1 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO -GAS FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. -GAS TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE ON 0-DAYS NOTICE. ) ) ) ) PROCEEDING NO. 1AL- G ) ) ) ) ) DIRECT TESTIMONY AND ATTACHMENTS OF CHERYL F. CAMPBELL ON BEHALF OF PUBLIC SERVICE COMPANY OF COLORADO March, 01
2 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO. -GAS FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. -GAS TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE ON 0-DAYS NOTICE ) ) ) ) PROCEEDING NO. 1AL- G ) ) ) ) ) SUMMARY OF DIRECT TESTIMONY OF CHERYL F. CAMPBELL Ms. Cheryl F. Campbell is Vice President, Gas of Xcel Energy Services Inc. ( Xcel Energy ). Ms. Campbell is responsible for the oversight of the overall gas business, including strategic planning and public and employee safety in each state in which Xcel Energy operates a gas system 1. Ms. Campbell s duties and responsibilities include, among other things, the design, operation, and maintenance of Public Service Company of Colorado s ( Public Service or Company ) natural gas pipeline system. The purpose of Ms. Campbell s testimony is five-fold: (1) provide an overview of Public Service s natural gas business today and describe our proposal to further improve our current operations in a proactive and predictive manner; () request that the Public Utilities Commission of Colorado ( Commission ) approve the acceleration of certain pipeline replacement projects 1 The states include Colorado, Michigan, Minnesota, North Dakota, South Dakota, Texas, and Wisconsin. Xcel Energy does not operate a gas system in New Mexico.
3 included for recovery in the Pipeline System Integrity Adjustment ( PSIA ) rider ; () support two new programs the Gas Storage Field Maintenance Program and the Enhanced Leak Management Program; () explain the capital and O&M cost drivers since our last rate case, Proceeding No. 1AL-1G ( 01 Rate Case ); and () provide support for certain of the adjustments necessary to the historical test year ( HTY ), the twelve months ending June 0, 01, and the Multi-Year Plan ( MYP ) Test Years, calendar years 01, 01 and 01. Ms. Campbell begins with an overview of Public Service s natural gas business and explains that our mission is to provide safe and reliable natural gas service to our Colorado customers. Federal rules require pipeline operators to know their assets, to identify the risks and threats to those assets, and to be proactive in mitigating those risks and threats. Ms. Campbell explains how Public Service has been and continues to transition to a more proactive and predictive manner in operating its gas business. Ms. Campbell next discusses the progress Public Service has made in executing our Integrity Management Plans since the 01 Rate Case. In this discussion, Ms. Campbell explains several changes to the PSIA for which Public Service seeks approval should the Commission grant our request to extend the PSIA for five years or until December 1, 00 as explained by Company witnesses Mr. Steven Wishart and Ms. Alice K. Jackson. First, with the completion of the Edwards-to-Meadow Mountain Transmission Project in 01 and the Cellulose Acetate Butyrate ( CAB ) Gas Service Replacement Program in 01, Public Service seeks approval to move these projects from the PSIA into
4 rate base as of January 1, 01. Second, Public Service is seeking approval to accelerate two PSIA programs: the Accelerated Main Replacement Program ( AMRP ) and the Programmatic Risk-Based Pipe Replacement Program. Great progress has been made with these programs; for example, under AMRP, all known cast iron main has been removed from our gas system (totaling miles since 00). Given that the types of pipe under these programs have reached the ends of their useful lives and they continue to deteriorate, the Company believes that it should accelerate the removal of these pipes for public safety reasons. Finally, Ms. Campbell testifies regarding the capital and operations and maintenance ( O&M ) cost drivers that led to the filing of this proceeding and provides support for the capital and O&M cost levels for the HTY and the MYP. Ms. Campbell also supports certain of the known and measurable adjustments made to the HTY and the MYP Test Years. As part of this discussion, Ms. Campbell describes two focus areas, which expanded since the last case namely, improving Gas Storage Field Maintenance and improving how PSCo identifies and repairs leaks on its system. These projects are reasonable and necessary as they support our proactive and continuous improvement of reliability and enhance the safety of our customers, employees, and the public. Ms. Campbell recommends that the Commission approve: (1) the capital additions associated with the Gas Utility s distribution and transmission business areas for the MYP Test Years as the related costs will be prudently incurred and reasonable and used and useful in providing customer service; () the Gas
5 Utility s distribution and transmission business areas O&M expenses for the MYP Test Years as they are prudent and reasonable; () the adjustments to revenues for the MYP Test Years supported in her testimony; () the proposed changes to the PSIA, namely accelerating the AMRP and the Programmatic Risk-Based Pipe Replacement Program; and () improving the maintenance practices for the gas storage fields and improving how leaks are identified and reparied as they support our proactive and continuous improvement of reliability and enhance the safety of our customers, employees, and the public.
6 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO. -GAS FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. -GAS TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE ON 0-DAYS NOTICE ) ) ) ) PROCEEDING NO. 1AL- G ) ) ) ) ) DIRECT TESTIMONY AND ATTACHMENTS OF CHERYL F. CAMPBELL SECTION INDEX PAGE I. INTRODUCTION, QUALIFICATIONS, PURPOSE OF TESTIMONY AND RECOMMENDATIONS... 1 II. PUBLIC SERVICE S GAS BUSINESS... A. OVERVIEW OF PUBLIC SERVICE S GAS BUSINESS... B. PUBLIC SERVICE S FOCUS ON OPERATING IN A PROACTIVE AND PREDICTIVE MANNER Safety Processes and Procedures Efficient Management of Resources Operation of Public Service s System in an Efficient and Effective Manner Maintaining a Well-Trained Workforce.... Future Direction of Public Service... III. THE COMPANY S INTEGRITY MANAGEMENT PROGRAMS... A. PROGRESS UNDER THE INTEGRITY MANAGEMENT PROGRAMS Distribution Integrity Management Plan (DIMP)...
7 . Transmission Integrity Management Plan (TIMP)... B. ASSESSMENT OF INTEGRITY PROGRAMS... IV. CHANGES IN GAS SYSTEMS AND DISTRIBUTION OPERATIONS COSTS AFFECTING BASE RATE REVENUE REQUIREMENTS... A. OPERATIONS AND MAINTENANCE EXPENSES Key Drivers Causing O&M Expense to Increase Between the 01TY and the HTY.... HTY O&M Expenses and Adjustments O&M Adjustments Related to the MYP Period... B. CAPITAL COSTS... C. OTHER ADJUSTMENTS Natural Gas Liquids Revenues.... Revenues Related to Cherokee... V. SUMMARY AND CONCLUSION...
