Company: Southern California Gas Company (U 904 G) Proceeding: 2016 General Rate Case Application: A.14-11-XXX Exhibit: SCG-06 SOCALGAS DIRECT TESTIMONY OF PHILLIP E. BAKER UNDERGROUND STORAGE November, 2014 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA     TABLE OF CONTENTS I.  INTRODUCTION ......................................................................................................1  A.  Summary of Costs................................................................................................1  B.  Summary of Activities .........................................................................................2  C.  Risk Management Practices in Storage .............................................................5  1.  Risk Assessment............................................................................................6  2.  Risk Mitigation Alternatives Evaluation....................................................6  3.  Risk Reduction Benefits ...............................................................................7  4.  Integration of Risk Mitigation Actions and Investment Prioritization ...7  5.  Investment Included in Request to Support Risk Mitigation ..................7  D.  Support To/From Other Witnesses ....................................................................8  II.  NON-SHARED COSTS .............................................................................................8  A.  Introduction .........................................................................................................8  B.  Underground Storage – Routine O&M .............................................................8  1.  Criticality of Storage and Underlying Activities .......................................9  2.  Cost Forecast Methodology .......................................................................13  3.  Cost Drivers ................................................................................................14  C.  New Environmental Regulatory Balancing Account O&M Costs ................15  1.  Description of Costs and Underlying Activities .......................................16  2.  Cost Forecast Method ................................................................................16  3.  Cost Drivers ................................................................................................16  D.  Storage Integrity Management Program ........................................................16  1.  Introduction ................................................................................................17  2.  General Description of Work ....................................................................22  3.  Cost Forecast Methodology .......................................................................24  4.  Cost Drivers ................................................................................................24  III.  CAPITAL COSTS ....................................................................................................24  A.  Introduction .......................................................................................................24  B.  Storage Compressors.........................................................................................26  1.  B1-Goleta Units #2 and #3 Overhauls ......................................................27  2.  B2-Blanket Projects....................................................................................28  C.  Storage Wells .....................................................................................................28  1.  C1-Wellhead Valve Replacements ............................................................31  PEB-i Doc #292223    2.  C2-Well Tubing Replacements .................................................................31  3.  C3-Wellhead Leak Repairs .......................................................................32  4.  C4-Well Inner-String Installations ...........................................................33  5.  C5-Submersible Pump Replacements ......................................................33  6.  C6-Well Stimulations/Re-Perforations .....................................................34  7.  C7-Well Gravel Packs ................................................................................34  8.  C8-Well Re-Drills .......................................................................................35  9.  C9-Well Replacements ...............................................................................35  10.  C10-Well Plug and Abandonments ..........................................................37  11.  C11-Storage Blanket Projects ...................................................................38  12.  C12-Cushion Gas Purchases (Honor Rancho Expansion)......................39  13.  C13-Storage Integrity Management Program .........................................39  D.  Storage Pipelines ................................................................................................42  1.  D1-Valve Replacements .............................................................................44  2.  D2-Aliso Pipe Bridge Replacement ...........................................................44  3.  D3-Aliso Injection System Debottlenecking .............................................45  4.  D4-Aliso Canyon Piping Improvements ...................................................45  5.  D5-Playa del Rey Withdrawal Debottlenecking ......................................46  6.  D6-Pipeline Blanket Projects.....................................................................47  E.  Storage Purification Systems ............................................................................47  1.  E1-Aliso Canyon Dehydration Upgrades .................................................48  2.  E2-Honor Rancho Dehydration Upgrades ...............................................49  3.  E3-Goleta Dehydration Upgrades.............................................................50  4.  E4-Purification Blanket Projects ..............................................................50  F.  Storage Auxiliary Systems ................................................................................51  1.  F1-Aliso Central Control Room Modernization......................................52  2.  F2-Aliso Main Plant Power Line Upgrade ...............................................52  3.  F3-Aliso Sesnon Gathering Plant Project ................................................53  4.  F4-Auxiliary Systems Blanket Projects ....................................................54  IV.  CONCLUSION .........................................................................................................54  V.  WITNESS QUALIFICATIONS ..............................................................................55    PEB-ii Doc #292223    LIST OF APPENDICES Appendix A: Glossary of Acronyms..............................................................................................A-1 Appendix B: Underground Storage of Natural Gas ....................................................................B-1 Appendix C: Downhole Schematic and Wellhead Diagram .......................................................C-1   LIST OF TABLES Table PEB-1 – Test Year 2016 Summary of Total O&M Costs……………………………...1 Table PEB-2 – Test Year 2016 Summary of Total Capital Costs……….………...……..…..1 Table PEB-3 – Descriptive Statistics of Storage Fields.…………………..………………......5 Table PEB-4 – Non-Shared O&M Summary of Costs..…………………..…………………..8 Table PEB-5 – Non-Shared Routine O&M Costs…………………………..…………………9 Table PEB-6 – NERBA Costs for Storage, Transmission and Gas Engineering..................16 Table PEB-7 – Storage Integrity Management Program O&M Costs………..………...….17 Table PEB-8 – Number of Major Well Integrity Workovers by Year…………….....…….19 Table PEB-9 – SIMP O&M Cost Detail………………………………………………….......24 Table PEB-10 – Capital Expenditures Summary of Costs.....................................................25 Table PEB-11 – Capital Expenditures for Storage Compressors...….………….……….....26 Table PEB-12 – Capital Expenditures for Storage Wells………………………...………....29 Table PEB-13 – SIMP Capital Cost Detail...............................................................................42 Table PEB-14 – Capital Expenditures for Storage Pipelines…………………………..……43 Table PEB-15 – Capital Expenditures for Purification Systems……………………………47 Table PEB-16 – Capital Expenditures for Storage Auxiliary Systems…………………..…51 LIST OF FIGURES Figure PEB-1 –Transmission and Storage System…..…………...…………...………………3 Figure PEB-2 – System Send-out December 2013…...…………...…………….....................10 Figure PEB-3 – Aerial View of Playa Del Rey Underground Storage Field…..…...………11 Figure PEB-4 – Non-Shared O&M Summary of Routine Costs.…...………………………14 Figure PEB-5 – Age Distribution of Storage Wells……………………………......................20 Figure PEB-6 – Historical and Forecasted Total Capital by Year...…..………....................25 Figure PEB-7 – Historical and Forecasted Storage Compressor Capital……......…...…….27 Figure PEB-8 – Historical and Forecasted Wells Capital………............................................30 Figure PEB-9 – Historical and Forecasted Storage Pipelines Capital….………...................43 Figure PEB-10 – Historical and Forecasted Purification Systems Capital…….……...........48 Figure PEB-11 – Historical and Forecasted Auxiliary Systems Capital.……….......…........51 PEB-iii Doc #292223    1 SUMMARY UNDERGROUND STORAGE O&M Total Non-Shared Total Shared Services (Incurred) Total O&M Thousands of 2013 Dollars 2013 Adjusted TY2016 Change Recorded Estimated $30,995 $40,181 $9,186 $0 $0 $0 $30,995 $40,181 $9,186 2 Thousands of 2013 Dollars UNDERGROUND STORAGE CAPITAL Total Capital 3 2014 2015 2016 $71,429 $74,270 $90,523 The funding summarized above and described in my testimony is reasonable and 4 represents the required Operations and Maintenance (O&M) expenses and capital investments 5 for Southern California Gas Company’s (SoCalGas or the Company) underground storage 6 facilities to: 7 8  Maintain the safety, integrity, and effective operations of the natural gas storage system; 9 10  Provide a reliable and economic supply of gas for customers throughout the service territory, especially during periods of high demand; 11  Achieve compliance with operating and environmental regulations; and 12 13  Allow gas deliveries to be efficiently balanced throughout the overall transmission and distribution system. 14 Incremental O&M and capital funding associated with a new safety, system integrity, and 15 risk management initiative, the Storage Integrity Management Program (SIMP), is proposed for 16 underground storage wells. This program is modeled after SoCalGas’ Transmission Integrity 17 Management Program (TIMP), and a similar two-way balancing account process is requested.  18 The driving force behind the expenditure plan for Underground Storage is the objective 19 of SoCalGas and its employees to provide safe, reliable deliveries of natural gas to customers at 20 reasonable rates. O&M and capital investments also enhance and maintain the efficiency and 21 responsiveness of operations, extend the life of assets, and facilitate compliance with 22 governmental regulations.  PEB-iv Doc #292223   1 2 3 The O&M forecast was established using a five-year trend, with the addition of costs for the new safety and integrity management program for underground storage wells. The capital forecast was established using a five-year average. Added to the average are 4 remediation costs for the new safety and well integrity management program, plus costs to drill 5 new wells. 6 7 To understand this Test Year (TY) 2016 forecast in the proper context, the following factors should be considered: 8 9 10 11 12  Storage facilities consist of large complex interconnected industrial equipment that continues to age. The increasing volume, frequency and complexity of above-ground and below-ground maintenance work, and the declining availability of replacement components for older assets exposed to demanding field conditions, all continue to push operating costs higher. 13 14 15 16 17 18 19  Costs for storage activities have been increasing at a relatively consistent rate in recent years in support of safety, system integrity, maintenance, reliability, deliverability, and regulatory compliance objectives. Most increases have been driven by the intensity of traditional operating functions and routine work efforts across the board that are required to safely operate and maintain the aging infrastructure of the fields. As a result, there are very few “big ticket items” one can single out as primary contributors for the increasing O&M trend. 20 21 22 23 24 25  Problems associated with operating equipment, aging wells, compressors, and gas and liquid process/piping systems are difficult to predict. When unpredictable failures or preemptive repair situations occur, the associated mitigation costs for such occurrences can vary from year to year. This potential for peaks and valleys in spending trends supports a longer-term (five-year) trending methodology to forecast O&M costs.   26 27 28 29 30 31 32 33  In the future, pipeline integrity inspection requirements, the frequency and depth of regulatory audits and resulting compliance activities, additional focus on employee training, operator and supervisory qualification, employee turnover, expanded permitting and reporting requirements of regulatory agencies from new and existing environmental regulations such as storm water requirements, security enhancements, and chemical costs are all expected to increase operating expenses. These upward pressures further support the five-year trending methodology used to forecast O&M costs. 34 35 36  Capital costs for routine storage functions have been relatively consistent over the past five years. This supports the five-year methodology used to forecast costs for traditional baseline capital expenditures. 37 38  Underground storage reservoirs are dynamic geological assets where gas injection and withdrawal capabilities can change over time. These changes, which include PEB-v Doc #292223   1 2 3 4 5 6 natural well degradation and storage volume variability due to fluid extraction or intrusion, require ongoing studies and significant capital investments in new or replacement wells to maintain historical storage deliverability rates. The small number of new or replacement wells planned, the high cost of constructing these assets, along with an inconsistent historical trend for this particular sub-activity supports a zero-based approach to forecasting the capital costs for new wells. PEB-vi Doc #292223   1 SOCALGAS DIRECT TESTIMONY OF PHILLIP E. BAKER 2 UNDERGROUND STORAGE 3 I. INTRODUCTION 4 A. Summary of Costs 5 I sponsor the TY2016 forecasts of O&M costs for non-shared services, and forecasts of 6 capital costs for years 2014, 2015, and 2016, associated with Underground Storage for 7 SoCalGas.1 My cost forecasts support the Company’s goals of maintaining and enhancing public 8 and employee safety, as well as providing reliable supplies of gas for service delivery. 9 Underground Storage’s support of SoCalGas’ safety, integrity and reliability goals is discussed 10 in greater detail within this testimony. Tables PEB-1 and PEB-2 below summarize my 11 sponsored costs. 12 13 14 Table PEB-1 Southern California Gas Company Test Year 2016 Summary of Total O&M Costs UNDERGROUND STORAGE O&M Total Non-Shared Total Shared Services (Incurred) Total O&M 15 16 17 Thousands of 2013 Dollars 2013 Adjusted TY2016 Change Recorded Estimated $30,995 $40,181 $9,186 $0 $0 $0 $30,995 $40,181 $9,186 Table PEB-2 Southern California Gas Company Test Year 2016 Summary of Total Capital Costs UNDERGROUND STORAGE CAPITAL Total Capital 18 19 Thousands of 2013 Dollars 2014 2015 2016 Estimated Estimated Estimated $71,429 $74,270 $90,523 In addition to this testimony, please also refer to my workpapers, Exhibits SCG-06-WP (O&M) and SCG-06-CWP (capital), for additional information on the activities described herein.                                                              