instances with two exceptions, the features as found had depths less than called out in the ILI logs. In the one case, the as-found feature had a depth of 23% as compared to 22% on the logs, and in the other 45% as compared to 44% on the logs. These results indicate that the ILI inspection and analysis provide conservative results.

The deepest cluster corrosion found was 14%. To grow an anomaly from 14% to become an anomaly requiring immediate action, the equivalent of 1.1 MAOP, requires growth in depth to 38%, an additional loss of 103 mils (((38-14)/100)*0.429). If one assumes a conservative growth rate of 4 mils per year, this yields 25.75 years. The use of 4 mils is a reasonable assumption knowing that the pipe is coated with FBE coating that has been demonstrated to

29 Kern River Gas Transmission Company Petition for MAOP Special Permit

be effective as evidenced in excavations made since installation. In addition, the company will verify the integrity of the coating and cathodic protection system by conducting a close interval survey over a four-year period following approval of the petition. To grow an anomaly from 14% to the equivalent of 1.25 MAOP requires growth in depth to 25%, an additional loss of 47 mils (((25-14)/100)*0.429). If one assumes a conservative growth rate of 4 mils per year, this yields 11.75 years.

The above analysis and Figure 3 demonstrate that the use of ILI response criteria more conservative than the 1.1 MAOP as “immediate” and 1.25 MAOP as “one year scheduled” criteria applied in prior granted MAOP special permits is unwarranted. The new criteria proposed by PHMSA that adds an additional level of conservatism in Class 2 and 3 locations, will result in hundreds of additional digs for features as shallow as 3%, which will be primarily mill-related anomalies. We believe this is not only impractical and provides no safety benefit, but that there would be significant additional risk from the unnecessary digs. Kern River requests the Special Permit Grant use the anomaly evaluation and response criteria granted in the Alliance Pipeline and the Maritimes and Northeast Pipeline Special Permits. Kern River also requests that response time frames will be managed in accordance with the time frames specified in the ILI Response Procedure contained in the Kern River O&M Manual.

Re-inspection with ILI will be performed at the interval determined in accordance with ASME B31.8S or the pipeline safety regulations, whichever is less.

30 Kern River Gas Transmission Company Petition for MAOP Special Permit

Table 10 – Summary High Resolution MFL Tool Runs and Findings

Miles Actionable Number Number of Assessed Anomalies of Verification Findings Required Digs Digs 2004 Original 60 0 0 5 1 inactive external Line 4 not found Loop Line 60 0 0 2 1 plain dent 1 not found Laterals 0 0 0 0 2005 Original 182 0 0 5 4 inactive external Line 1 not found Loop Line 155 0 0 1 1 not found Laterals 35 0 0 0 2006 Original 132 1 1 1 1 inactive external Line 1 mid-wall Loop Line 103 0 0 3 3 internal Laterals 26 0 0 3 2 inactive external 1 mid-wall 2007 Original 309 5 In In Progress Line Progress Loop Line 309 1 In In Progress Progress Laterals 0 0 0 In Progress

31 Kern River Gas Transmission Company Petition for MAOP Special Permit

Kern River conducted additional analyses to further demonstrate its confidence in applying Modified B31G and the anomaly evaluation and response criteria used in the Alliance Pipeline and Maritimes and Northeast Pipeline Special Permit Grants. In general, the depths and lengths called on the ILI logs and the as found in excavations are very close in value.

The anomaly depths as called on ILI logs were greater than depths as found in excavations, with two exceptions. As stated above, in those two exceptions, the as found values were deeper than the values on the ILI logs by one percent of wall thickness, or approximately 2.3% of the values measured on ILI logs. It is particularly noteworthy that the comparative measurements are well within the ILI vendor specification of +/- ten percent of wall thickness. The comparison of called depths versus as found depths is depicted in Figure 4.

Figure 4 – Comparison of Depths Called on ILI Logs versus Depths As Found

70%

60%

50%

40%

30% Found As Depth

20%

10%

0% 0% 10% 20% 30% 40% 50% 60% 70% Depth As Called on ILI Logs

Key- Triangles are for 2004, circles are for 2005 and diamonds are for 2006.

32 Kern River Gas Transmission Company Petition for MAOP Special Permit

Anomaly lengths as called were also very similar to as-found values; the number of over- calls equaling the under-calls.4 The comparison of called lengths versus as-found lengths is depicted in Figure 5. The largest under-call on a clustered corrosion was a 17.5% difference between the ILI called length and the as-found feature.