8 Attachment CFC-1 Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- Attachment CFC- LIST OF ATTACHMENTS Service Territory Map OSHA Recordable Incidents Damage Prevention Locates AGA s Commitment to Safety Historical AMRP Results Leak Ratio Trend FERC Account Details HTY Vacancies Natural Gas Liquids Revenues NYMEX Futures Prices Natural Gas Liquids Historical Test Year (HTY) O&M Expenditures by Object and FERC Account Attachment CFC-1 Project Capital Additions: 01 to 01
9 GLOSSARY OF ACRONYMS AND DEFINED TERMS Acronym/Defined Term Meaning 0 Rate Case Proceeding No. AL-G 0 Pipeline Safety Act or 0 Act Pipeline Safety, Regulatory Certainty, and Job Creation Act of 0 01 Rate Case Proceeding No. 1AL-1G 01TY 01 Rate Case test year, 1 months ending September 0, Test Year The 1 months ending December 1, Test Year The 1 months ending December 1, Test Year The 1 months ending December 1, 01 AFUDC AGA AMRP ASV CAB CIG Commission or PUC Company CWIP DIMP DOT Allowance for Funds Used During Construction American Gas Association Accelerated Main Replacement Program Automatic Shut Off Cellulose Acetate Butyrate Colorado Interstate Gas Colorado Public Utilities Commission Public Service Company of Colorado or Public Service Construction Work In Progress Distribution Integrity Management Program Department of Transportation
10 Acronym/Defined Term Meaning ERT FERC FTE Gas Utility HCA HP Encoder Receiver Transmitter Federal Energy Regulatory Commission Full-Time Equivalent Public Service s natural gas operations High Consequence Area High Pressure HTY Historical Test Year, 1 months ending June 0, 01 ILI In line inspection IP MAOP Intermediate Pressure Maximum Allowable Operating Pressure MYP Multi-Year Plan period of January 1, 01 through December 1, 01, which includes the 01, 01, and 01 test years. O&M O&M First Set Credits OSHA PDP PHMSA PM PSIA Operations and Maintenance Costs associated with the accounting treatment of meter set expenses Occupational Safety and Health Administration Pipeline Data Project Pipeline and Hazardous Material Safety Administration Project Manager Pipeline System Integrity Adjustment
11 Acronym/Defined Term Meaning Public Service, or Company RCV ROW SCADA SME TIMP Xcel Energy XES Public Service Company of Colorado Remote Control Value Right-Of-Way Supervisory Control and Data Acquisition Subject Matter Expert Transmission Integrity Management Program Xcel Energy Inc. Xcel Energy Services Inc.
12 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO. -GAS FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. -GAS TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE ON 0-DAYS NOTICE. ) ) ) ) PROCEEDING NO. 1AL- G ) ) ) ) ) DIRECT TESTIMONY AND ATTACHMENTS OF CHERYL F. CAMPBELL I. INTRODUCTION, QUALIFICATIONS, PURPOSE OF TESTIMONY AND RECOMMENDATIONS 1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. A. My name is Cheryl F. Campbell. My business address is 100 Larimer Street, Suite 100, Denver, Colorado 00. Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? A. I am employed by Xcel Energy Services Inc. ( XES ), as Vice-Present, Gas. XES is a wholly-owned subsidiary of Xcel Energy Inc. ( Xcel Energy ), and provides an array of support services to Public Service Company of Colorado ( Public Service or the Company ) and the other operating subsidiaries of Xcel Energy on a coordinated basis. My responsibilities include oversight of the overall gas business, including strategic planning and public and employee safety in each state in which
13 Xcel Energy operates a gas system. In this position, I am responsible for, among other things, the design, operation, and maintenance of Public Service s Colorado natural gas pipeline system. Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? A. I am testifying on behalf of Public Service. Q. PLEASE BRIEFLY OUTLINE YOUR RESPONSIBILITIES FOR PUBLIC SERVICE. A. I oversee the design, operation, and maintenance of Public Service s gas transmission and distribution pipelines and underground storage facilities. I also direct gas control, gas emergency response and repairs, and gas distribution and gas transmission engineering activities in Colorado, as well as in the other states in which Xcel Energy provides regulated natural gas service. I am also responsible for gas compliance, gas standards, and integrity management programs across Xcel Energy s operating areas and for the administration of the gas transportation business on the Public 1 Service gas system. A statement of my education and relevant experience is set forth in Attachment A to my Direct Testimony. Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? A. The purpose of my testimony, in brief, is to present an overview of Public Service s natural gas business, describe developments, and detail the major contributors to changes in the Company s costs since our last gas rate case in Proceeding No. 1AL-1G ( 01 Rate Case ). In that The states include Colorado, Michigan, Minnesota, North Dakota, South Dakota, Texas, and Wisconsin. Xcel Energy does not operate a gas system in New Mexico.
14 case, the Public Utilities Commission of Colorado ( Commission ) continued, until December 1, 01, an infrastructure cost recovery mechanism, the Pipeline System Integrity Adjustment ( PSIA ), through which Public Service is permitted to recover the revenue requirements associated with its pipeline integrity management programs. In this proceeding, Public Service is seeking an extension of the PSIA for five years, or until December 1, 00. See the Direct Testimony of Company witnesses Mr. Steve Wishart and Alice K. Jackson for further discussion of the Company s request for an extension of the PSIA. Although the costs of the projects that are recovered through the PSIA are not included in the base rate revenue requirements for the historical test year ( HTY ) ending June 0, 01 or the Multi-Year Plan ( MYP ) period, 01 through 01, proposed in this case, these PSIA costs represent a portion of the gas system costs that benefit our customers and impact their overall rates. The PSIA also completes the picture of the substantial work that Public Service has completed to date and the long-term plan for the Company s future regarding our transition to operate our gas system in a proactive and predictive manner. In order to explain Public Service s transition to operating in a proactive and predictive manner, I discuss the success of the PSIA and Public Service s direction with respect to the integrity management programs and other non-psia initiatives, which are necessary for a Note that as I discuss later in my testimony, Public Service is proposing in this proceeding to move two completed projects from the PSIA into rate base as of January 1, 01.