1 Pursuant to CPUC Decision (D) 01-06-081, issued June 28, 2001, the costs forecast in TY2016 do not include costs associated with the operation and maintenance of the Montebello underground storage field or any costs associated with salvage operations. This decision directs that all costs associated with the Montebello underground storage field operation be removed from rates as of August 29, 2001, which has been done. Also, as of April 2009, the East Whittier storage field was removed from rate base. Therefore, costs associated with maintaining this field are also excluded from this case. PEB-1 Doc #292223   1 B. Summary of Activities 2 SoCalGas operates four underground storage fields with a combined working capacity of 3 approximately 136 Bcf. 2 These fields are: Aliso Canyon (86.2 Bcf), La Goleta (21.5 Bcf), 4 Honor Rancho (26.0 Bcf), and Playa del Rey (2.4 Bcf). Underground Storage is responsible for 5 the safety, system integrity, design, operations, maintenance, and gas injection/withdrawal 6 activities, along with environmental and regulatory compliance functions, within the four storage 7 fields. It plans and constructs the capital investments necessary to provide value-added storage 8 services for SoCalGas customers. The critical goals for storage are safety, system integrity, gas 9 availability, reliability, and value, which are achieved in full compliance with governmental 10 regulations.3 11 Gas storage fields can only be constructed in areas with unique underground geological 12 characteristics. Their proximity to local gas consumers and transmission and distribution 13 pipelines make them even more valuable assets. The unique underground geology of SoCalGas’ 14 storage fields, all former hydrocarbon-producing fields, and their location with respect to gas 15 loads make them ideally suited for storage operations within the SoCalGas system. More 16 information about what determines a good storage field is provided in Appendix B: Underground 17 Storage of Natural Gas, and incorporated here by reference. 18 By their nature, gas storage fields occupy large open areas of land and require the 19 continual installation, maintenance, refurbishment, and replacement of heavy industrial 20 equipment such as engines, compressors, electrical systems, wells and piping, gas processing 21 components, and instrumentation. 22 Natural gas is compressed onsite to very high pressures (up to 3,600 psig) and injected 23 underground into the field reservoirs through piping networks and storage wells, typically during 24 seasonal periods when gas consumption is low and supplies are ample. 25 Storage gas is usually withdrawn and delivered to customers through the transmission 26 and distribution system when gas consumption is seasonally high during winter months. At the 27 beginning of the withdrawal season in November, the combined storage capacity of the four 28 storage fields is enough to supply all of SoCalGas’ customers for approximately six weeks, if 29 one assumes an average daily consumption rate.                                                              2 The volumetric capacity of a natural gas storage field reservoir is measured in units of billion cubic feet (Bcf). 3 Additional information on storage operations can be found in Appendix B. PEB-2 Doc #292223   1 2 A diagram/map of the SoCalGas/SDG&E gas transmission system, including the location of the four storage fields is shown in Figure PEB-1 below. 3 4 5 6 Figure PEB-1 Southern California Gas Company Transmission and Storage System  The four storage facilities are an integrated part of the energy infrastructure required to 7 provide southern California businesses and residents with safe and reliable energy and gas 8 storage services at a reasonable cost. 9 10 Aliso Canyon Aliso Canyon is located in Northern Los Angeles County and is the largest of the four gas 11 storage fields, with a working capacity of approximately 86 Bcf and deliveries to the 12 Los Angeles pipeline loop. Aliso Canyon began storage operations in 1973, although many of 13 its wells date back to the 1940s. Aliso Canyon has 115 injection/withdrawal/observation wells PEB-3 Doc #292223   1 and is designed for a maximum withdrawal rate of approximately 1.8 Bcf per day at full-field 2 inventory. Within the field, it is estimated there are approximately 38 miles of gas injection, 3 withdrawal, and liquid-handling pipelines that connect the storage wells to processing and 4 compression facilities. 5 Honor Rancho 6 Honor Rancho is also located in Northern Los Angeles County, approximately ten miles 7 north of Aliso Canyon, with a working capacity of approximately 26 Bcf and deliveries to the 8 Los Angeles pipeline loop. Honor Rancho began storage operations in 1975, although many of 9 its wells date back to the 1940s. Honor Rancho has 40 gas injection/withdrawal wells and is 10 designed for a maximum withdrawal capability of 1.0 Bcf per day. It is estimated that 11 approximately 12 miles of pipelines connect the storage wells to processing and compression 12 facilities. 13 La Goleta 14 La Goleta is located in Santa Barbara County near the Santa Barbara Airport and the 15 University of California–Santa Barbara campus and provides service to the northern coastal area 16 of the SoCalGas territory. La Goleta, the oldest of the four fields, began storage operations in 17 1941 and has a working capacity of approximately 21 Bcf. Most of its wells date back to the 18 1940s. La Goleta has 20 gas injection/withdrawal/observation wells and is designed for a 19 maximum withdrawal capability of 0.4 Bcf per day. It is estimated that approximately eight 20 miles of pipelines connect the storage wells to processing and compression facilities. 21 Playa Del Rey 22 Playa Del Rey, located in central Los Angeles County, near the Los Angeles International 23 Airport, was placed into storage service in 1942. It is the smallest of the storage fields, yet, due 24 its location, is a very critical asset with a design working capacity of approximately 2.4 Bcf. 25 Playa Del Rey has 54 gas injection/withdrawal/observation wells. It is estimated that 26 approximately 11 miles of pipeline connect the storage wells to processing and compression 27 facilities. 28 Playa Del Rey is designed for a maximum withdrawal rate of 0.4 Bcf per day to meet 29 residential, commercial and industrial loads throughout the western part of Los Angeles, 30 including oil refineries and power generators. PEB-4 Doc #292223   1 2 Table PEB-3 below further summarizes the descriptive characteristics of all four storage fields. 3 4 5 Table PEB-3 Southern California Gas Company Descriptive Statistics of Storage Fields Descriptive Statistic Aliso Canyon La Goleta Honor Rancho Playa del Rey Year Field Placed in Service Injection/Withdrawal/Observation Wells (number) Gas Compressor Units (number) Compression Horsepower (bhp) Maximum Reservoir Pressure (psig) Working Gas (Bcf) Maximum Withdrawal Rate (MMcfd) Maximum Injection Rate (MMcfd) Maximum Well Depth (feet) Minimum Well Depth (feet) Average Well Depth (feet) 1973 115 8 42,000 3,600 86.2 1,860 600 10,691 6,997 8,146 1941 20 8 5,700 2,050 21.5 420 140 6,912 4,247 4,886 1975 40 5 27,500 4,400 26.0 1,000 300 13,300 9,165 9,959 1942 54 3 6,000 1,700 2.4 400 75 6,575 6,049 6,339 6 C. Risk Management Practices in Storage 7 The risk policy witnesses, Diana Day (Exhibit SCG-02) and Doug Schneider (Exhibit 8 SCG-03), describe how risks are assessed and factored into cost decisions on an enterprise-wide 9 basis. Several of my costs address safety risks associated with the storage system. Most 10 specifically, I propose to establish a new SIMP, described and discussed below in the O&M and 11 Capital cost sections, to mitigate safety-related risks. 12 While we have historically managed risk at our storage facilities by relying on more 13 traditional monitoring activities and identification of potential component failures, we believe 14 that it is critical that we adopt a more proactive and in-depth approach. Historically, safety and 15 risk considerations for wells and their associated valves and piping components have not been 16 addressed in past rate cases to the same extent that distribution and transmission facilities have 17 been under the Distribution and Transmission integrity management programs. As a prudent 18 storage operator, SoCalGas proposes to manage and approach the integrity of its storage well 19 assets, which all fall under the jurisdiction of the California Department of Oil, Gas and 20 Geothermal Resources (DOGGR), in a manner consistent with the approach adopted for 21 distribution and transmission systems. Risk management activities, processes, and procedures PEB-5 Doc #292223 Total All Fields 229 24 81,000 136.1 3,760 1,115 -   1 for well integrity should have a focus similar to those employed under the Company’s pipeline 2 risk mitigation programs. 3 Accordingly, in this rate case, we propose to establish a highly proactive approach to 4 evaluating and managing risks associated with wells in our storage system through a new SIMP, 5 modeled after the successes of our pipeline integrity management programs (TIMP and DIMP). 6 Through the implementation of the SIMP, better storage well system data will be collected, 7 maintained and modeled to identify the top risks throughout Storage. Comprehensive plans to 8 mitigate those risks will be developed and implemented. 9 10 1. Risk Assessment Currently, risk assessment of our storage system is of a qualitative nature and is based on 11 our long experience in operating and managing SoCalGas’ storage facilities. During routine 12 system assessments, we monitor the condition of our assets and consider the risks they may pose 13 on safety, reliability, and the environment. 14 The future of risk assessment for our storage system is moving towards a more robust and 15 quantitative approach that will help us capture more information on the condition of our storage 16 wells and develop models that will assist in prioritizing risk mitigation activities. The details of 17 this new risk assessment are captured in further sections of my testimony describing the SIMP. 18 19 2. Risk Mitigation Alternatives Evaluation Well risk mitigation is evaluated on a case-by-case basis. Whenever a well may pose a 20 safety risk, we act immediately to address the problem. Alternatives, such as plugging and 21 abandoning the well, versus a major repair or well replacement, are evaluated based on 22 conditions, including the age of the well, prior repair or maintenance history, performance during 23 withdrawal or injection periods, and surface considerations, such as susceptibility to landslides. 24 These various conditions, and their associated costs, are evaluated to determine the safest, most 25 cost-effective mitigation option. Another consideration that may influence repair decisions is the 26 age and condition of certain well components that may have become obsolete and are no longer 27 supported by the original equipment manufacturer and cannot be readily replaced or maintained. 28 At a very high level, alternatives to mitigate risks posed by deteriorating, aging, obsolete 29 or failed storage equipment include: 30  Replacement of equipment / storage wells 31  Overhaul of equipment / storage wells PEB-6 Doc #292223   1  Repair of equipment / storage wells 2  Abandonment of a storage well / equipment 3  Installation of additional equipment 4 3. Risk Reduction Benefits 5 The proposed mitigation activities are expected to address safety, reliability and 6 environmental risks by either maintaining a certain acceptable level of control over those risks, 7 or by further reducing the potential impacts of the risks. While there are no current means to 8 provide a quantitative risk reduction forecast, it is my belief that the proposed mitigation 9 activities will greatly assist in controlling and reducing the risks in our storage system. 10 In addition to establishing a more quantitative risk analysis of our storage wells as 11 discussed below, the SIMP will result in a more effective prioritization of required capital 12 expenditures that address risks that impact safety, reliability and the environment. 13 14 4. Integration of Risk Mitigation Actions and Investment Prioritization The implementation of the proposed SIMP will establish an integrated risk management 15 and investment prioritization process for storage management at SoCalGas. Storage wells are an 16 integral gas delivery component, and an unanticipated safety concern could interrupt access to 17 the working gas asset and potentially lead to a complete shutdown of a storage field. 18 Models to be developed from captured well data will evaluate threats and risks that exist 19 in our storage system. This will allow for a prioritization of those storage well threats, based on 20 their location, age, condition and other factors, thereby establishing a robust methodology for 21 prioritizing storage management investments. 22 23 5. Investment Included in Request to Support Risk Mitigation Investments related to the SIMP are necessary to establish a risk management program. 24 Future mitigation activities that will result from the implementation of the SIMP will be risk- 25 driven and will address identified and prioritized risks. SoCalGas forecasts $5.676 million 26 annually in O&M and $24.272 million annually in capital costs for the implementation of the 27 SIMP. It is anticipated that the SIMP will last for six years, the estimated length of time required 28 to inspect all of the wells and mitigate any identified conditions. After this six-year period, when 29 the program is complete, future inspection and mitigation costs will be addressed through routine 30 operations. PEB-7 Doc #292223   1 D. Support To/From Other Witnesses 2 In addition to sponsoring my own organization’s costs, I also provide sponsorship of the 3 New Environmental Regulatory Balancing Account (NERBA) cost forecast for the reporting 4 requirements under Subpart W for Gas Engineering, Gas Transmission and Underground Storage 5 for witnesses Raymond Stanford (Exhibit SCG-07), John Dagg (Exhibit SCG-05), and myself. 6 The costs associated with Subpart W reporting requirements are illustrated in the cost detail in 7 section II.C of my testimony. Policy testimony in support of NERBA and storm water 8 regulations is provided by Environmental Services witness Jill Tracy (Exhibit SCG-17). 9 II. NON-SHARED COSTS 10 A. 11 Table PEB-4 below summarizes the total non-shared O&M forecasts for the listed cost 12 Introduction categories. 13 14 15 Table PEB-4 Southern California Gas Company Non-Shared O&M Summary of Costs UNDERGROUND STORAGE Thousands of 2013 Dollars Categories of Management Underground Storage – Routine New Environmental Regulatory Balancing Account (NERBA) (Existing Balancing Account) Storage Integrity Management Program (Proposed New Balancing Account) Total 2013 Adjusted Recorded $30,681 TY2016 Estimated Change $34,101 $3,420 $314 $404 $90 $0 $5,676 $5,676 $30,995 $40,181 $9,186 16 B. 17 Table PEB-05 below summarizes the non-shared O&M forecasts for routine storage 18 Underground Storage – Routine O&M operations. PEB-8 Doc #292223   1 2 3 Table PEB-05 Southern California Gas Company Non-Shared Routine O&M Costs UNDERGROUND STORAGE Categories of Management Underground Storage - Routine 4 1. 5 Thousands of 2013 Dollars 2013 Adjusted Recorded $30,681 TY2016 Estimated Change $34,101 $3,420 Criticality of Storage and Underlying Activities The use of the four underground storage fields is an essential component of the energy 6 delivery system within California that works in conjunction with the SoCalGas transmission 7 pipeline and distribution delivery network. This interconnected system consists of high-pressure 8 pipelines, compressor stations, and underground storage fields, designed to receive natural gas 9 from interstate pipelines and local production sources. The integrated system enables deliveries 10 of natural gas to customers or into storage field reservoirs, depending on market demands. 