Figure 5 – Comparison of Lengths Called on ILI Logs versus Lengths As Found

16.0

14.0

12.0

10.0

8.0 th As Found g Len 6.0

4.0

2.0

0.0 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 Length As Called on ILI Logs (Inches)

Key- Triangles are for 2004, circles are for 2005 and diamonds are for 2006.

It can be seen from the graphical comparisons of the ILI called depths and lengths versus the as-found values that there is a high degree of similarity. This further demonstrates that values derived from ILI logs used with Modified B31G and the criteria in the Alliance and M&N Special Permit grants provide a technically sound and sufficiently conservative basis for operation at 80 % SMYS.

4 An over-call is where the anomaly as found during the excavation is smaller than the size called in the ILI log and an under-call is the converse.

33 Kern River Gas Transmission Company Petition for MAOP Special Permit

Stress Corrosion Cracking Coating systems utilizing FBE coating were installed on the below ground pipe in accordance with specifications as stated in this petition. The pipeline system should not be susceptible to stress corrosion cracking (SCC) due to the fact that FBE coating was installed. However, if the pipeline is exposed and the coating is found to be disbonded or otherwise damaged, a direct examination of the pipe will be performed in accordance with company Integrity Management Plan.

The coating system has a temperature rating of 149 degrees F maximum on the mainline, and 230 degrees F on the loop line. The temperature of gas in the pipeline will generally be less than 120 degrees F. Historically, all station discharge temperatures have been below 120 degrees F, with the exception of Veyo and Goodsprings compressor stations which frequently reach 130 degrees F. Modeling of the system and compression at the higher pressures indicates that the Veyo and Goodsprings compressor stations will be similar to the current system. Even at these temperatures the coatings used have a history of good performance and will be operated at temperatures less than the temperature rating of the coating materials. High temperature shutdowns of compressor units are set to protect the thicker coatings in the compressor stations. Gas after-coolers are installed where necessary to protect the pipeline coatings.

The close interval survey will help confirm that the soil is conducting current and the pipe is receiving adequate cathodic protection. See the External Corrosion Section above.

34 Kern River Gas Transmission Company Petition for MAOP Special Permit

MANAGING TIME-INDEPENDENT THREATS

Mechanical Damage The pipe design provided for fracture control. This was provided by the pipe specification with Charpy V-notch tests that meet the pipe specification. See the pipe design section of this petition.

Puncture resistivity is calculated to be 65 tons of force from the equipment for this pipe. Refer the pipe design section of this petition.

Pipe inspection at the site during construction was in accordance with company specifications and dents greater than 2% of the pipe diameter were removed.

Pipeline marking will be line of sight, in accordance with company O&M Manual.

The damage prevention program developed for the Integrity Management Program will be implemented for this pipeline.

Kern River is a member of the Common Ground Alliance and will implement the appropriate measures and best practices identified by that organization applicable for pipelines.

Weather and Outside Force The company has identified and monitors known earthquake faults along the system. These areas are being reviewed to evaluate the effect of operation at higher stress levels to evaluate the overall impact of combined loading. It is anticipated that the evaluation will be completed during the timeframe in which PHMSA will be reviewing and evaluating this petition. Recommendations, where applicable, to mitigate effects of operation at the higher stress levels will be discussed with PHMSA personnel.

Flooding has not been an issue except for some major washes where erosion control structures have been installed to protect the pipelines. A periodic inspection and monitoring program is in place per the company O&M Manual.

Incorrect Operations The company has an O&M Manual of procedures. The procedures are routinely reviewed and kept current. The company uses qualified persons to perform all of the O&M activities as stated in the procedures. These persons are qualified in accordance with the company’s Operator Qualification Program. The company will implement its quality assurance program as described in the IMP Quality Assurance Plan for this pipeline.

35 Kern River Gas Transmission Company Petition for MAOP Special Permit

REFERENCED STANDARDS, SPECIFICATIONS AND PROCEDURES

Several Engineering Standards and Construction Specifications as well as Operations and Maintenance Procedures, Corrosion Control Procedures and Integrity Management Program Procedures are referenced in this petition. Standards, specifications and procedures are periodically reviewed and updated as appropriate. These documents are available for review by PHMSA staff.