15 comprehensive understanding of the long-term plan for our gas system. Finally, I discuss the major drivers affecting the gas distribution and transmission costs reflected in the HTY and MYP base rate revenue requirements in this rate case, including, particularly, changes in operations and maintenance ( O&M ) expenses and additions to plant inservice. Q. IN DELIBERATING ON THE 01 RATE CASE, THE COMMISSION OPINED THAT IT NEEDED TO SEE A COMPREHENSIVE GAS PLAN FROM THE COMPANY. DID PUBLIC SERVICE DEVELOP SUCH A PLAN FOR THIS PROCEEDING? A. Yes. As discussed in detail by Company witness Ms. Jackson, over the last year, the Company has undergone an examination of our gas business. In this proceeding, Public Service is presenting a base plan for the gas business as enhanced by the PSIA s pipeline integrity work. The PSIA and non-psia projects that I and Company witness Mr. Luke A. Litteken discuss reflect our plan for the gas business. Q. WHAT RECOMMENDATIONS ARE YOU MAKING IN YOUR DIRECT TESTIMONY? A. In brief, I recommend that the Commission approve: the Gas Utility s distribution and transmission business areas capital additions for the MYP Test Years as the related costs will be prudently incurred and reasonable and used an useful in providing customer service;
16 the Gas Utility s distribution and transmission business areas O&M expenses for the MYP Test Years as they are prudent and reasonable; the proposed changes to the PSIA, namely accelerating the AMRP and Programmatic Risk-Based Pipe Replacement Programs; and the expansion of two activities improving Gas Storage Field Maintenance and improving Leak Management practices as they support our current operations and goals to seek proactive and continuous improvement to reliability and enhance the safety of our customers, employees, and the public. Q. HOW IS YOUR DIRECT TESTIMONY ORGANIZED? A. My Direct Testimony is separated into two parts. In the first part of my testimony, I will: provide a general description of Public Service s natural gas business; discuss Public Service s proposal to further improve our current operations in a proactive and predictive manner, including the incremental, non-psia initiatives proposed for the gas business, which are further discussed by Public Service witness Mr. Litteken; review the various pipeline safety and integrity programs and related projects undertaken by Public Service in recent years; and provide detail and support of Public Service s proposed plan to accelerate certain pipeline integrity projects that will further
17 enhance safety and reliability. In the second part of my testimony, I will: provide support for the major cost drivers of the increase requested in this gas rate case related to Public Service s natural gas operations (the Gas Utility ), including a description of the increases in non-psia O&M expenses for the Gas Utility s distribution and transmission business areas and the major plant additions during the HTY and the MYP; provide support for the major gas plant additions to be placed into service during the MYP period; explain the drivers of increases in the Gas Utility s O&M expenses for distribution and transmission from the 01 Rate Case to the HTY in this proceeding; sponsor and explain the development of the O&M expenses for the Gas Utility s distribution and transmission business areas for the MYP period; sponsor and explain the development of the Gas Utility s distribution and transmission business areas capital budgets for the MYP period; detail how Public Service controls its O&M and capital costs; and 1 detail how Public Service continually monitors the status of its distribution and transmission projects.
18 II. PUBLIC SERVICE S GAS BUSINESS 1 A. OVERVIEW OF PUBLIC SERVICE S GAS BUSINESS Q. PLEASE PROVIDE AN OVERVIEW OF PUBLIC SERVICE S NATURAL GAS BUSINESS. A. As a regulated natural gas public utility, Public Service is in the business of purchasing, transporting, distributing, and reselling natural gas to customers in Colorado. Except for a small segment of our gas transportation business, our rates and services are regulated exclusively by this Commission. Public Service s natural gas operations are a large and important part of the overall gas, electric, and steam utility services that the Company provides to Colorado customers. As depicted in the map in Attachment CFC-1, the Company s natural gas pipeline network extends north from the San Juan Basin in southern Colorado through the San Luis Valley over Rollins Pass to the Front Range, and then terminates near the Wyoming border. The Front Range System extends south from near the Wyoming state line through the Denver metropolitan area. The system extends just across the Douglas County line, through and including Highlands Ranch, and also includes the City of Pueblo and its environs. The system also extends from Grand Junction to Steamboat Springs on the Western Slope. Public Service s natural gas system is comprised of over,0 miles of transmission pipelines, over 1,000 miles of distribution mains, and approximately 1. million individual service lines. It also includes
19 about,000 horsepower of compression located at 1 distinct sites around the state, two natural gas storage fields, and two gas processing plants. It is a diverse system, spanning rural, suburban, and urban environments. Public Service provides gas sales and transportation service to many Front Range communities (e.g., the greater Denver metro area, Fort Collins, and Pueblo), the Western Slope (e.g., Grand Junction, Rifle, Meeker, etc.), and mountain and resort communities (e.g., Alamosa, Steamboat Springs, Copper Mountain, Vail, Durango, Pagosa Springs, Crested Butte, and Leadville). We operate facilities in 0 counties within the state. Public Service s system has direct access to major gas supply areas in Colorado, including residue plants in the Denver-Julesberg Basin, the San Juan Basin, and certain production fields on the Western Slope. Through gas transportation capacity held on upstream interstate pipelines, Public Service also is able to access major gas supply areas in Wyoming, Colorado, Utah, Texas, Kansas, and Oklahoma. The Company provides natural gas service to residential, commercial, and industrial customers, as well as to gas-fired electric generation facilities. Public Service is the upstream gas transportation service provider for certain local gas distribution systems owned and operated by Atmos Energy Corporation, the Town of Center, Colorado Natural Gas, Inc., and SourceGas Distribution, LLC. The Company also
20 transports gas in interstate commerce by delivering gas supplies to interconnected pipeline systems that subsequently transport the gas to out-of-state markets. This interstate service is regulated by the Federal Energy Regulatory Commission ( FERC ) and is provided pursuant to a limited-jurisdiction certificate of public convenience and necessity issued by the FERC in 1. See Public Service Co. of Colorado, 1 FERC,01 (1). Q. PLEASE PROVIDE A BREAKDOWN OF THE NUMBER OF GAS CUSTOMERS SERVED BY PUBLIC SERVICE AND THEIR ANNUAL USAGE. A. At the end of 01, the Company had approximately 1. million natural gas sales customers, residential and commercial, and,1 transportation customers. The number of customers and their usage by class and type of service are as follows: 01 Customer Profile 1 Number of Customers Volumes (Dekatherms) Residential Sales 1,,0,1, Commercial Sales 0,,,0 Transportation,1,1,