11 SoCalGas uses its storage assets to efficiently meet seasonal, as well as daily, gas balancing 12 requirements.4 To satisfy these needs, the individual storage facilities act as “gas suppliers” or 13 “consumers,” depending upon the withdrawal or injection requirements as managed by Gas 14 Control. Fluctuating demands may require Storage Operations to perform gas injection or 15 withdrawal functions at any hour of the day, 365 days per year. Storage fields are continually 16 staffed with operating crews and on-call personnel to support these critical 24/7 operations. 17 Figure PEB-2 below illustrates the crucial role of storage in the delivery of reliable gas 18 service for energy consumers within southern California during the fall and winter heating 19 season.                                                              4 In order to maintain operational stability of the gas system, smaller changes in supply and demand are typically met by “increasing” and/or “pulling” on the inventory of pressurized gas contained within the transmission pipelines. This process known as “packing and drafting,” is an efficient way to deal with minor changes in load. As the system load increases, and can no longer be satisfied using pack and draft, the system is balanced by either injecting natural gas into the storage fields when pipeline delivery supply exceeds customer demand, or withdrawing natural gas from storage when service requirements exceeds out-of-State pipeline supplies. PEB-9 Doc #292223   1 2 3 Figure PEB-2 Southern California Gas Company System Send-out December 2013 5 4.5 4 Billion Cubic Feet per Day 3.5 3 2.5 2 1.5 1 0.5 0 1 5 7 9 11 13 15 17 19 21 23 25 27 29 31 Storage Withdrawal 4 5 3 Pipeline Receipts From the bar chart in Figure PEB-2, it can be observed that SoCalGas underground 6 storage provided approximately 58% of the system send-out, or 17.7 Bcf, for a seven-day period 7 beginning on December 5, 2013. On December 6, 2013, storage actually delivered 2.8 Bcf or 8 66% of the gas consumed by residential, commercial and industrial customers on this cold day. 9 Had underground storage not been available and reliable for this extended period of high 10 demand, widespread curtailments may have been necessary, and potentially significantly 11 impacted millions of Southern California customers. 12 The reliance/dependency on underground storage to supply the SoCalGas system with 13 such enormous volumes of gas over short period of times due to extreme weather conditions 14 occurring locally or out of state, or from the temporary reduction of interstate supplies for other 15 reasons, places significant strains on the wells, pipelines, and other aging storage facilities that 16 must support the heavy withdrawal demands. The expected instant availability of storage gas 17 requires continuous maintenance activities and ongoing investments to satisfy these immediate 18 and longer-term customer demands. 19 20 Storage is responsible for the operation, maintenance, integrity, and engineering functions associated with the use of facilities within the perimeter of the fields. This PEB-10 Doc #292223   1 responsibility also extends beyond the plant perimeter in some areas, where gas injection and 2 withdrawal pipelines and storage wells exist outside of the storage field property. As an 3 example, Figure PEB-3 below is an aerial view of the Playa del Rey storage field that plots the 4 location of its wells inside and outside of the plant perimeter.5 5 6 7 Figure PEB-3 Southern California Gas Company Aerial View of Playa Del Rey Underground Storage Field Well (Active)    Well (Abandoned)  Fenced Perimeter 8   9 The Storage department presently consists of approximately 175 employees. It is 10 organized with both operational and technical support groups that provide cost-effective delivery 11 of services essential to operating and maintaining the safety, integrity, security, and reliability of 12 its crucial gas delivery assets. While each storage field has its own unique operating issues and 13 characteristics, there are common support activities performed on a regular basis that make up 14 the bulk of historical expenses presented in this testimony. 15 In general, the activities performed in compliance with increasing regulatory 16 requirements that drive the historical and future O&M costs for storage can be summarized as 17 follows:                                                              5 Some wells are plotted on the graphic as a single dot, due to their close proximity of each other. PEB-11 Doc #292223   1 Management, Supervision, Training, and Engineering 2 These activities cover the administrative salaries and engineering costs associated with 3 the operation of the underground storage fields. This includes funding for studies in connection 4 with reservoir operations and wells necessary to maintain the integrity of the storage system. 5 Leadership, safety, technical training, operator qualification and quality assurance functions are 6 other critical components of this grouping. 7 Wells and Pipelines 8 9 These costs include salaries and expenses associated with routinely operating storage reservoirs such as: turning wells on and off, well testing and pressure surveys, and wellhead6 and 10 down-hole activities for contractors that perform subsurface leakage surveys on 11 injection/withdrawal facilities. Other expenses include the costs associated with patrolling field 12 lines, lubricating valves, cleaning lines, disposing of pipeline drips, injecting corrosion 13 inhibitors, pressure monitors, and maintaining alarms and gauges. 14 Equipment Operation and Maintenance 15 These costs include salaries and expenses for maintenance work performed on gas 16 compressors and other mechanical equipment. The work ranges from the basic repair of an oil 17 leak to a major time consuming overhaul of a compressor engine. Other maintenance functions 18 include: work on measurement and regulating equipment, starting and monitoring engines, 19 lubricating machinery, environmental compliance, checking pressures, work on equipment used 20 for conditioning extracted gas, and wastewater disposal systems. Lastly, this area includes costs 21 for chemicals, consumables, fuel, and electrical power used to operate storage reservoirs and 22 compressors. 7 23 Structural Improvements, Rents, Royalties 24 These costs include salaries and expenses for maintenance work performed on 25 compressor station structures at underground storage facilities along with property rental costs. 26 Royalty payments associated with gas wells and land acreage located at underground storage 27 properties is also included.                                                              6 An illustrative diagram of a wellhead is provided as Appendix C, Wellhead Diagram and Down-hole Schematic. 7 The cost of natural gas used as fuel for the compressors and other equipment necessary to operate the storage fields has been adjusted out and excluded from this testimony because these costs are included in the Triennial Cost Allocation Proceeding (TCAP). In the same manner, all unaccounted for quantities of gas associated with field operation activities are similarly excluded from this general rate case due to cost recovery in the TCAP. PEB-12 Doc #292223   1 2 Records Management These activities are associated with maintaining records related to storage assets and 3 operations. Typical types of work performed include: work orders, surveys and documentation 4 of wells, pipelines, topography, roads, rights-of-way, various infrastructure and easements 5 boundary verification, and creation and maintenance of maps related to underground 6 zones/rights. Audit related activities are also included. 7 8 9 2. Cost Forecast Methodology A five-year trending methodology using 2009 to 2013 adjusted-recorded expenses for labor and non-labor was used to forecast the TY2016 O&M for routine Storage operations, since 10 historical O&M costs have been increasing at a relatively consistent rate. Storage facilities 11 consist of large heavy duty equipment located above and below ground that continues to wear 12 and age, due to operating demands and the environment. The volume of maintenance work, 13 along with its complexity and the limited availability of replacement components, continues to 14 push costs consistently higher on an annual basis. Increasingly stringent governmental 15 regulations, operator qualification requirements, enhanced employee training, chemical 16 consumables, records management functions and enhanced audit activities also contribute to the 17 upward trend. 18 // 19 // PEB-13 Doc #292223   1 Figure PEB-4 below illustrates the historical and future projected costs (excluding 2 NERBA and SIMP in 2016) for the routine labor and non-labor expenses based on a five-year 3 trending methodology. 4 5 6 Figure PEB-4 Southern California Gas Company Non-Shared O&M Summary of Routine Costs Storage O&M ‐ Routine Labor & Non‐Labor 40 35 $ Millions 30 25 20 15 Actual 5 Yr Trend Forecast 10 5 2009 7 8 2011 2012 2013 2014 2015 2016 The five-year trend establishes a TY2016 forecast of $34.101 million for routine O&M expenses. 9 10 2010 3. Cost Drivers Most increases in costs for storage over the five-year trend period are driven by the 11 intensity of traditional operating functions and routine work efforts across the board that are 12 required to safely operate and maintain the aging infrastructure of the fields, and costs associated 13 with a larger volumetric storage capacity and throughput.8 14 Aging wells, compressors, and gas and liquid piping systems are susceptible to 15 unpredictable failures or preemptive repair situations. The associated mitigation costs for such                                                              8 Over the five-year period of 2009 through 2013, SoCalGas increased the capacity of its storage fields by 5 Bcf, from approximately 131 Bcf to 136 Bcf. In CPUC Decision (D) 10-04-034, SoCalGas was authorized to increase the capacity of Honor Rancho from 23 to 28 Bcf. This expansion is expected to result in a total storage capacity of 138 Bcf by 2016, an inventory increase of 5.3% over 2009 volumes. PEB-14 Doc #292223     1 occurrences can vary from year to year. Thus, single events among relatively few facilities can 2 have a significant impact on expense history. This “peak and valley” potential is another reason 3 that a long-term horizon, such as the five-year historical trending methodology utilized, is 4 appropriate for forecasting O&M costs. 5 In the future, pipeline integrity inspection requirements, the frequency and depth of 6 regulatory audits and resulting compliance activities, additional focus on employee training and 7 supervisory qualification, chemical consumables, increased permitting and reporting to 8 regulatory agencies, along with new and existing environmental regulations are expected to add 9 to operating expenses. Thus, O&M costs are expected to continue to increase, if not exceed, the 10 annual historical rate of approximately 3.1%. 11 Another cost driver that varies from year to year is the amount of gas throughput 12 (injection volume plus withdrawal volume) for the storage fields. This cycled volume is 13 dependent on external factors such as the weather, the economy, and the gas markets. Over the 14 five-year period of 2009 through 2013, the annual volume of gas cycled through the storage 15 fields varied from a high of 228 Bcf to a low of 162 Bcf. The storage throughput in 2013 was 16 197 Bcf, 4% higher than the five year average of 189 Bcf. Higher gas throughput causes more 17 wear on the compressors and equipment, and requires additional use of consumables such as 18 engine oil, glycol, chemicals, odorant, etc. 19 There are few “big ticket items” one can point to as a primary cause for the increasing 20 trend. Those few identifiable items that tend to stand out beyond the routine trend include the 21 increasing costs of environmental compliance and hazardous waste disposal along with chemical 22 consumables such as lubricating oil or glycol. 23 C. New Environmental Regulatory Balancing Account O&M Costs 24 The NERBA is a two-way balancing account established to record costs associated with 25 specified new and proposed environmental regulations. Table PEB-6 below summarizes the 26 costs for Storage, Transmission and Gas Engineering that are balanced in the NERBA. PEB-15 Doc #292223   1 2 3 Table PEB-6 Southern California Gas Company NERBA Costs for Storage, Transmission and Gas Engineering UNDERGROUND STORAGE Thousands of 2013 Dollars 2013 Adjusted Recorded $314 Categories of Management New Environmental Regulatory Balancing Account (NERBA) 4 5 1. TY2016 Estimated Change $404 $90 Description of Costs and Underlying Activities The NERBA costs in my testimony are limited to the Environmental Protection Agency 6 Subpart W reporting requirement costs for Gas Engineering, Gas Transmission, and 7 Underground Storage. This forecast is to comply with the Subpart W requirements for fugitive 8 emission monitoring, as supported by Environmental Services witness Jill Tracy (Exhibit SCG- 9 17), that address facilities downstream of major equipment, such as compressors, regulator 10 stations, and valves. 11 12 2. Cost Forecast Method The forecast method for this cost category is the base year plus anticipated incremental 13 costs. This method is appropriate because it identifies specific environmental regulatory changes 14 and their related costs impacting the company in 2013, and during the next forecast period that 15 cannot be represented using an average or trending forecast. Due to the uncertainty of the scope 16 and anticipated costs related to future reporting, incremental funding was added to the base year 17 recorded costs. 18 19 20 3. Cost Drivers The cost drivers behind this forecast are the anticipated upper pressures from air quality agencies requiring more emission reporting during the next forecast period. 21 D. Storage Integrity Management Program 22 SoCalGas proposes to implement a new SIMP to proactively identify and mitigate 23 potential storage well safety and/or integrity issues before they result in unsafe conditions for the 24 public or employees. Table PEB-7 below summarizes the projected O&M costs for 25 implementation of the SIMP. PEB-16 Doc #292223   1 2 3 Table PEB-7 Southern California Gas Company Storage Integrity Management Program O&M Costs UNDERGROUND STORAGE Categories of Management Storage Integrity Management Program (SIMP) 4 5 1. Thousands of 2013 Dollars 2013 Adjusted Recorded $0 TY2016 Estimated Change $5,676 $5,676 Introduction SoCalGas proposes to implement a new six-year SIMP to proactively identify and 6 mitigate potential storage well safety and/or integrity issues before they result in unsafe 7 conditions for the public or employees. A proactive, methodical, and structured approach, using 8 state-of-the-art inspection technologies and risk management disciplines to address well integrity 9 issues before they result in unsafe conditions, or become major situational or media incidents, is 10 a prudent operating practice. Without a robust program to inspect underground storage wells to 11 identify potential safety and/or integrity issues, problems may remain undetected within the high 12 pressure above-ground wellheads, pipe laterals (up to 3,600 psig) and below-ground facilities (up 13 to 4,400 psig) among the 229 storage field wells. This situation is evidenced by an increase in 14 recent years in the type of work related to safety conditions observed as part of routine 15 operations. This concern is further amplified by the age, length, and location of wells. Some 16 SoCalGas wells are more than 80 years old with an average age of 52 years. Well depths can 17 exceed 13,000 feet. In addition, some wells are located within close proximity to residential 18 dwellings or high consequence areas, as shown in Figure PEB-3. 