21 B. PUBLIC SERVICE S FOCUS ON OPERATING IN A PROACTIVE AND PREDICTIVE MANNER Q. WHAT IS THE BASIC MISSION OF PUBLIC SERVICE S GAS BUSINESS? A. Our mission is to provide safe and reliable service to our Colorado customers. This goal is paramount. We understand that natural gas service is absolutely critical to the State of Colorado and its citizens. When customers need natural gas for heating or any other end use, we must be ready to provide that service on demand. Moreover, we must design and operate our system to ensure the safety of our customers, our employees and contractors, and the public. Q. DOES PUBLIC SERVICE PROVIDE SAFE AND RELIABLE SERVICE TO ITS CUSTOMERS? A. Yes. However, we cannot be complacent. In fact, like the rest of the gas industry in the United States, Public Service is focused on operating in a proactive and predictive manner. Q. WHAT DO YOU MEAN BY PUBLIC SERVICE IS FOCUSED ON OPERATING IN A PROACTIVE AND PREDICITVE MANNER? A. Federal rules make clear that each individual pipeline operator is responsible for identifying and evaluating the risks of its system and for addressing those risks in a proactive manner. Thus, for the pipeline operator, this directive can be broken down into three main points: know your assets; identify the risks and threats to those assets; and be proactive in mitigating those risks and threats. These points must be
22 addressed, not sequentially, but in unison. This can be viewed as a continuous cycle of plan, do, check, act. For example, if risks are identified but are not addressed until much later, the purpose of the directive is defeated. It is in accomplishing and sustaining these three points that Public Service is focused on operating in a proactive and predictive manner. In order to operate in this manner, Public Service recognizes the importance of essential elements to operate and maintain its gas system in a holistic manner. Those can be divided into four categories: (1) the implementation of enhanced safety processes and procedures; () the efficient management of resources; () the operation of our system in an efficient and effective manner; and () the maintenance of a well-trained workforce. Not only keeping current, but demonstrating continuous improvement in these four categories with respect to rules, regulations, and processes and procedures will allow Public Service to operate in a proactive and predictive manner. In doing so, Public Service will reduce risk to our employees, our customers, and the public while increasing service levels on the system. While the gas industry as a whole has consistently improved safety over the last 0 years, a number of recent events have demonstrated that we cannot be complacent. And while Public Service has made great strides with the projects completed through the PSIA, work still needs to be done.
23 Q EVEN WITH THE COMPANY FOCUSED ON OPERATING IN A PROACTIVE AND PREDICTIVE MANNER, WILL THERE BE TIMES DURING WHICH IT WILL NEED TO REACT TO CERTAIN EVENTS? A. Yes. An example is the historic floods that occurred from September through September 1, 01. During that weather event, Colorado s Front Range experienced record-breaking rainfall that led to historic flooding in the area. Boulder established a new -hour rainfall record of.0 inches, far exceeding the previous record of.0 inches set on July 1,. The flash flooding resulted in flooded and washed out roadways and bridges, stranded vehicles, and forced many workplaces to be closed from September 1 through September 1. In all, the floods washed away hundreds of miles of roads and left many small mountain communities completely cut off causing damage across nearly,000 square miles. Flooding destroyed more than 0 homes and damaged over 1,000 homes and commercial buildings. This historic flood resulted in significant damage to the Gas Utility facilities. Some of Public Service s gas infrastructure followed the very same roads and bridges that were damaged or destroyed by the flood. There were major areas impacted on Public Service s gas system, including (1) exposed or damaged pipelines as roads were washed away; See The Record Front Range and Eastern Colorado Floods of September -1, 01 prepared U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Weather Service at p.. Id. at 1. Id. at 1. 1
24 () infiltration of water into the distribution system as homes were moved from foundations; and () our gas transmission pipelines undermined in new river beds creating stress on the pipelines and necessitating the shutdown of various lines to maintain safety. Approximately,0 customers were without natural gas service due to flood damage to the gas system. In addition, Public Service lost its ability to meet full winter load requirements on its gas system, with the potential for many more outages as the temperatures dropped in the fall and winter. Q. PLEASE DESCRIBE PUBLIC SERVICE S RESTORATION EFFORTS IN RESPONSE TO THE SEPTEMBER 01 FLOODS. A. Occurring at a critical time period before the winter months and despite the inability to reach certain areas because of road conditions, Public Service not only safely, effectively and efficiently restored service to customers who suffered outages as a result of this historic flood but also timely restored full winter capability. Public safety around the gas system was Public Service s first priority. Despite the amount of compromised and exposed pipe, as a result of the tremendous effort and focus of our employees, there was no ignition of gas, no fire and no serious incidents. Over 00 Xcel Energy employees worked on restoring customers without service due to the flood and to restore our winter capability. All parts of the Company were involved including field crews, engineers, designers, supply chain, customer care, community relations and fleet. In the years leading up to the floods, Public Service conducted (and continues to 1
25 conduct) complex emergency drills that enabled the effective management of the immediate emergency as well as the restoration efforts. As a result of these efforts, over ten miles of pipe were replaced, including plastic and steel, distribution and transmission pipelines. Over 00 meters were replaced and over 1,00 meters were inspected. Service to approximately,0 customers was restored, percent of which were restored by the end of September 01. The system was returned to normal operating status on or about October 1, 01 and full winter capability was restored by October 1, 01. Public Service spent approximately $1 million to repair damage to the Company s natural gas system. Q. WERE EVERYDAY OPERATIONS IMPACTED AS A RESULT OF THIS COMPREHENSIVE RESTORATION EFFORT? A. Yes. Public Service s response to this historic flood was an all hands on deck process. In other words, all resources were diverted to safely, effectively, and efficiently restoring not only service to customers who experienced outages as a result of the flood, but also restoring the system to full winter capability. Planned major construction efforts were delayed so that heavy equipment could be used in the restoration effort. Materials on hand as a result of other planned activities were diverted to use as part of the restoration effort. A number of projects were impacted, including many PSIA projects. These included the Accelerated Main Replacement The approximate $1 million reflects both capital and O&M costs related to the restoration effort. In Section IV of my testimony, I propose an adjustment to the HTY for O&M expenses to remove the expenses that are above and beyond normal expenses of doing business during the HTY. 1
26 Program ( AMRP ), CAB Gas Service Replacement Program, the Distribution Integrity Management Program ( DIMP ), the Transmission Integrity Management Program ( TIMP ), and the West Main Transmission Line Replacement Project. 1. Safety Processes and Procedures Q. PLEASE EXPLAIN THE FIRST CATEGORY OF WORK YOU MENTIONED THE IMPLEMENTATION OF ENHANCED SAFETY PROCESSES AND PROCEDURES. A. This category addresses the processes and procedures related to the safety of our employees, contractors, and the public. With respect to the safety of our employees, Public Service s gas operation has shown a reduction in injuries in striving for zero Occupational Safety and Health Administration ( OSHA ) recordable incidents. See Attachment CFC-. While there was an increase in injuries in 01 (to 0 levels), in 01, we achieved the lowest level of recordable injuries in the last five years. We continue to implement behavior-based safety efforts with our employees, which includes improving work processes, assessing work sites for unsafe situations, and utilizing tools and equipment that promote a positive safety climate. A key to the success of our safety programs is communicating and sharing information about situations that could have resulted in an accident. Ideally, our objective is to reduce the number of OSHA recordable incidents to zero by identifying risky behavior and providing alternative behaviors for the safe completion of work as well as recognizing individuals and departments for safe behaviors. Our successful programs and effective 1
27 employee communications have reduced Public Service s OSHA incident rate as we continue to change the culture on our journey to zero recordable incidents. With respect to contractors, safety is reviewed as part of the contracting process, with contractors with OSHA rates outside of industry norms excluded from bidding. Contractors with serious incidents (such as fatalities) are reviewed and allowed to bid on projects only if the mitigation measures that have been put into place are deemed proactive, sufficient and appropriate for the incident. Q. HOW HAS PUBLIC SERVICE ENHANCED THE PROCESSES AND PROCEDURES FOR PUBLIC SAFETY? A. With respect to public safety, Public Service has undertaken an extensive review of our emergency response procedures, with the goal of reducing our emergency response time. A utility s emergency response time is the average response time measured from the time an emergency call was received to when the first responder was on-site at the emergency location. In 01, by addressing data and human performance issues and efficiently deploying existing resources, Public Service was able to reduce our average response time from 1 minutes to 1 minutes. Our goal is to achieve an average response time of 0 minutes or less, which would place Public Service in the 1 st Quartile of our peer group. Achieving 1 st Quartile results will be a journey that can only be accomplished over a period of time by adding resources and becoming more efficient in work practices. As such the Company is proposing the Enhanced Emergency Based on American Gas Association ( AGA ) benchmarking data. 1
28 Response Program, which is discussed further in the Direct Testimony of Mr. Litteken, as the first step of this journey. Q. ARE THERE OTHER ISSUES REGARDING THE PROCESSES AND PROCEDURES RELATED TO PUBLIC SAFETY? A. Yes. Damage to Public Service s underground facilities continues to be a significant risk to our gas distribution system. The number one cause of leaks on Public Service s system has been third-party damage. Further, public damage has caused over a quarter of the significant incidents on gas distribution systems in the last five years in the United States. As a result, Public Service continues to institute a variety of outreach efforts to third parties regarding the importance of utilizing Colorado as well as the Common Ground Alliance best excavation practices. It is critical that our mains and services are located accurately before excavating to ensure safety for the workers as well as the public around the work site. We are constantly re-evaluating our damage prevention programs to increase their effectiveness. We also participate in several industry organizations where we obtain and share information about best practices for reducing public damage. As a result of these efforts, Public Service continues to maintain our industry leading, top quartile position. Attachment CFC- contains a graph that shows the number of damages per 1,000 locates from 00 through 01. As indicated by this graph, despite experiencing a slight uptick AGA 01 benchmarking for Third Party Damage per 1,000 excavation tickets. 1
29 recently, we have seen a percent reduction in damages per 1,000 locates on our system since 00. In order to maintain this high level of service, Public Service is proposing the Damage Prevention Program, which provides for quality control and supervision over locates. For further discussion, see the Direct Testimony of Mr. Litteken.. Efficient Management of Resources Q. PLEASE EXPLAIN THE SECOND CATEGORY OF WORK YOU MENTIONED THE EFFICIENT MANAGEMENT OF RESOURCES. A. Improving operating productivity has always been a focus of the Company. We routinely evaluate processes and technologies to identify more efficient ways of doing business. An example of the efficient management of resources lies in the successful implementation of field mobility technology for High Pressure Operations, which has allowed us to perform Senior Associate level work with one less full-time equivalent ( FTE ) position. In the past, personnel in the office would print off inspection sheets for valve and regulator inspections, input information from these same field inspections, and maintain and close the associated work orders. Implementation of field mobility technologies, including Mobile Data Terminals and a mobile dispatch and data collection software called Field Smart, has improved the efficiency of this process. Now, the Operators in the field are assigned the inspections and capture the pertinent information (i.e., what they did onsite, what they found, and any errors in the design information) electronically. This information, including completion of the 1
30 work, then goes directly into the Company s work and asset management system called PassPort, without an office employee ever having to touch it. This has not changed the Operators work load; however, it has eliminated the need for an office employee to enter information manually from the field into the PassPort system. The reduction of one FTE resulting from this process improvement is incorporated in the labor portion of the O&M adjustment as discussed later in my testimony.. Operation of Public Service s System in an Efficient and Effective Manner Q. PLEASE EXPLAIN THE THIRD CATEGORY OF WORK YOU MENTIONED THE OPERATION OF THE COMPANY S SYSTEM IN AN EFFICIENT AND EFFECTIVE MANNER. A. Public Service is standardizing processes for routine work and proactive maintenance to improve safety and reliability. This is a key change as we focus on operating our system in a proactive and predictive manner. With this focus, Public Service has placed importance on standardizing practices and procedures in the Company s Pipeline Compliance and Standards manual. The Company s Pipeline Compliance and Standards manual sets forth Public Service s inspection and maintenance protocols for our assets. Over the last three years, the Company has undertaken a comprehensive review of the manual and made appropriate modifications. These modifications clarify expectations for various inspection and maintenance work using gas industry standards and norms as the 1