19 The SIMP is intended to: 20  Identify threats and perform risk assessment for all wells 21  Develop an assessment plan for all wells 22  Remediate conditions 23  Develop preventative and mitigation measures 24  Maintain associated records PEB-17 Doc #292223   1 The primary threats to the SoCalGas well facilities that SIMP will address are internal 2 and external corrosion, and erosion.9 Once an issue is identified, the initiation of critical repair 3 work identified will immediately minimize safety risks. Lesser-risk integrity work will be 4 prioritized to plan and efficiently execute mitigation or preventative actions. 5 SoCalGas proposes to establish detailed baseline assessments on its underground assets 6 that are complete, verifiable, and traceable to a much greater degree than it has done in the past.10 7 This risk management approach will enhance the proactive assessment, management, planning, 8 repair, and replacement of below-ground facilities to eliminate situations that could potentially 9 expose the public or employees to uncontrolled well-related situations. 10 The SIMP would launch an accelerated and robust assessment of the inspected storage 11 well facilities (approximately 50% of the SoCalGas wells) over the rate case period. The initial 12 SIMP work, which will likely target wells older than fifty years of age, would enhance ongoing 13 safety, system integrity, support reliability of service, and provide additional confidence that 14 wells, down-hole equipment, and associated pipe laterals maintain their compliance with 15 DOGGR regulations. While SoCalGas currently meets existing requirements under DOGGR 16 regulations, the possibility of a well related incident still exists, given the age of the wells and 17 their heavy utilization. A SIMP will further decrease risks always present in these types of 18 operations, provide a higher level of safety for its customers and employees, and further protect 19 the environment. 20 Presently, most major O&M and capital funded activities conducted on storage wells are 21 typically reactive-type work, in response to corrosion or other problems identified through 22 routine pressure surveillance and temperature surveys. For example in 2008 at Aliso Canyon, it 23 was discovered during routine weekly pressure surveillance that the surface annulus of well 24 Porter 50A had a pressure of over 400 psig.11 In most cases, situations like this can be indicative 25 of production casing leaks from either internal or external corrosion where high pressure gas can                                                              9 The gas withdrawn from storage formations typically contains water, sand, and reactive gas constituents such as carbon dioxide that can corrode or erode storage well components especially during periods of high demand. 10 The goals and objectives of SIMP are similar to those of the TIMP for transmission pipelines. SIMP would be focused on vertical casing pipe and components (wells) and associated above-ground facilities. 11 The well was immediately taken out of service and work began to isolate and blow-down the surface casing. Eventually a workover rig moved onto the well and an ultrasonic inspection revealed external production casing corrosion from 450 ft. to 1050 ft. PEB-18 Doc #292223   1 migrate to the surface in a matter of hours. External corrosion has also been observed in other 2 wells at the field. 3 Routine surveillance and temperature survey work identifies problems that have already 4 occurred, and well integrity may have already been severely compromised requiring immediate 5 attention to maintain safety, integrity and reliability. For example in 2013, again at Aliso 6 Canyon, two wells were found to have leaks in the production casing at depths adjacent to the 7 shallower oil production sands. In these situations, there was no evidence of the leaks at the 8 surface or surface casing. 9 Reactive-type work in response to identified safety-related conditions observed as part of 10 routine operations has increased in recent years. In fact, a negative well integrity trend seems to 11 have developed since 2008. The increasing number of safety and integrity conditions 12 summarized in Table PEB-8 below is attributed primarily to the frequency of use, exposure to 13 the environment, and length of time the wells have been in service. 14 15 16 Table PEB-8 Southern California Gas Company Number of Major Well Integrity Workovers by Year Year Well Integrity Category Casing Leak Tubing Leak Wellhead Leak Casing Shoe Leak Sub-surface Safety Valve Total 17 2008 1 2 2009 1 1 - 2010 5 1 - 2011 2 3 2 1 - 2012 3 3 2 2013 2 4 2 1 3 2 6 8 8 9 Ultrasonic surveys conducted in storage wells as part of well repair work from 2008 to 18 2013 identified internal/external casing corrosion, or mechanical damage in 15 wells. External 19 casing corrosion has been observed at relatively shallow depths in the production casing, and at 20 deeper intervals near the Aliso Canyon shallow oil production zone at which is being water- 21 flooded. Internal mechanical wear has been observed in production casings, likely as a result of 22 drilling operations that took place when the well was originally drilled. In addition, external PEB-19 Doc #292223   1 tubing corrosion has been observed on tubing in the joint above the packer most likely as a result 2 of stagnant fluid. 3 In addition to the 36 well-related conditions presented in Table 8, and the corrosion or 4 mechanically damaged wells that were previously identified, SoCalGas has 52 storage wells in 5 service that are more than 70 years old. Half of the 229 storage wells are more than 57 years old 6 as of July 2014. Figure PEB-5 below displays the age distribution visually. 7 8 9 Figure PEB-5 Southern California Gas Company Age Distribution of Storage Wells Age Distribution of Storage Wells 50 45 47 44 40 39 Number of Wells 35 39 30 25 20 18 15 15 10 5 10 9 8 0 0‐10 11‐20 21‐30 31‐40 41‐50 51‐60 61‐70 71‐80 81‐90 Age of Wells in Years 10 11 Given the increasing trend in well integrity repairs, the corrosion threats that have been 12 detected on some wells, the increasing age of the wells, and the success of the California Public 13 Utilities Commission (CPUC)-approved TIMP, which has been established to maintain the safety 14 of horizontal high pressure pipelines that are subject to less harsh conditions than storage wells, 15 the SIMP is certainly justified. Without the SIMP, SoCalGas will continue to operate in a 16 reactive mode (with the potential for even higher costs to ratepayers) to address sudden failures PEB-20 Doc #292223   1 of old equipment. In addition, SoCalGas and customers could experience major failures and 2 service interruptions from potential hazards that currently remain undetected. 3 Some of the inspection techniques, components, and practices planned for the SIMP are 4 currently conducted on a limited basis as part of on-going operations performed to address 5 maintenance issues. The intensity of routine inspections is expected to continue at historical 6 levels. The more advanced SIMP inspections will be performed in addition to routine reactive 7 inspections, as there is currently no indication that the rate of reactive maintenance work will 8 decrease over the period of the next rate case. By establishing the additional and more robust 9 SIMP inspections, and creating baseline assessments of well conditions, the severity and extent 10 of reactive maintenance may be reduced in the future, and the time necessary to respond to 11 indications of breaches in reservoir integrity and safety should be greatly improved. 12 To take advantage of economy of scale, accelerate problem solving and knowledge 13 continuity, and best utilize the limited resources of qualified personnel and specialized 14 equipment in the oil and gas industry required for this type of program, SoCalGas plans to 15 conduct this program over a six-year period. Economic rig availability and quality supervision is 16 highly dependent on overall demands of the industry. A continuous program implemented over 17 a reasonable period of time will help secure efficient and effective specialty resources. After the 18 six-year baseline assessment period of the SIMP, it is expected that well assessments performed 19 on a regular frequency would become part of routine operations. 20 SoCalGas proposes that these O&M costs receive two-way balancing treatment due to the 21 highly unpredictable nature of inspection costs. Factors contributing to the uncertainty include 22 the unknown number of at-risk wells and their integrity status, the highly variable nature of well 23 inspection strategies, the uncertainty surrounding the volume and degree of repair work to be 24 performed, the variable cost of consulting experts when required, specialty equipment and 25 skillful operators to be procured, and erratic field conditions typically encountered once 26 inspection work is initiated. Since there are many uncertainties with regards to the number and 27 integrity condition of the wells, and down hole inspection activities can become enormously 28 costly and unpredictable when problems occur which is increasingly frequent, and follow-up 29 mitigation actions whether they be O&M or capital is so variable due to the unique situation of 30 each well, a two-way interest bearing balancing account treatment is requested for this work as 31 sponsored by Regulatory Accounts witness Reginald Austria (Exhibit SCG-35). PEB-21 Doc #292223   1 2 2. General Description of Work The safety and integrity-related work will be conducted in parallel at all four Storage 3 Fields (Aliso Canyon, Honor Rancho, Playa del Rey, and La Goleta). A project manager, with 4 other support personnel, will be used to conduct detailed internal well inspections and to develop 5 the threat identification, risk assessment, well assessment plan, plan to remediate the conditions 6 found, preventive and mitigative measures, and record keeping requirements for the SIMP. The 7 assessment portion of the process will include contract workover rigs that will be used to 8 evaluate downhole casing and tubing. Surface equipment such as valves, wellheads, and well 9 laterals will be evaluated using different methods. 10 A threat assessment and risk assessment matrix will be developed and populated, and a 11 priority inspection guide established, from existing well data that includes but is not limited to: 12 age of the well, proximity to sensitive areas or populations, workover history, inspection data, 13 historical withdrawal rates (energy release potential), known reservoir and geologic conditions, 14 and surrounding geological characteristics (fault lines, landslide potential, etc.). In summary, it 15 is expected that the oldest wells in closest proximity to the public, located in environmentally or 16 safety-sensitive areas that have not had recent downhole inspections or work would likely be 17 prioritized for inspection. Other wells may be added to this list, where deemed appropriate, 18 based on subject matter expertise. 19 The first order of work would include the detailed inspection of all surface valves and 20 above ground lines on the wellheads and laterals (both kill and injection/withdrawal lines), since 21 surface failures, should they occur, could potentially have the most immediate impact on 22 operating personnel and the public. 23 The majority of O&M costs to perform the noise and temperature surveys, pressure tests, 24 visual camera tests, and casing/tubing inspections to assess well integrity risks associated with 25 internal/external corrosion and erosion are associated with workover rig usage and well control 26 activities. A typical week-long inspection process is summarized at a high level with the 27 following ten steps: 28 1. Move in the workover rig and fill the well with brine. 29 2. Install well Blow-out Prevention Equipment. 30 3. Remove the tubing and down-hole completion equipment. 31 4. Scrape and prepare the casing, set the bridge plug and sand. PEB-22 Doc #292223   1 5. Run casing inspection equipment (Ultrasonic, magnetic flux, calipers, 2 cameras etc.). 3 6. Run the test packer and pressure test production casing. 4 7. Remove the sand and retrievable bridge plug. 5 8. Re-install the production tubing and completion equipment, then 6 pressure test. 7 9. Rig down the Blow-out Prevention Equipment, reinstall the production 8 tree, and move the workover rig off the well. 9 10. Replace laterals, instrumentation, unload the workover brine from the 10 wellbore and return the well to service. 11 This type of inspection operation typically requires six to eight days to complete, 12 assuming no difficulties are encountered. If difficulties are encountered, which are not unusual 13 with well work, the duration of the inspection and associated costs could easily double. 14 Follow-up preventative mitigation and remediation work will most likely be capitalized. 15 The remediation plan will depend on the evaluation of the inspection data, and further pressure 16 testing of the casing may be conducted. If no damage is observed or questionable conditions 17 identified, the tubing will be re-run, the wellheads and laterals reinstalled, and the well will be 18 returned to normal operations. If any significant deficiencies or unacceptable operating 19 situations are found during the evaluation, the well will not be returned to service. Rather, it will 20 be idled for an indefinite period of time while a detailed work prognosis is prepared and further 21 work scheduled. Preventative and mitigative measures could include actions such as running 22 inner liners, new tubing, cement squeezing of holes, or possible abandonment of the well. A 23 complete abandonment would likely require the drilling of a replacement well in order to 24 maintain storage field deliverability requirements. The details of the SIMP capital plan are 25 included in section III-C.C13 of this testimony. 26 The record keeping requirements will include a written Storage Integrity Management 27 Plan, traceable, verifiable and complete documentation of the results of the assessments that are 28 completed, and the results of the remediation completed. 29 The company labor required for the inspection process is one individual at each of the 30 four fields to oversee the workover/inspection contractors, plus 1.5 FTEs to manage the 31 inspection program, interpret the complex data, and develop follow-up mitigation plans. PEB-23 Doc #292223   1 3. 2 Cost Forecast Methodology The forecast method used for SIMP O&M activities is zero-based. This approach is most 3 appropriate because this is a new program and the assumed units of work, estimated cost per 4 unit, and support labor needs are identifiable. Unit costs for the ten step inspection process 5 previously described and the lateral inspections are based on historical prices of similar type 6 work. Labor FTEs to support the program based on experience and practicality consist of one 7 Contract Administrator for each of the fields (4), a Well Inspection Project Manager (1), and 0.5 8 clerical support. These costs are presented in Table PEB-9 below. 9 10 11 Table PEB-9 Southern California Gas Company SIMP O&M Cost Detail Description Annual Number Well Inspections and Mitigation Lateral Piping Inspections Company Labor FTEs Well Inspection Costs Reassigned to Capital Total O&M 40 40 5.5 N/A - 12 13 4. 14 Cost Per Estimated Inspection Total (Thousands of $2003) $390 $15,600 $5 $200 N/A $812 N/A ($10,936) $5,676 Cost Drivers The most significant cost drivers for this uniquely specialized work performed on high 15 pressure wells is the availability of workover rigs, the skilled field and technical workforce 16 required to produce and analyze data, and the specialized equipment to be employed. 