31 baseline. Further, where additional risk factors have been identified in our service territory, Public Service has modified our inspection and maintenance protocols to enhance the safety and reliability of our system. These modifications have led Public Service to be more proactive and have further enhanced the safety and reliability of our system. An example of these modifications involves the avoidance of cross bores, which are the intersection of an existing underground utility or underground structure by a second utility resulting in direct contact between the facilities of the two utilities. Pursuant to the modified Pipeline Compliance and Standards manual, employees and contractors are now required to ensure proactively that no cross bore exists when a service or main is directionally drilled and could cross another utility facility, such as a sewer. This can include using a camera in the sewer line after the gas line is installed to ensure no impairment. This type of proactive risk management approach enhances public safety. If left undetected, a cross bore could result in an injury to a plumber or someone else in the course of clearing a clogged sewer. Incidents from these types of conflicts have been widely published as a risk in the industry. Q. HAS PUBLIC SERVICE INSTITUTED OTHER PROJECTS AND PROGRAMS? A. Yes. In the 0 rate case in Proceeding No. AL-G ( 0 Rate Case ), Public Service requested approval of the PSIA, which would allow Usually for gas utilities, a cross bore occurs when a gas facility intersects with an existing sewer main or sewer lateral. 0
32 Public Service to continue undertaking our extensive initiative to enhance the safety and reliability of our gas pipeline system. By adopting the settlement agreement in that rate case, with slight modifications, the Commission approved the PSIA. The result has been a success. Public Service has instituted a number of projects and programs through the PSIA since its approval to develop effective integrity management programs and to enhance our gas system safety and reliability. These projects and programs include, in part: AMRP, CAB Gas Service Replacement Program, Poor Performing Material Replacement Program, programs that assess the integrity of our transmission and distribution lines, and data integrity programs. Through the PSIA, Public Service has already completed or will complete during the MYP three major projects: (1) the Edwards-to-Meadow Mountain Transmission Project; () the West Main Transmission Line Replacement Project; and () the CAB Gas Service Replacement Program. Additionally, in 01, Public Service removed the last of the known cast iron pipe from our system as part of AMRP. I will discuss PSIA projects further in Section III of my Direct Testimony. With the approval of the PSIA, which allowed for the timely recovery of the costs of the integrity management programs and related projects, great strides have been made in our steadfast focus on knowing our assets, identifying the risks and threats to our assets, and being proactive in mitigating those risks and threats. The result is that Public Service has In total since 00, Public Service removed the remaining miles of cast iron main in our gas system. 1
33 enhanced the safety and reliability of our Colorado pipeline system. However, as I said earlier, we cannot become complacent; work still needs to be done. In this proceeding, in addition to requesting an extension of the PSIA, Public Service is also requesting approval of non-psia projects and programs that allow us to operate effectively and efficiently and will further support our continued effort to ensure our mission of providing safe and reliable service to our customers. Q. PLEASE DESCRIBE THE NON-PSIA PROJECTS AND PROGRAMS THAT PUBLIC SERVICE IS PROPOSING IN THIS PROCEEDING. A. In addition to the Enhanced Emergency Response Program and the Damage Prevention Program that I discussed above, Public Service is proposing five other projects and programs: the Inside Meter Replacement Project, the Regulator Station Improvement Project, the Supervisory Control and Data Acquisition ( SCADA ) / Gas Control Monitoring Improvement Program, improving gas storage field maintenance, and improving the management and repair of leaks. I will address the last two efforts, gas storage field maintenance and improving the management of leaks, later in my testimony. The Inside Meter Replacement Project proposes to move most of the remaining legacy meters still located inside of customer premises to outside locations and to replace the existing facilities with new meters, connections, and regulators. The benefits of this project to our customers and to public safety are two-fold. One, the relocation of meters outside of a customer s
34 premise allows the Company to more efficiently perform routine required inspection and maintenance of these meters without having to coordinate access or inconvenience the customer. Second, moving the meters to outside locations reduces the risk of gas accumulating in a confined space where there are more sources of ignition. The Regulator Station Improvement Project proposes to place regulator stations on a mandated five-year rebuild inspection cycle, add redundancy at key points, and replace obsolete equipment. This project will provide significant reliability benefits to our customers in terms of avoided gas outages. The SCADA / Gas Control Monitoring Improvement Program will increase the visibility and provide enhanced control of our gas systems in an automated fashion. Through a robust SCADA system, Gas Controllers are effectively the eyes and ears on our system and can see potential failures and dispatch crews to effectuate any repairs prior to a catastrophic failure. This program will add more SCADA pressure monitoring points into our Gas Control room from regulator stations and add redundancies in certain critical locations. In his Direct Testimony, Mr. Litteken will address these non-psia projects and programs in greater detail.
35 Q. WHY ARE NON-PSIA (TRADITIONAL GAS WORK) PROJECTS IMPORTANT? A. Public Service is committed to the safety and reliability of our gas system and to implementing projects to enhance safety and reliability that are separate and apart from the projects included in and recovered through the PSIA. This includes addressing legacy issues in which construction practices, standards, and codes were less stringent than today, as well as strengthening our own internal standards and maintenance practices. The Company s approach to managing risk is to not only ensure compliance with federal codes and standards, which are intended to be the minimum requirements of a gas operator, but to also ensure that we institute preventative or additional measures to reduce risks to public safety, reliability, and our gas system. It is that approach that is the driver behind these types of incremental projects. Furthermore, as I noted in the 0 Rate Case, the PSIA projects generally represent long-term projects that are variable in nature whereas non-psia projects are shorter-term projects that tend to be more predictable. 1 1 Many of these initiatives are not short-term projects. Because we don t know what we will find when we conduct an assessment, we are finding that our capital and O&M needs are variable. This variability is not based on the traditional pipeline safety code work, which required us to complete activities on a schedule (e.g., leak surveys), but is driven more by the overall integrity of a segment or type of pipe. 0 Rate Case, Campbell Direct, :1-.
36 Maintaining a Well-Trained Workforce Q. PLEASE EXPLAIN THE FOURTH AND FINAL CATEGORY OF WORK YOU MENTIONED MAINTAINING A WELL-TRAINED WORKFORCE. A. Like many other utilities across the United States, Public Service is in the middle of a major transition of our workforce, with approximately 0 percent of our employees, including craft, technical, and leadership positions, eligible to retire in the next eight to ten years. In order to maintain a well-trained workforce that can safely implement our processes and procedures and make appropriate decisions in the field, Public Service has initiated several programs. First, Public Service has added its operator qualification program as a requirement for new distribution and transmission construction crews and improved the overall program which will strengthen and maintain critical skill sets over time. Second, taught by experienced gas employees, Public Service has developed and implemented a Supervisor Boot Camp for managers and supervisors. This three-year program is a combination of classroom, handson learning, and field experience. The purpose of the program is to ensure our front line leaders have a solid understanding of how Public Service designs, operates, and maintains our gas system. Third, Public Service has constructed a new training facility that was completed in 01. The new facility will allow enhanced hands-on training in a controlled environment. Specifically, the new training center will include the following: classroom and lab facilities for apprentice and journeyman
37 training, an appliance lab, a regulator station lab and simulator, a welding shop, an outdoor burn pit for gas leak simulations, and a 1 station computer lab. Fourth, Public Service has developed and conducted a number of mock emergency drills designed to simulate real events on the gas system that have an impact on public safety. These drills can be simple or catastrophic in nature. Key employees, emergency responders and, in some cases community emergency first responders as well as state pipeline safety representatives, participate in these drills in order to further their knowledge, coordination, and readiness in the event of a real situation. Finally, Public Service has initiated a leadership development program within the Operations group. The goal of this gas leadership development program is to provide leaders with the skills and tools necessary to increase effective leadership skills which in turn improves employee engagement, which leads to better operational performance. Public Service will continue to investigate and to implement programs as necessary to continue to bridge this workforce gap and maintain a welltrained workforce.. Future Direction of Public Service Q. CAN YOU OFFER ANY GENERAL COMMENTS ON THE DIRECTION PUBLIC SERVICE NEEDS TO TAKE OVER THE NEXT SEVERAL YEARS? A. Yes. I believe we have historically delivered safe, reliable, and low-cost services to customers. In order to continue our mission and to comply with
38 State and Federal pipeline integrity rules, Public Service needs to continue to focus on operating in a manner that is more proactive and predictive and essentially delivers a higher level of service. This new operating culture will move Public Service to a Find It, Fix It philosophy. To operate in this proactive and predictive manner, Public Service will continue to standardize processes, monitor field and office practices, and benchmark against other utilities. In fact, Public Service will be participating in AGA s Peer Review Program. This voluntary peer-to-peer safety and operational practices review program allows natural gas utilities throughout the United States to observe their peers, share leading practices, and identify opportunities to better serve customers and communities. Employees have already begun to participate in reviews of other utilities, with a formal review of Xcel Energy scheduled for early 01. However, once the four categories I discussed above have been established, Public Service s work does not stop. Complacency is the enemy of a proactive and predictive gas utility. The data collected needs to be evaluated and processes and procedures need to be continually reviewed and updated to maintain a safe and reliable system. Q. IS PUBLIC SERVICE S ONLY GOAL TO PROVIDE SAFE AND RELIABLE SERVICE? A. No. Even though we are focused on operating in a proactive and predictive manner, Public Service also must be fiscally responsible. Larger projects, such as the recently installed Cherokee pipeline, require significant planning
39 in order to be completed in an efficient and cost effective manner. As a result, in 01, Public Service created a Project Management department. The Project Management Department assigns a project manager ( PM ) to large and/or complex capital gas projects and programs. The PMs focus on managing the project scope, schedule, and cost. Any risks and issues associated with a project get prompt attention and decision making. There have been a number of benefits following the establishment of this department, such as (1) declining variability of final project costs; () increasing availability of resources to execute major programs of work; and () increasing collaboration with local communities to limit inconvenience and repetitive work in a particular area. We have a duty to our investors to provide a reasonable value for their investment and to our customers to ensure that their service is provided at a reasonable cost. I will explain in detail later in my testimony how we develop capital and O&M budgets to accommodate the work necessary to fulfill our mission at a reasonable cost.
40 III. THE COMPANY S INTEGRITY MANAGEMENT PROGRAMS Q. WHAT SPECIFIC COMPANY PROPOSALS RELATED TO THE PSIA ARE YOU SPONSORING IN THIS RATE CASE? A. In addition to providing support for costs and plant additions contributing to Public Service s need for the proposed rate increases in the HTY and for the MYP, there are specific proposals that I am sponsoring in my Direct Testimony that center around the PSIA. Specifically, Public Service is requesting the Commission s approval for the following proposals: (1) removal from the PSIA of recovery of the costs related to the Edwardsto-Meadow Mountain Transmission Project and inclusion of those costs for recovery through base rates in the 01 Test Year and beyond; () removal from the PSIA of the CAB Gas Service Replacement Program and inclusion of those costs for recovery through base rates in the 01 Test Year and beyond; and () the acceleration of certain specific DIMP initiatives. I will address the third of these three requests, Mr. Wishart and Ms. Jackson will address the first two. Q. ARE THE COMPANY S INTEGRITY MANAGEMENT PROJECTS REQUIRED BY STATUTE OR RULE? A. TIMP 1 and DIMP 1 are federally-mandated programs. These rules make clear that each individual pipeline operator is responsible for identifying and evaluating the risks on their systems and addressing those risks in a 1 CFR Part 1, Subpart O Regulations; Gas Transmission Pipeline Integrity Management 1 CFR Part 1, Subpart P Regulations; Gas Distribution Pipeline Integrity Management
41 1 proactive manner. While the requirements under the DIMP are designed to allow operators some flexibility in dealing with the risks that are unique to their systems, there are stricter rules governing specific dates in which transmission pipelines must be assessed and anomalies remediated. Q. WHO REGULATES THE SAFETY OF THE COMPANY S NATURAL GAS PIPELINES? A. While Congress delegates certain responsibility and funding to states, overall responsibility for pipeline safety rests primarily with the Pipeline and Hazardous Materials Safety Administration ( PHMSA ), which is the administrative arm of the United States Department of Transportation ( DOT ). The Commission conducts its pipeline safety program with regard to intrastate pipelines in Colorado in accordance with PHMSA s state 1 pipeline safety certification regulations. PHMSA also oversees any supplemental state-specific safety requirements. Q. DO PIPELINE SAFETY REGULATIONS SPECIFY THE FULL EXTENT OF ACTIONS A PRUDENT OPERATOR IS EXPECTED TO UTILIZE WHEN OPERATING THEIR SYSTEM? A. No. The pipeline safety regulations, or code (including the federal code and complementary codes adopted by the states), were never meant to be allinclusive. In other words, the federal code prescribes the minimum that should be done to construct, operate, and maintain a natural gas system. Inherent in the code, and in the integrity rules, is the requirement that pipeline operators do what is reasonably necessary for the public good. 0