17 III. CAPITAL COSTS 18 A. Introduction 19 The costs described in this section cover the capital expenditures estimated for Storage 20 operations. The intent behind the capital expenditure plan is to provide safe, reliable delivery of 21 natural gas to customers at the lowest reasonable cost. These investments also enhance the 22 integrity, efficiency, and responsiveness of operations while maintaining compliance with 23 applicable regulatory and environmental regulations. Table PEB-10 below summarizes the total 24 capital forecasts for Gas Storage for 2014, 2015, and 2016. PEB-24 Doc #292223   1 2 3 4 Table PEB-10 Southern California Gas Company Capital Expenditures Summary of Costs (Thousands of $2013) Category Description Storage Compressors 2013 Recorded $8,991 2014 Estimated $7,790 2015 Estimated $7,790 2016 Estimated $7,790 Storage Wells $10,976 $31,890 $34,360 $36,977 $0 $2,008 $2,510 $24,272 Storage Pipelines $4,005 $6,546 $10,083 $4,931 Storage Purification Systems $9,284 $8,796 $7,605 $7,605 Storage Auxiliary Systems $11,058 $14,398 $11,922 $8,948 Total Capital: $44,313 $71,429 $74,270 $90,523 Storage Integrity Management Program 5 6 Figure PEB-6 below presents the Total Capital summary of Table PEB-10 in a graphical format. 7 8 9 Figure PEB-6 Southern California Gas Company Historical and Forecasted Total Capital by Year Historical and Forecasted 100 90 80 $s in Millions 70 60 SIMP 50 New Wells 40 Baseline 30 Actual 20 Baseline 10 0 2009 2010 2011 2012 2013 2014 2015 2016 Year 10   PEB-25 Doc #292223   1 The 2016 capital request of $90.523 million was derived using the following methodology: 2  Summation of five-year averages to create a baseline estimate for routine functions. 3  Plus, incremental costs to drill new wells at a level that began in 2014 to address 4 natural deliverability declines. 5  6 As noted previously, SoCalGas seeks two-way balancing treatment of the SIMP capital Plus SIMP. 7 cost estimates. Additional detail on the categories and costs that comprise the total capital 8 forecast is presented in the sections below. 9 B. 10 Storage Compressors This Budget Category includes costs associated with natural gas compressors. These 11 storage compressor units increase the pressure of natural gas so it can be injected into the 12 underground reservoirs. Examples of equipment within this area include turbines, engines, high- 13 pressure gas compressors, compressed air system equipment, fire suppression systems, gas 14 scrubbers, and related control instruments. This budget category includes the necessary capital 15 for maintenance, replacements, and upgrades of the various storage field compressors to uphold 16 safety, maintain or improve reliability, extend equipment life, achieve environmental 17 compliance, and to meet the required injection capacities. Table PEB-11 below summarizes the 18 cost forecast for storage compressors. 19 20 21 Table PEB-11 Southern California Gas Company Capital Expenditures for Storage Compressors STORAGE COMPRESSORS B1- Goleta Units #2 and #3 Overhauls B2- Blanket Projects Total 22 Thousands of 2013 Dollars Estimated Estimated Estimated 2014 2015 2016 $253 $2,272 $0 $7,538 $5,518 $7.790 $7,791 $7,790 $7,790 Due to the annual variability of this category, a five year average was used to develop the 23 2016 estimate, as presented in Figure PEB-7 below. Projects expected to cost over $1 million 24 are supported by individual capital workpapers that accompany this testimony, Exhibit SCG- 25 CWP. PEB-26 Doc #292223   1 2 3 Figure PEB-7 Southern California Gas Company Historical and Forecasted Storage Compressor Capital Storage Compressors ‐ Recorded and Forecast  Capital 15 Actual 5 Yr. Average Forecast $s in Millions 12 9 6 3 0 2009 2010 2011 2012 2013 2014 2015 2016 Years 4 5 1. 6 7 B1-Goleta Units #2 and #3 Overhauls a. Description When compressors reach the end of their service lives, they must be overhauled in order 8 to avoid replacing them in-kind. Overhauls are necessary for safety, to restore and/or maintain 9 their efficiency, deliver capacity, maintain compliance with environmental regulations and 10 provide reliable service. While parts and compressor service contractors are still available, an 11 overhaul is typically the most cost-effective solution. Goleta Units #2 and #3 have reached their 12 maximum in-service time and require overhauls in order to maintain safety, efficiency, 13 reliability, and environmental compliance. The overhaul of units #2 and #3 at Goleta is expected 14 to cost $253K, $2.272 million, and $0 in 2014, 2015, and 2016, respectively. Specific details 15 regarding the overhauls may be found in my capital workpapers, Exhibit PEB-06-CWP. 16 b. Forecast Method 17 Costs are based on the knowledge of experienced personnel who have handled similar 18 overhauls in the recent past. Such experience is based on recent costs of component parts and 19 quotes by qualified contractors. PEB-27 Doc #292223   1 2 c. Cost Drivers The cost drivers for these capital projects relate to the very specific skill sets, tooling, 3 parts, and specialized knowledge for gas engines, equipment, and the high pressure natural gas 4 compressors they power. 5 2. 6 7 B2-Blanket Projects a. Description Compressor Station equipment must have continuing capital maintenance as items 8 continue to age and to wear out. SoCalGas plans to replace and upgrade aging and obsolete 9 compressor equipment via smaller projects with individual costs estimates that do not justify the 10 preparation of individual workpapers. These projects are addressed as “Blanket” projects and 11 cost estimates vary from tens of thousands to several hundred thousands of dollars. Projected 12 work includes, but is not limited to overhauls, rebuilds, major equipment replacements and 13 upgrades to critical assets such as power turbines, gear boxes, compressors, and engines. 14 Deferral of these smaller compressor maintenance projects could jeopardize safety or cause 15 equipment to shut down, which can threaten supply continuity. Forecast capital costs for Blanket 16 projects in $ millions for 2014, 2015, and 2016 are $7.538, $5.518, and $7.790, respectively.   17 18 b. Forecast Method This estimate is based on the local knowledge and judgment of the managers at the 19 storage fields, and the historical conditions at each field that routinely need correcting through 20 blanket capital projects. 21 c. 22 Cost Drivers The underlying cost drivers for Blanket projects relate to equipment type and complexity, 23 operating location, availability of qualified contractors, and workload. There are a limited 24 number of qualified contractors available for compressor work in Southern California, and they 25 perform work for customers other than SoCalGas. Thus, prices for these specialized services 26 vary based on contractor workload and associated equipment lead times. Parts and equipment 27 costs are driven by the limited number of competing suppliers and the very specialized nature of 28 the hardware. 29 C. 30 This Budget Category includes costs associated with replacing failed components on 31 Storage Wells existing wells, and the design, drilling and completion of replacement wells for the injection and PEB-28 Doc #292223   1 withdrawal of natural gas and reservoir observation purposes. This includes well workover 2 contractors (major well work), drilling contractors, and component materials such as tubing, 3 casing, valves, pumps, and other down-hole equipment. Table PEB-12 below summarizes the 4 capital cost forecast for this Budget Category. 5 6 7 Table PEB-12 Southern California Gas Company Capital Expenditures for Storage Wells STORAGE WELLS C1- Wellhead Valve Replacements C2- Well Tubing Replacements C3- Wellhead Leak Repairs C4- Well Inner-string Installations C5- Submersible Pump Installations C6- Well Stimulations C7- Well Gravel Packs C8- Well Re-drills C9- Replacement Wells C10- Plug and Abandon Wells C11- Blanket Projects C12- Cushion Gas Purchase C13- SIMP Total Thousands of 2013 Dollars Estimated Estimated Estimated 2014 2015 2016 $1,194 $1,194 $1,194 $4,041 $4,041 $4,041 $1,807 $1,807 $1,807 $1,707 $1,707 $1,707 $552 $552 $552 $176 $176 $176 $3,715 $3,715 $3,715 $2,209 $2,008 $0 $10,241 $10,442 $18,273 $3,876 $6,195 $4,688 $974 $1,125 $824 $1,398 $1,398 $0 $2,008 $2,510 $24,272 $33,898 $36,870 $61,249 8 PEB-29 Doc #292223   1 2 Figure PEB-8 below illustrates the combined Wells and SIMP capital forecasts from Table PEB-12 in a graphical format. 3 4 5 Figure PEB-8 Southern California Gas Company Historical and Forecasted Wells Capital Storage Wells ‐ Recorded and Forecast Capital  70 60 Actual 5 Yr. Average Forecast SIMP $s in Millions 50 40 30 20 10 0 2009 2010 2011 2012 8 2014 2015 2016 Years 6 7 2013 The Storage Wells category in this testimony is further described using the following sub-sections: 9  C1-Wellhead Valve Replacements 10  C2-Well Tubing Replacements 11  C3-Wellhead Leak Repairs 12  C4-Well Inner-string Installations 13  C5-Submersible Pump Replacements 14  C6-Well stimulations 15  C7-Well Gravel Packs 16  C8-Well Re-drills 17  C9-Well Replacements PEB-30 Doc #292223   1  C10-Well Plug and Abandonments 2  C11-Storage Blanket Projects 3  C12-Cushion Gas Purchase 4  C13-Storage Integrity Management Program (SIMP) 5 1. 6 7 C1-Wellhead Valve Replacements a. Description SoCalGas plans to replace and upgrade gas-passing, aging, and obsolete wellhead valves 8 located throughout the four storage fields. This work is necessary due to obsolete and gas- 9 passing wellhead valves, some of which have been in service more than fifty years. Gas-passing 10 wellhead valves can create a safety, operating or environmental hazard if not replaced in a timely 11 manner. Costs in $ millions for 2014, 2015, and 2016 are forecast to be $1.194, $1.194, and 12 $1.194, respectively. The specific details regarding wellhead valve replacements identified as 13 part of routine operations are found in my capital workpapers, Exhibit PEB-06-CWP. An 14 illustrative diagram of a wellhead is provided as Appendix C, Wellhead Diagram and Downhole 15 Schematic. 16 17 b. Forecast Method Historically, there have been twelve to fifteen wellhead valve replacement projects per 18 year at an approximate cost of $85k each. Fourteen projects are planned in 2016. Costs include 19 the material and services required to secure the well, replace the wellhead valves, and return the 20 well to service. 21 22 c. Cost Drivers The cost drivers for wellhead valves are the purchase price of the valves and the 23 installation contracting services. Wellheads must be isolated from reservoir pressure and 24 depressurized in order to replace the principal valve. This is a complex operation that requires 25 controlling well pressures that can reach 3,600 psig. 26 2. 27 C2-Well Tubing Replacements a. Description 28 Continuous tubing replacements are required among the existing 229 aging wells 29 throughout the storage fields. Tubing replacements are necessary to maintain aging well 30 equipment when they have reached the end of their useful life. Leaking tubing strings can 31 become a safety or environmental hazards if not replaced in a timely manner. Costs in $ millions PEB-31 Doc #292223   1 for such work are estimated to be $4.041, $4.041, and $4.041, for 2014, 2015, and 2016 2 respectively. The estimated costs of the replacement projects include the tubing commodity 3 purchase, all of the activities involved to secure the wells, the equipment and well services 4 required for tubing removal, and the reinstallation operations. Specific details regarding tubing 5 replacements identified as part of routine operations are found in my capital workpapers, Exhibit 6 PEB-06-CWP. 7 8 9 10 b. There are seven workover rig tubing replacement projects estimated per year at an approximate cost of $575k each. Costs include the material and services required to secure the well, replace the tubing, valve work, and returning the well to service. 11 12 Forecast Method c. Cost Drivers Cost of these replacements is driven by the very specific nature and characteristics of 13 high pressure injection wells. This is a complex operation that requires controlling well 14 pressures which can reach 3,600 psig. 15 3. 16 C3-Wellhead Leak Repairs a. Description 17 Wellhead leak repairs are required among the existing 229 wells throughout the storage 18 fields. Wellhead leaks pose safety and environmental risks and must be removed from service 19 while leak repairs are in progress. The costs for these wellhead leak repairs in $ millions are 20 forecast to be $1.807, $1.807, and $1.807, for 2014, 2015, and 2016, respectively. Specific 21 details regarding cost estimates for wellhead leak repairs identified as part of routine operations 22 may be found in my capital workpapers, Exhibit PEB-06-CWP. 23 24 b. Forecast Method Four wellhead leak repairs requiring workover rig support are planned at an approximate 25 cost of $450k each. Individual project costs typically vary due to the specific equipment 26 required and configuration of the well being repaired. 27 28 c. Cost Drivers The cost driver for this activity relates to the highly specialized nature of work performed 29 on leaking high pressure wells and the skilled workforce and equipment employed. These 30 repairs can be complex operations that require controlling underground well pressures, which 31 can reach 3,600 psig. PEB-32 Doc #292223   1 4. 2 3 C4-Well Inner-String Installations a. Description When the production casing in a well reaches the end of its useful life, an inner-string 4 may be installed to extend the life of the well, depending on its mechanical condition. This 5 methodology requires the installation of smaller-sized casing due to a loss of production casing 6 integrity observed within the storage wells. Inner-string installations are used as a temporary or 7 interim mitigation strategy in response to aging or damaged storage wells. The well must be 8 removed from service and secured pending the installation process. The well will be unavailable 9 for withdrawal or injection until the work is completed. The costs for inner-string installations in 10 $ millions are projected to be $1.707, $1.707, and $1.707, for 2014, 2015, and 2016, 11 respectively. Specific details regarding inner-string installations identified as part of routine 12 operations are found in my capital workpapers, Exhibit PEB-06-CWP. 13 14 15 b. Forecast Method SoCalGas plans to complete two inner-string installations per year, at an approximate cost of $850k each. 16 c. Cost Drivers 17 The underlying cost drivers for this activity relate to the highly specialized nature of work 18 performed on high pressure wells and the skilled workforce and equipment employed. These can 19 be complex operations. 20 5. 21 22 C5-Submersible Pump Replacements a. Description SoCalGas plans to replace existing electric submersible pumps in various storage wells. 23 These pumped wells, required to control liquids and storage reservoir management, typically 24 require replacement on a one to four year cycle. If pumps are not installed in a timely manner, 25 there is the likely risk of reduced reservoir storage capacity. The forecast for 2014, 2015, and 26 2016 are $552K, $552K, and $552K, respectively. Specific details regarding these capital 27 projects are found in my capital workpapers, Exhibit PEB-06-CWP. 28 29 30 b. Forecast Method SoCalGas typically replaces two electric submersible pumps per year, at an approximate cost of $275k each. PEB-33 Doc #292223   1 c. 2 Cost Drivers The cost drivers for these projects relate to equipment type and complexity, location, and 3 availability of qualified contractors. Individual project costs can also vary due to the depth of the 4 electric submersible pump being replaced. There are a limited number of qualified contractors 5 who specialize in downhole pumps and controls. Thus, the prices for this very specialized work 6 varies according to contractor workload and associated lead times. Parts and equipment costs are 7 driven by the limited number of competing suppliers and the very specialized nature of these 8 pumps. 9 6. 10 11 C6-Well Stimulations/Re-Perforations a. Description SoCalGas plans to perform required “stimulation” or “re-perforation” of existing storage 12 wells to improve poor deliverability rates. Storage wells that experience minor productivity 13 damage can be restored via this method. These capital expenditures therefore support the 14 company’s goals of maintaining the integrity, efficiency, reliability and continuity of supply. 15 The forecast for well stimulations and re-perforations work in 2014, 2015, and 2016 is $176K, 16 $176K, and $176K, respectively. Specific details regarding these capital projects are found in 17 my capital workpapers, Exhibit PEB-06-CWP. 18 b. 19 20 The forecast is based on local knowledge of expected upgrades and capital project estimates prepared on experience. 21 22 Forecast Method c. Cost Drivers The underlying cost drivers for these projects relate to the complexity of the operations 23 and availability of qualified contractors. Parts and equipment costs are driven by the limited 24 number of competing suppliers and the very specialized nature of the hardware they produce. 25 7. 26 27 C7-Well Gravel Packs a. Description Gas flows will be restricted if a well has a failed gravel pack. Typically, a well will 28 remain out of service until the well is repaired and re-gravel packed. SoCalGas plans to replace 29 failed gravel packs from existing wells at historical rates. The costs in $ millions for well gravel 30 pack replacements are forecasted to be $3.715, $3.715, and $3.715, for 2014, 2015, and 2016, 31 respectively. Costs include the materials and services required to remove existing equipment, PEB-34 Doc #292223   1 sidetrack the well, install a new gravel pack, complete the well, and return the well to service. 2 Specific details regarding gravel pack replacements are found in my capital workpapers, Exhibit 3 PEB-06-CWP. 4 5 b. Forecast Method Typically there are two gravel pack replacements performed per year at an approximate 6 cost of $1.85 million each. Individual project costs may vary from well to well and field to field, 7 depending on the actual depth and mechanical condition of the subject well. 8 9 10 c. The underlying cost drivers for this activity relate to the highly specialized nature of work performed on high pressure wells and the skilled workforce and equipment employed. 11 8. 12 13 Cost Drivers C8-Well Re-Drills a. Description It is not uncommon for a well to experience declining or poor deliverability with age. If a 14 storage well has poor deliverability and the well is not re-drilled, the well will likely become a 15 high operating cost, low productivity asset, with negative impacts to service reliability. 16 SoCalGas expects to relocate bottom-hole locations for some wells due to poor or low 17 deliverability. The costs in $ millions for well re-drills are projected to be $2.209, $2.008, and 18 $0, for 2014, 2015, and 2016, respectively. Specific details regarding re-drill projects are found 19 in my capital workpapers, Exhibit PEB-06-CWP. 20 21 22 b. Re-drill costs are based upon historical projects of similar complexity. However, no storage well re-drills are planned for 2016. 23 24 25 c. Cost Drivers The cost drivers for this activity relate to the highly specialized nature of work performed on high pressure wells and the skilled workforce and equipment employed. 26 9. 27 28 Forecast Method C9-Well Replacements a. Description SoCalGas plans to replace mechanically constrained wells with curtailed deliverability, 29 along with high operating cost aging injection/withdrawal wells and their associated production, 30 with new wells that provide higher deliverability rates. These new wells are necessary 31 replacements due to lost deliverability from failed gravel packs or poor deliverability rates from PEB-35 Doc #292223   1 other causes. It also includes the replacement of lost withdrawal capacity from the required 2 abandonments of aging storage wells. The costs for replacement storage wells in $ millions are 3 forecast to be $10.241, $10.442, and $18.273 for 2014, 2015, and 2016, respectively. 4 At the end of the 2013/2014 winter withdrawal season, during a period of high demand 5 and low field inventory not seen in recent years, Aliso Canyon was not able to meet the 6 deliverability levels expected from existing wells. Declining performance of older wellbores, 7 along with the necessary plugging of problem wells, resulted in the field falling short of delivery 8 expectations by more than 350 MMCFD. Having operated at higher inventories in recent years, 9 this 20% downgrading of well performance was not readily apparent until early 2014. 10 With modern well design and completion techniques, opportunities exist to reduce the 11 number of storage wells by drilling new replacement wells in a manner that may allow for better 12 than a one-for-one replacement. Depending on the storage field and its geology, a newly drilled 13 and completed replacement well is likely to provide the replacement deliverability of two or 14 more existing older wells. This scenario would be repeated as each new replacement storage 15 well is drilled, thus potentially reducing the overall storage well count and operating expenses. 16 These projects will locate and prepare drill sites, drill and complete new replacement 17 storage injection/withdrawal wells to be strategically located throughout the Storage Fields. 18 Included are all services and materials to complete each well. The anticipated numbers and 19 locations of the replacement wells are as follows: 20 21 22  2014 - Two Aliso Canyon Storage Wells. This work is required to replace naturally declining deliverability from existing wells, and wells that were abandoned due to integrity concerns; 23 24 25 26  2015 - Two Goleta Storage Wells. This work is necessary to improve lost deliverability as well as decrease the footprint of the facility by bringing remotely located wells in a high consequence area closer to the main station and removing injection/withdrawal lines from environmentally-sensitive areas; and 27 28 29  2016 - Three Aliso Canyon Storage Wells. This work is needed to continue the replacement of lost deliverability due to the natural productivity declines from aging wells described above. 30 Specific details regarding storage well replacements are found in my capital workpapers, 31 Exhibit PEB-06-CWP. PEB-36 Doc #292223   1 b. Forecast Method 2 Planned replacement wells located among the storage fields will vary in cost, but average 3 approximately $5-6 million each. Costs are based on historical well drilling costs combined with 4 recent vendor cost estimates. 5 c. Cost Drivers 6 The underlying cost drivers for these capital projects relate to the highly specialized 7 nature of work performed on high pressure wells and the necessarily skilled workforce and 8 equipment employed. These older storage wells typically require high cost casing repairs 9 ($700K or more) per occurrence and/or repeated re-gravel packing of the wells due to highly 10 erosive sand production. Costs of replacing the gravel packs of these aging wells are typically in 11 the range of $2 million each. Phasing in these new higher-deliverability replacement wells and 12 eliminating the high cost aging wells over time, may reduce the Company’s long term operating 13 costs by reducing the need for frequent, high cost, casing repairs and gravel pack capital projects. 14 10. 15 16 C10-Well Plug and Abandonments a. Description SoCalGas plans to abandon aging, mechanically unsound wells that are beyond their 17 useful lives. Required abandonments are becoming more frequent as various storage wells reach 18 or exceed their useful lives. These subject wells become high risk, high operating cost assets due 19 to poor or declining mechanical integrity, or complete lack of productivity due to age. A number 20 of the abandonments are required for the removal of wells and their operations from 21 environmentally sensitive areas or higher public risk areas and relocating the new replacement 22 storage wells within storage field boundaries. 23 Currently there are 26 existing mechanically-unsound, unproductive, or aging storage 24 wells located in environmentally-sensitive areas. SoCalGas will focus on the abandonment of 25 aging storage wells located in environmentally-sensitive or high consequence areas. Projected 26 costs include the material and services required to plug and abandon the wells in a manner that 27 meets or exceeds California DOGGR requirements. The cost in $ millions for well plug and 28 abandonments are forecasted to be $3.876, $6.195, and $4.688, for 2014, 2015, and 2016, 29 respectively. Specific details regarding well abandonment projects are found in the capital 30 workpapers, Exhibit PEB-06-CWP. PEB-37 Doc #292223   1 b. Forecast Method 2 Eight wells per year are planned for abandonment among the existing storage fields, at an 3 approximate cost of $600K each. The individual well abandonment costs will vary depending on 4 the condition of the well at the time of the abandonment, surface location of the well, in addition 5 to the depth of the well to be abandoned. 6 7 c. Cost Drivers The underlying cost drivers for these capital projects relate to the highly specialized 8 nature of work performed on high pressure gas wells and the necessarily skilled workforce and 9 equipment employed. 10 11. 11 12 C11-Storage Blanket Projects a. Description SoCalGas plans to build and place in service multiple smaller projects with individual 13 costs that do not warrant the preparation of individual workpapers. These forecasted capital 14 expenditures support the goals of maintaining the safety of the public and employees, as well as 15 operating efficiency, reliability and continuity of supply. The costs of individual projects in this 16 category will vary from as low as ten thousand to as high as several hundreds of thousands of 17 dollars. They include shallow zone work in the Aliso Canyon field, projects related to geology 18 and storage engineering, and smaller technology upgrades. The forecast in $ million for 2014, 19 2015, and 2016 is $0.974, $1.125, and $0.824, respectively. Specific details regarding these 20 projects are found in my capital workpapers, Exhibit PEB-06-CWP. 21 22 b. Forecast Method The forecasts of these smaller projects are based on local knowledge of required upgrades 23 and capital maintenance projects prepared by experienced professionals who have worked in the 24 Storage fields for years. This method is appropriate because these professionals are responsible 25 for preparing a list of upgrades and projects, which is updated and prioritized regularly, based on 26 equipment age, wear and tear, failure history, and technical obsolescence. 27 28 c. Cost Drivers The underlying cost drivers for these kinds of projects relate to equipment type and 29 complexity, operating location, availability of qualified contractors, and workload. There are a 30 limited number of qualified contractors available for Storage field work. Thus, the prices for this 31 very specialized work varies according to the contractor’s workload and associated lead times. PEB-38 Doc #292223   1 Parts and equipment costs are driven by the limited number of competing suppliers and the very 2 specialized nature of the hardware. 3 12. 4 5 C12-Cushion Gas Purchases (Honor Rancho Expansion) a. Description SoCalGas plans to purchase cushion gas to support the final phase of the Honor Rancho 6 expansion project. Cushion gas is the volume of gas intended to serve as the permanent 7 inventory within a storage reservoir that is required to maintain adequate pressure for 8 deliverability rates throughout the withdrawal season. The need for storage capacity expansion 9 and its relationship to Gas System supply reliability was established by the CPUC in decision 10 (D) 10-04-034. That discussion is incorporated herein by reference. The cost for cushion gas 11 purchases in $ million is forecast to be $1.398, $1.398, and $0, for 2014, 2015, and 2016, 12 respectively. Specific details regarding this estimate of cushion gas costs may be found in my 13 capital workpapers, Exhibit PEB-06-CWP. 14 15 b. Costs are estimated for the purchase of 300 MMCF, at a price of $4.55 per decatherm. 16 17 c. Cost Drivers The unit cost of the gas is driven by conditions in the natural gas market. 18 13. 19 20 Forecast Method C13-Storage Integrity Management Program a. Description Reactive-type well repair work performed by Storage related to safety situations observed 21 as part of routine operations has increased in recent years. In fact, a negative well integrity trend 22 seems to have developed since 2008. The increasing number of well integrity conditions 23 summarized in Table PEB-8 above are attributed primarily to the frequency of use, operating 24 environment, age, and length of time the wells have been in service. In contrast to the reactive 25 capital work discussed above, the SIMP is intended to proactively identify, diagnose, and 26 mitigate potential safety and/or integrity problems associated with gas storage wells. It is 27 important to distinguish that SIMP is incremental work above and beyond the levels traditionally 28 performed. As such, it consists of accelerated mitigation work performed over a condensed 29 period of time in response to the thorough well integrity inspections described above in section II 30 D-2 of my testimony. Early identification and mitigation of well integrity issues will improve PEB-39 Doc #292223   1 safety and increase reliable gas deliveries. The capital costs in $ million for the SIMP are 2 forecasted to be $2.008, $2.510, and $24.272 for 2014, 2015, and 2016, respectively. 3 Safety and/or integrity conditions that are presently unknown may exist within the high 4 pressure (up to 3,600 psig) above ground pipe laterals and below ground facilities that comprise 5 of 229 aging gas storage field wells that can exceed 13,000 feet in depth. Some SoCalGas wells 6 are more than 80 years old while the average age of all Storage wells is 52 years. A proactive, 7 methodical, and structured approach, using advanced inspection technologies, such as ultra-sonic 8 and neutron type casing logs, along with risk management disciplines to address well integrity 9 issues before they result in unsafe conditions for employees or the public, or become major 10 incidents, is a prudent operating practice. In addition, some SoCalGas wells are located within 11 close proximity to residential dwellings, as depicted in Figure PEB-2. 12 The primary threats to the SoCalGas well facilities that SIMP will address are internal 13 and external corrosion, and erosion.12 Immediate repairs may be necessary to minimize safety 14 risks. Lesser risk integrity work will be prioritized to plan and efficiently execute mitigation 15 actions. 16 SoCalGas proposes that these capital costs receive two-way balancing account treatment 17 due to the highly unpredictable nature of estimating well mitigation costs. Factors contributing 18 to the uncertainty include the unknown number of at-risk wells and their integrity status, the 19 highly variable nature of well mitigation strategies, the uncertainty surrounding the volume and 20 degree of repair work to be performed, the variable cost of consulting experts, when required, 21 specialty equipment and skillful operators to be procured, and erratic field conditions typically 22 encountered once repair work is initiated. All well work to be performed will be dependent on 23 the site-specific conditions found at the time work is initiated. While average costs were utilized 24 to prepare initial forecasts for SIMP, actual conditions and the scale of work to be performed can 25 only be determined after the well is actually entered with inspection devices and/or repair tools. 26 Given the fact that many of the wells have not been worked on in recent years, and the mature 27 age of some wells, major problems and fixes of unknown costs are anticipated. 28 29 Past work on well Frew 3 at Aliso Canyon in 2013 is a good example of the wide variability in mitigation costs. Frew 3 was originally targeted for a tubing leak repair scheme,                                                              12 The gas withdrawn from storage formations typically contains water, sand, and reactive gas constituents such as carbon dioxide that can corrode or erode storage well components especially during periods of high demand. PEB-40 Doc #292223   1 estimated to cost approximately $600,000. Once the well was entered and repairs began, the 2 wellbore was found to be compromised due to shifting geological formations requiring extensive 3 work. The net result was a decision to abandon the well at a cost of $1.39 million, more than 4 double the original repair estimate. 5 In addition, costs for the well rigs required for SIMP are dependent on activity 6 throughout the oil and gas industry. The ability to secure equipment and associated prices are 7 dependent on energy demand and rig availability worldwide. Financial outlays to secure rigs and 8 oil/gas field services can vary greatly over time due to domestic and foreign developments 9 related to energy. 10 11 b. Forecast Method The forecast method used for the SIMP capital work is zero-based. This approach is 12 most appropriate because it is an incremental program. The costs per units of work are based on 13 historical averages, and internal labor support was established based on practical considerations 14 and experience. Actual well repair methods will be based upon assessment findings, however, 15 and optimized among the options described in the Capital Costs Section III C-Wells of my 16 testimony. Unit costs based on historical prices of similar type work for the mitigation work 17 would most likely consist of: 18  Wellhead Valve Replacements ($85k) 19  Well Tubing Replacements ($575k) 20  Wellhead Leak Repairs ($450k) 21  Well Inner-string Replacements ($850k) 22 Mitigation work could also consist of well abandonments, well redrills or well 23 replacements typically cost approximately $0.6 million, $2.0 million, and $6 million, 24 respectively. 25 The decision whether to re-drill an existing well or drill a replacement well as a risk 26 mitigation strategy depends upon localized conditions encountered during the downhole 27 inspections. If data indicate poor conditions of casing in the upper part of the wellbore, a re-drill 28 solution is generally not an option. Other site-specific conditions that could justify a 29 replacement well over a re-drill are wells with a small casing, existing condition of the 30 well/casing cement bond, proximity of integrity issues relative to the surface, and the geographic 31 location of the well within the reservoir. Re-drill versus replacement decisions will be made by PEB-41 Doc #292223   1 experienced storage reservoir engineering personnel using knowledge, professional judgment 2 and site specific information. 3 Labor totaling 6.5 FTEs to support the capital program consists of two Contract 4 Administrators for Aliso Canyon, and one each for the remaining three fields, one Well 5 Mitigation Project Manager, and 0.5 FTE clerical support. Company labor estimates are 6 presented in Table PEB-13 below. 7 8 9 Table PEB-13 Southern California Gas Company SIMP Capital Cost Detail Description Annual Number Wells Requiring Capital Mitigation Work Lateral Piping Replacements Company Labor FTEs Well Inspection Costs Reassigned to Capital Total Capital 28 5 6.5 28 - 10 c. 11 Unit Estimated Cost Total (Thousands of $2013) $429 $12,014 $75 $375 N/A $945 N/A $10,936 $24,272 Cost Drivers The most significant cost driver for this uniquely specialized work performed on high 12 pressure wells is the availability of workover rigs, material costs, the skilled field and technical 13 workforce required to produce and analyze data, and the equipment to be employed. Other cost 14 drivers include the unique solutions required to address the conditions discovered during 15 exploratory examinations of the wells, equipment, well design, and permitting requirements. 16 D. Storage Pipelines 17 This Budget Category includes costs associated with upgrading or replacing failed field 18 piping and related components. The cost forecast for this work is summarized in Table PEB-14 19 below. 20 PEB-42 Doc #292223   1 2 3 Table PEB-14 Southern California Gas Company Capital Expenditures for Storage Pipelines STORAGE PIPELINES D1- Valve Replacements D2- Aliso Pipe Bridge Replacement D3- Aliso Injection System Debottlenecking D4- Aliso Canyon Piping Improvements D5- Playa del Rey Withdrawal Debottlenecking D6- Pipeline Blanket Projects Total 4 Thousands of 2013 Dollars Estimated Estimated Estimated 2014 2015 2016 $889 $889 $688 $505 $3,526 $0 $0 $505 $505 $1,313 $152 $505 $505 $2,526 $0 $3,334 $2,485 $3,233 $6,546 $10,083 $4,931 Figure PEB-9 below depicts the Storage Pipeline costs from Table PEB-14. 5 6 7 Figure PEB-9 Southern California Gas Company Historical and Forecasted Storage Pipelines Capital Storage Pipelines ‐ Recorded and Forecast Capital 15 Actual 5 Yr. Average Forecast $s in Millions 12 9 6 3 0 2009 2010 2011 2012 2013 2014 2015 2016 Years 8 9 10 The Storage Pipelines category in this testimony is further described using the following sub-sections: 11  D1-Valve Replacements 12  D2-Aliso Pipe Bridge Replacement 13  D3-Aliso Injection System Debottlenecking PEB-43 Doc #292223   1  D4-Aliso Canyon Withdrawal System Debottlenecking 2  D5-Playa del Rey Withdrawal Debottlenecking 3  D6-Blanket Projects 4 1. 5 6 D1-Valve Replacements a. Description Valves within the storage fields can leak or allow gas to pass as they wear and age.   7 SoCalGas plans to replace various valves of differing sizes and pressure ratings throughout the 8 year, depending on line shut-in capability and valve conditions. The costs for valve 9 replacements are estimated to be $889k, $889k, and $688k for 2014, 2015, and 2016, 10 respectively. Specific details regarding this valve work may be found in my capital workpapers, 11 Exhibit PEB-06-CWP. 12 13 b. Forecast Method Historical average costs are approximately $20K per valve. The estimated number of 14 replacements, approximately 5% of the larger field valves every year, is based on recent 15 operational experience. 16 17 c. Cost Drivers The underlying cost drivers for this capital category relate to the purchase price of the 18 valves and their installation costs. This includes specialized work performed on high pressure 19 gas lines and the skilled workforce and equipment employed for replacements. 20 2. 21 22 D2-Aliso Pipe Bridge Replacement a. Description SoCalGas plans to relocate an existing pipe rack in Aliso Canyon out of a ravine area 23 with an active landslide and soil erosion condition that is threatening several existing pipe 24 supports. Failure of pipe and supports in this ravine could result in the potential loss of gas 25 injection/withdrawal capabilities of 21 wells in Aliso Canyon’s east field. The combined 26 withdrawal capacity of these wells is approximately 600 MMCFD. A Rupture of these pipes 27 could result in the release of crude oil and brine water into the stream at the bottom of the ravine. 28 The costs in $ million for the Aliso Pipe Bridge Replacement are projected to be $0.505, $3.526, 29 and $0 for 2014, 2015, and 2016, respectively. Specific details regarding this project may be 30 found in my capital workpapers, Exhibit PEB-06-CWP. PEB-44 Doc #292223   1 2 3 b. The project costs were derived by estimates from structural steel fabricators and installation contractors. 4 5 Forecast Method c. Cost Drivers The underlying cost driver for this capital project relates to the soil types, customized 6 design, permits, steel fabrication, and the highly specialized nature of work performed on high 7 pressure gas piping, and the skilled workforce and equipment employed. 8 3. 9 10 D3-Aliso Injection System Debottlenecking a. Description Through the evolution of the Aliso Canyon storage field, piping restrictions have 11 developed. SoCalGas plans to improve the injection capacities at Aliso Canyon through the 12 installation of larger diameter pipe and associated pipe supports. With new projects such as 13 Aliso Canyon Turbine Replacement, and planned well replacements, the system piping will be 14 studied to eliminate sections that restrict the flow of gas to the storage wells. Pipe will be sized 15 to meet the specific injection criteria. This project will allow for a more efficient gas injection 16 process. If bottlenecks are not removed, adequate pipe capacity at the intended rate of injection 17 at maximum capacity will not be achieved. The costs for the injection system debottlenecking 18 are forecast to be $0, $505k, and $505k for 2014, 2015, and 2016, respectively. Specific details 19 regarding this project are found in my capital workpapers. See 06-CWP. 20 21 b. Estimated costs are based on recent projects of similar pipe size, scope and complexity. 22 23 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to material costs and the highly 24 specialized nature of work performed on high pressure gas injection piping and the skilled 25 workforce and equipment employed. 26 4. 27 28 D4-Aliso Canyon Piping Improvements a. Description SoCalGas plans to perform necessary work to minimize piping restrictions in the Aliso 29 Canyon withdrawal system. In addition, work is also planned for a remote well-kill safety 30 system, installation of field utility gas system (Master Lease Gas), and replacement of high 31 pressure liquid handling pipelines. The improvement of these systems will allow for remote PEB-45 Doc #292223   1 killing of the wells, a cleaner source of motive gas in the field for equipment, and the continued 2 reliability of liquid-carrying piping. The liquid handling pipelines are critical to liquid removal 3 operations from the high pressure gas system that transports, cleans, dehydrates, and meters gas 4 from the facility. If the liquid handling pipelines were to fail, gas deliveries may be significantly 5 impacted or sent through metering without complying with standards for water content in 6 pipeline-quality natural gas. Safety equipment in the field also requires clean motive gas for 7 proper operations. Each of these projects will require new piping, pipe supports and possibly 8 pipe trenches. The costs for these piping improvements are forecast to be $1,313k, $152k, and 9 $505k for 2014, 2015, and 2016, respectively. Specific details regarding these projects may be 10 found in my capital workpapers, Exhibit PEB-06-CWP. 11 12 13 b. Estimated costs are based on recent projects of similar equipment size, scope and complexity. 14 15 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature 16 of work performed on high pressure pipelines and the skilled workforce and equipment 17 employed. 18 5. 19 20 D5-Playa del Rey Withdrawal Debottlenecking a. Description SoCalGas plans to perform necessary work to alleviate system bottlenecking in the Playa 21 del Rey withdrawal system. Upgrade of the lower field equipment and piping would help 22 maintain deliverability capacity while achieving the desired standards for water content in 23 pipeline-quality natural gas. The work will include replacement of withdrawal equipment and 24 installation of newly resized piping. The costs in $ million are estimated to be $0.505, $2.526, 25 and $0, for 2014, 2015, and 2016, respectively. Specific details regarding this project may be 26 found in my capital workpapers, Exhibit PEB-06-CWP. 27 28 29 b. Forecast Method This cost estimate is based on previously-completed work, vendor quotes for similar equipment, and current contractor rates. PEB-46 Doc #292223   1 2 3 c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature of work performed and the skilled workforce and equipment employed. 4 6. 5 D6-Pipeline Blanket Projects a. Description 6 SoCalGas plans to perform necessary work to alleviate various pipeline issues. This can 7 include various projects including pipe replacements, expansions, upsizing, supports, corrosion 8 protection, and other elements related to piping systems. The upgrade of station piping will help 9 maintain injection and deliverability capacity. The costs in $ million are estimated to be $3.334, 10 $2.485, and $3.233, for 2014, 2015, and 2016, respectively. Specific details regarding these 11 projects may be found in my capital workpapers, Exhibit PEB-06-CWP. 12 13 14 b. This cost estimate is based on the assumption that future costs and projects will be similar in scope and pricing to historical levels. 15 16 17 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature of work performed and the skilled workforce and equipment employed. 18 E. Storage Purification Systems 19 This budget category forecasts costs associated with equipment used primarily for the 20 removal of impurities from, or the conditioning of, natural gas withdrawn from storage. 21 Examples of equipment included in this area are dehydrators, coolers, scrubbers, boilers, pumps, 22 valves, piping, power supply, controls, and instrumentation. Table PEB-15 below summarizes 23 the forecast of capital expenditures for Storage Purification Systems. 24 25 26 Table PEB-15 Southern California Gas Company Capital Expenditures Purification Systems STORAGE PURIFICATION SYSTEMS E1- Aliso Canyon Dehydration Upgrades E2- Honor Rancho Dehydration Upgrades E3- Goleta Dehydration Upgrades E4- Purification Blanket Projects Total PEB-47 Doc #292223 Thousands of 2013 Dollars Estimated Estimated Estimated 2014 2015 2016 $1,018 $1,018 $1,018 $3,094 $992 $0 $3,055 $1,018 $0 $1,629 $4,577 $6,587 $8,796 $7,605 $7,605   1 Figure PEB-10 below illustrates the Purification Systems forecast from Table PEB-15. 2 3 4 Figure PEB-10 Southern California Gas Company Historical and Forecasted Purification Systems Capital Storage Purification Equipment   Recorded and Forecast Capital Actual 5 Yr. Average Forecast $s in Millions 15 12 9 6 3 2009 2010 2011 2012 2013 2014 2015 2016 Years 5 6 7 The Storage Purification Systems category in this testimony is further described using the following sub-sections:  8  E1-Aliso Canyon Dehydration Upgrades 9  E2-Honor Rancho Dehydration Upgrades 10  E3-Goleta Dehydration Upgrades 11  E4-Purification Blanket Projects 12 1. 13 14 E1-Aliso Canyon Dehydration Upgrades a. Description This project will include the installation of new gas and glycol filters for improved gas 15 conditioning. Instrumentation upgrades will also improve the ability to remotely monitor the 16 plant during operation. In addition, the site Motor Control Center will be replaced to better 17 support existing and new equipment. The Dehydration 2 plant at Aliso Canyon has withdrawal 18 capacity of approximately 750 MMCFD. SoCalGas has plans to upgrade the Dehydration 2 19 plant to increase its withdrawal capacity. Without this project, the station may not be able to 20 adequately comply with standards for water content in pipeline-quality natural gas and achieve PEB-48 Doc #292223   1 future planned increases in withdrawal capacity. The estimated forecasts in $ million for this 2 project are $1.018, $1.018, and $1.018, for 2014, 2015, and 2016 respectively. Specific details 3 regarding this project may be found in my capital workpapers, Exhibit PEB-06-CWP. 4 5 6 b. Costs are based on quotes provided by vessel fabricators, equipment manufacturers, contractor estimates, and similar work completed on previous projects. 7 8 9 10 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature of work performed, the necessarily skilled workforce, equipment employed, and the cost of materials. 11 2. 12 E2-Honor Rancho Dehydration Upgrades a. Description 13 SoCalGas plans to separate dehydration trains and install filters to allow for more 14 flexibility of operations, less downtime during routine maintenance, improved gas conditioning, 15 and a reduction in glycol degradation. The Programmable Logic Controller system will be 16 upgraded to meet the new operating requirements and instrumentation needs. Without this 17 project, the station may require extended and more frequent shutdowns as part of routine 18 maintenance activities. In addition, this project will also allow the station to better achieve water 19 content standards in pipeline-quality natural gas. The costs for improvements in $ million are 20 $3.094, $0.992, and $0, for 2014, 2015, and 2016, respectively. Specific details regarding this 21 capital project are found in my capital workpapers, Exhibit PEB-06-CWP. 22 23 24 b. Costs are based on quotes provided by vessel fabricators, equipment manufacturers, contractor estimates, and similar work completed on previous projects. 25 26 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature 27 of work performed, the necessarily skilled workforce and equipment employed and the cost of 28 materials. PEB-49 Doc #292223   1 3. 2 3 E3-Goleta Dehydration Upgrades a. Description SoCalGas plans to install new gas and glycol filters, heat exchangers, glycol regeneration 4 equipment upgrades and instrumentation for remote monitoring in order to improve dehydration 5 efficiency. This project will also allow the station to better achieve water content standards in 6 pipeline-quality natural gas. Costs for the Goleta dehydration project in $ million are projected 7 to be $3.055, $1.018, and $0 for 2014, 2015, and 2016, respectively. Specific details regarding 8 this capital project may be found in my capital workpapers, Exhibit PEB-06-CWP. 9 10 11 b. Costs are based on quotes provided by vessel fabricators, equipment manufacturers, contractor estimates, and similar work completed on previous projects. 12 13 Forecast Method c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature 14 of work performed, the necessarily skilled workforce and equipment employed, and the cost of 15 materials. 16 4. 17 E4-Purification Blanket Projects a. Description 18 SoCalGas plans to perform necessary work to alleviate gas processing and purification 19 issues. This can include work on various equipment including dehydrators, coolers, scrubbers, 20 boilers, pumps, valves, piping, power supply, controls, and instrumentation. Upgrade of 21 purification equipment will help maintain deliverability capacity and allow the station to better 22 achieve water content standards in pipeline-quality natural gas. The costs in $ million are 23 estimated to be $1.629, $4.577, and $6.587, for 2014, 2015, and 2016, respectively. Specific 24 details regarding this project may be found in my capital workpapers, Exhibit PEB-06-CWP. 25 26 b. This cost estimate is based on historical and expected levels of work. 27 28 29 Forecast Method c. Cost Driver(s) The underlying cost drivers for this capital project relate to the highly specialized nature of work performed and the skilled workforce and equipment employed. PEB-50 Doc #292223   1 F. Storage Auxiliary Systems 2 This budget code includes work on various types of field equipment not included in other 3 budget codes such as instrumentation, measurement, controls, electrical, drainage, infrastructure, 4 safety, security, and communications systems. The costs associated with this work are 5 summarized in Table PEB-16 below. 6 7 8 Table PEB-16 Southern California Gas Company Capital Expenditures for Storage Auxiliary Systems STORAGE AUXILIARY SYSTEMS F1-Aliso Central Control Room Modernization F2-Aliso Main Plant Power Line Upgrade F3-Aliso Sesnon Gathering Plant Project F4-Auxiliary Systems Blanket Projects Total 9 Thousands of 2013 Dollars Estimated Estimated Estimated 2014 2015 2016 $2,021 $1,010 $0 $1,010 $0 $0 $1,111 $303 $1,010 $10,256 $10,609 $7,938 $14,398 $11,922 $8,948 Figure PEB-11 below depicts the Auxiliary Systems cost forecast from Table PEB-16. 10 11 12 Figure PEB-11 Southern California Gas Company Historical and Forecasted Auxiliary Systems Capital Storage Auxillary Systems‐ Recorded and Forecast Capital Actual 5 Yr.Average Forecast $s in Millions 15 12 9 6 3 2009 2010 2011 2012 2013 Years 13 PEB-51 Doc #292223 2014 2015 2016   1 2 The Auxiliary Systems category in this testimony is further described under the following sub-sections: 3  F1-Aliso Canyon Central Control Room Modernization 4  F2-Aliso Canyon Main Plant Power Line Upgrade 5  F3-Aliso Canyon Sesnon Gathering Plant Project 6  F4-Auxiliary Equipment Blanket Projects 7 1. 8 9 F1-Aliso Central Control Room Modernization a. Description SoCalGas plans to update, modernize and reconfigure the control room at the Aliso 10 Canyon storage facility. This project includes modernization of control room displays, 11 communication equipment, and building renovation. Without this upgrade of the control room, 12 the station operators would be unable to efficiently monitor and operate the new equipment. The 13 costs for the Aliso Central Control Room Modernization project in $ million are forecast to be 14 $2.021, $1.010, and $0, for 2014, 2015, and 2016 respectively. Specific details regarding this 15 project may be found in my capital workpapers, Exhibit PEB-06-CWP. 16 17 18 b. Estimated costs are based on recent projects of similar scope and complexity in addition to recently-received vendor quotes. 19 20 21 c. Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature of work performed, the skilled workforce and equipment employed, and the cost of materials. 22 2. 23 24 Forecast Method F2-Aliso Main Plant Power Line Upgrade a. Description SoCalGas plans to improve the overhead power system with new poles and wire to 25 withstand 120 mile per hour wind load requirements. The new system will continue to allow the 26 main plant, dehydration units and gathering plant to be energized by Southern California Edison, 27 onsite generators, or alternate powers sources. Portions of the system will be installed 28 underground. The project will eliminate wood poles, reduce fire danger and strengthen the 29 electrical lines for high wind conditions. This project will provide Aliso Canyon with increased 30 electrical reliability by upgrading the electrical system infrastructure at the main plant, PEB-52 Doc #292223   1 dehydrators, and gathering plants to remain electrified with utility power during “Red Flag” 2 events. South Coast Air Quality Management District variance requests are required for 3 operation of the onsite generators used during red flag events. This project will also decrease the 4 need for air quality permit variances. The costs forecast in $ million are $1.010, $0.500, and $0, 5 for 2014, 2015, and 2016, respectively. Specific details regarding this capital project may be 6 found in my capital workpapers, Exhibit PEB-06-CWP. 7 8 9 10 b. Costs are based on previously-completed work of similar content and scope. Similar work that increased the wind load capability of the local electrical system was completed at the Porter water injection site in 2012. 11 12 13 c. Cost Drivers The underlying cost drivers for this capital project relate to the design, the specialized nature of work performed, the availability of qualified workers and equipment purchases. 14 3. 15 16 Forecast Method F3-Aliso Sesnon Gathering Plant Project a. Description Safety items of concern identified during a process hazard analysis of the pressure relief 17 system at the Aliso Sesnon Gathering Plant will be addressed with a redesign. The current 18 pressure relief system has several critical low points that could interfere with the gathering plant 19 pressure relieving equipment during a full system blow down. The liquid buildup could 20 potentially overwhelm the liquid removing equipment, causing gas withdrawal rates to be 21 reduced. The relief vessel will be relocated, system piping will be modified to eliminate low 22 points, and relief valves will be replaced to better satisfy process conditions. The costs for this 23 project in $ million are forecast to be $1.111, $0.303, and $1.010, for 2014, 2015, and 2016, 24 respectively. Specific details regarding this work may be found in my capital workpapers, 25 Exhibit PEB-06-CWP. 26 27 b. Estimated costs are based on vendor quotes and previously completed work. 28 29 Forecast Method c. Cost Drivers The underlying cost drivers for these capital projects relate to the highly-specialized 30 nature of work performed, the availability of necessarily-skilled workforce and equipment 31 employed and the cost of materials. PEB-53 Doc #292223   1 4. 2 F4-Auxiliary Systems Blanket Projects a. 3 Description SoCalGas plans to perform necessary work to alleviate instrumentation, Supervisory, 4 Control and Data Acquisition, measurement, controls, electrical, cyber security, and other 5 auxiliary systems support issues. This can include work on various equipment including, 6 coolers, scrubbers, boilers, pumps, valves, piping, and power supplies. The upgrade of auxiliary 7 systems will help maintain safety, security, deliverability, and reliability in the delivery of 8 pipeline-quality natural gas. The costs of this project in $ million are estimated to be $10.256, 9 $10.609, and $7.938, for 2014, 2015, and 2016, respectively. Specific details regarding this 10 project may be found in my capital workpapers, Exhibit PEB-06-CWP. 11 b. 12 Forecast Method This cost estimate is based on historical and expected levels of work. 13 c. 14 Cost Drivers The underlying cost drivers for this capital project relate to the highly specialized nature 15 of work performed and the skilled workforce and equipment employed. 16 IV. CONCLUSION 17 In this testimony, I describe activities and projects necessary for SoCalGas to achieve its 18 goals of maintaining the safety and reliability of critical gas underground storage infrastructure. 19 The expenditures discussed in this testimony are required to maintain public and employee safety 20 while cost-effectively meeting customer needs, in compliance with mandated regulatory 21 requirements. My O&M and capital forecasts represent a reasonable level of funding for the 22 critical activities and capital projects planned during this forecast period. The forecasts of the 23 planned O&M and capital expenditures represented in this testimony are appropriate and 24 prudently derived, and should be adopted by the Commission. Implementation of the proposed 25 SIMP is justified and prudent and the request for balancing account treatment for SIMP costs is 26 reasonable and should be adopted. 27 This concludes my prepared direct testimony. PEB-54 Doc #292223   1 2 3 V. WITNESS QUALIFICATIONS My name is Phillip E. Baker. I am employed by Southern California Gas Company. My business address is 9400 Oakdale Ave., Chatsworth, California 91313-6511. 4 I am the Director of Storage. In this capacity, I am responsible for maintaining the 5 integrity of the storage system to ensure a safe, reliable supply of natural gas for customers 6 throughout the SoCalGas and SDG&E service territory. 7 I have a Bachelor of Science degree in Civil Engineering from California State 8 University at Los Angeles. I have worked for SoCalGas for thirty-five years, with a broad 9 background in engineering and gas operations. Throughout my career I have held various staff 10 and operations positions in Gas Distribution, Engineering, Gas Transmission, Fleet, Facilities 11 and Logistics, and Customer Services. In recent years, I have held the positions of Director- 12 Customer Services, Director-Distribution Services, Director-Commercial and Industrial Services. 13 I was named to my present position, Director-Storage, in 2013. 14 I have previously testified before the Commission. PEB-55 Doc #292223   Appendix A Glossary of Acronyms BCF Billion Cubic Feet BCFD Billion Cubic Feet per Day CPUC California Public Utilities Commission DIMP Distribution Integrity Management Program DOGGR California Department of Oil, Gas and Geothermal Resources DOT United States Department of Transportation FTE Full Time Equivalents MMCF Million Cubic Feet MMCFD Million Cubic Feet per Day NERBA New Environmental Regulatory Balancing Account O&M Operations and Maintenance PSIG Pounds per Square Inch Gauge SoCalGas Southern California Gas Company SIMP Storage Integrity Management Program TCAP Triennial Cost Allocation Proceeding TIMP Transmission Integrity Management Program PEB-A-1  Doc #292223  Appendix Underground Storage of Natural Gas PEB -B-1 Doc #292223 Eula 5E a .- .Iw HI mam. 4.3.51.3 waging?.303? PEB-B-2 Doc #292223 Doc #292223 PEB-B-3 Underground ., . .. - . -.-..- .. storage is based on the simpll! numise that if an unduqrnund rock -.- - . held OII - . -. - .- - andqas securer for an ans of years. I1 could con?n toduwundnr . . .. . .- - . . . I. 1' canholled conditions. 3 2: m. PEB-B-4 Doc #292223 Doc #292223 PEB-B-S . Int GOOD momma FIELD PEB-B-6 Doc #292223 .71: PEB-B-7 Doc #292223 . what-Jo . .. SCI .3 .H.u:n .Iauu: I a PEB-B-8 Doc #292223 Doc #292223 PEB-B-9 stand! (Duration: adlva?led on onlus 1min our gas con1r0 cor-tar to specific storage fields Customarllr. storm ls required for "nor-n! load balancing: Injecting summer suppHos at gas undeman to be held in resem for win!" unnatural. i opmnus uuotnanoum Doc #292223 SIDRAGE FACILITY f= V. 4.- I I Just as In storage the signal to cemmnce withdrawal of gas from storage is relayed to the fluid from our maln on control center. Withdrawal ls usually ordered to met Maw custom" domino 0 throughout tho cold. uth winter suson: a on air Dollutlon raised! days: or a durinq peak-load conditions. than gas. from :toraqt augment: the uolumu constantly "ouran 111 from out-of- sllto subpluers. Doc #292223 SIS UHDERGEOUND STORAGE SITES South-em Calilornid Ga: a subsidiary Sempra Energy. operafour underground stoma: fields. Each faci ty has tie-velaan due In unlqu geologic characterislics which makes :1 Ideal for ma; stulaqe. The wait none at these Sites pe?nrms an assent-an function for all - - - nurqa: cuslomcrsintno - . - -. Southern Ca Umllarea .- - .. . . . . We mark to cantinue la - . meet our :ustomus' nuds In a safe and environmentally sound manner. lhcrebv assurlnq in. cant-n uance of good naiqnbor relations with surmundinq rundents. 35% .6 zozazz< PEB-B-12 Doc #292223 Doc #292223 PEB-B-13 FANS IBOUT NATURAL GIS Lg]. . 'upll i . lahl mun: . -- l l- 't hunting '1 .lil In'mm Jrl?xan rum - I: hulnmuv wht?ll whim (arm- a: "mu-n wizh vg-niu?[ml-rim n1 5., . r. \t-nmm.? .ru-Ig'. -. Appendix Downhole Schematic and Wellhead Diagram Proposed Porter 50 Gas Company Schematic Field Name Operator County State Aliso Canyon Southern California Gas Company Los Angeles California Ground Eievation (ft) KByG/ound Distance (ft) Spud Date 1,947.00l 2460' Original Hole, 4/29/2010 1:53:07 PM MD (ftKB) Vertical schematic (actual) -190.8 24.6 Surface Casing Cement; 24.6?9000 11KB 46,] 8 Description:Surface; in; Top:24.6 Description:Surface; 82:17 1/2; Depth Btm:900.0 Length:875.40 lt 899.0 899.4 899.9 Production CaSIng Cement; DescriptionProduction; in; 4 049 Top:24.6 ftKB; Depth 7,198.2 7,198.7 7,199.1 7,249.0 7,298.9 7,299.4 7,299.9 7,309.4 7,318.9 Description:Gravel Pack Liner; in; I 7 Topj?gao 1/2, lt 8,638.1 8,638.6 8,639.1 8,639.6 I Description:TD Original Hole; Depth 8,640.1 8,855.5 WellView? Page 1 of 1 Job End Date: Doc #292223 THIS DRAWING IS NOT TO SCALE. THE DIMENSIONS REFLECTED ON THIS DRAWING ARE ESTIMATED DIMENSIONS AND ARE FOR REFERENCE ONLY. ?1?2413" G, WINGS, I 3-1l8? API 5,000 44.69" 3-1/ API 5000 Ii. 11" API 5,000 GATE VALVES, 5,000 27.50" 5,000 7.1" g, 13-5/8 API 5,000 20.25" VALVE, 2" API 5,000 13-3r'8" - 9-51'8" .. 2-7/3" .. a 2010 Weatherford International Inc. All rights reserved Customer: SOUTHERN CALIFORNIA GAS CO. Project TBD Quote: TBD Tender, ProIect 0r Well. ALISO CANYON - PORTER 503 Date. 04-27-2010 Drawn By JJ PEB-C-2 Doc #292223