42 Q. IS IT ONLY AN OPINION THAT STRICTLY ADHERING TO THE CODE OF FEDERAL REGULATIONS REPRESENTS A MINIMUM LEVEL OF COMPLIANCE? A. No, the code specifically outlines this fact. Within the section defining the overall scope of the regulations within Part 1.1 it states the following: What is the scope of this part? (a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the limits of the outer continental shelf as that term is defined in the Outer Continental Shelf Lands Act ( U.S.C. ). Q. HOW HAVE INDUSTRY GROUPS RESPONDED WITH RESPECT TO GAS OPERATORS GOING BEYOND MINIMUM CODE? A. The AGA originally released its Commitment to Enhancing Safety in October 0 and subsequently updated it in May 01. The AGA s Commitment to Safety describes how AGA and member companies are going beyond minimum compliance with current regulations to ensure the safety of the nation s. million miles of gas pipelines. A copy of AGA s Commitment to Safety is contained in Attachment CFC-. The report was prepared at request of federal and state officials having oversight of pipeline safety. Public Service is an active member of the AGA and fully supports the Commitment to Safety. The Company is implementing the actions that the report lays out as part of its ongoing mission to provide safe and reliable service to our Colorado customers. 1
43 Q. HAVE THERE BEEN ADDITIONAL REGULATORY CHANGES THAT HAVE IMPACTED THE GAS BUSINESS SINCE THE LAST GAS RATE CASE IN 01? A. As I explained in my Direct Testimony in the 01 Rate Case, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 0 ( 0 Pipeline Safety Act or 0 Act ) was signed into law on January, 01. Numerous provisions of the 0 Act call for regulations, studies, and reports, mostly by the DOT; the exact changes to the rules under which the pipeline industry will have to operate have yet to be determined. Q. WHAT CHALLENGES DO YOU SEE AHEAD FOR THE INTEGRITY MANAGEMENT PROGRAMS? A. There are a number of challenges facing Public Service s integrity management programs. The first is that the DIMP and TIMP plans must ensure that all specific federal requirements are met. Second, since the 0 Pipeline Safety Act was passed, a number of other significant events have occurred within the industry and these incidents act as catalysts driving the continuing evolution of the regulatory landscape. This necessitates that Public Service anticipate the potential regulatory changes and be judicious in preparing for changes that may occur so that the Company is able to execute on changes once finalized at the federal level. A second challenge is the timing and prioritization of resources. Resources must be allocated where they will provide the best value to customers in terms of safety and cost. This resource allocation, in turn,
44 requires considerable analysis and judgment. The result is that some projects can be completed within a short period, but others must be completed over years as it is not cost-effective or practical to complete all projects in a short period. For these long-term projects, Public Service develops schedules or milestones to ensure that the ultimate goal will be achieved. Furthermore, not all projects lend themselves to meaningful completion dates. For example, TIMP pipeline assessments and the mitigation of identified risks represent an ongoing obligation. While PHMSA established a deadline of December 01 for the initial baseline assessments of transmission pipelines in High Consequence Areas ( HCAs ), the regulations also require pipeline operators to reassess transmission lines on a frequency not to exceed every seven years, or more frequently depending on risk. The regulations also require that pipeline operators apply the knowledge gained to understand threats to the rest of the system and to mitigate the risks to assets outside of HCAs, again on an ongoing basis. Third, the integrity management plans must be flexible enough to account for uncertainties or new developments. The litmus test of an effective plan is not whether the planned activities were carried out exactly as forecasted, but whether the plans were based on the best information known at the time and were flexible enough to adapt to unforeseen changes. As new information becomes available (i.e. based on the know your assets
45 criteria), the short-term and long-term plans should be modified to capture this knowledge. For example, Public Service s assessments, repairs, and renewals must be coordinated with the communities in which the work occurs. This might include other planned utility work or street reconstruction or paving activities. When scheduling and executing projects in the field, Public Service strives to minimize impacts on the affected communities; however, the requirements of local governmental bodies might change the scope, cost, and/or timing of various projects. We strive to accommodate changes within the construct of our overall risk management, but keep the safety of the public at the forefront of planning our work. There are a variety of factors that impact resource needs in any given year. While Public Service uses its experience to forecast potential repairs and replacements, the results of the assessments themselves will drive the amount of repair and renewal work during the year. In addition, unforeseen weather and natural disasters, such as the 01 floods or recent wildfires, will also impact our ability to complete planned integrity management work. Finally, another fundamental challenge is emerging and/or pending regulations. Such changes, particularly if they entail the completion of specific activities by certain dates, usually require the Company to modify its long-term plans. Public Service regularly reviews communications received from PHMSA in the form of advisory bulletins published in the
46 Federal Register and considers this information when stepping through the phases of know your system, identify threats, and proactively mitigate risks. Public Service considers all of these challenges when developing its plans including relative risk assessments, known or anticipated regulations, resource availability, and the requirements or preferences of local communities. We make modifications to the plans during the year as these circumstances arise. A. PROGRESS UNDER THE INTEGRITY MANAGEMENT PROGRAMS Q. PLEASE EXPLAIN HOW THE COMPANY S INTEGRITY MANAGEMENT PROGRAMS AND THE VARIOUS INITATIVES THEREUNDER HAVE CHANGED SINCE THE 01 RATE CASE. A. Public Service has made good progress under TIMP and DIMP since the 01 Rate Case. Public Service is making significant progress regarding asset knowledge. The Pipeline Data Project ( PDP ) Distribution project continues to identify and fill in legacy data gaps, increasing the knowledge of our system and supporting the risk modeling of our assets. Further, the pipeline assessment activities being performed are proactively identifying risks and threats to our pipeline system. Assessments facilitate the determination of anomalous conditions on Public Service s pipelines. These anomalous conditions may include corrosion, dents, construction or manufacturing defects, or other conditions. The Company then determines if remediation activity is required, and if so the type of
47 remediation and the timeframe for each anomaly encountered. Assessment technology continues to evolve and Public Service will remain active in understanding and applying these technologies when economical and feasible. Since the last rate case was filed in December 01, much progress has been made on TIMP and DIMP, such as: (1) approximately 1 miles of bare steel main have been renewed; () over,00 CAB services have been replaced with modern materials; () all known cast iron pipe has been removed; () the health and condition of approximately 00 miles of transmission pipelines and miles of distribution mains have been assessed and a number of repairs made; () remote controlled valves ( RCVs ) have been installed at nine sites as part of the Automatic Shut Off / Remote Control Valve ( ASV/RCV ) Set Program; and () the third year of the five-year West Main Transmission Line Replacement Project has been completed. Under the currently-approved PSIA, Public Service is required to file each November 1 the work plan for the major initiatives for the following calendar year. We also voluntarily meet with the Commission s Staff and Office of Consumer Counsel regularly throughout the year, providing a summary of the work, progress to date, findings, and whether we expect any issues. The PSIA procedures also provide for a prudence review, if warranted, after each April annual filing for the prior year s work.
48 Distribution Integrity Management Plan (DIMP) Q. WHAT IS THE DIMP? A. The DIMP was developed based on a rule that was approved by PHMSA in 00. This program is similar to TIMP in the fundamental aspects. The rule addresses how distribution utilities must identify, prioritize risk, evaluate, repair, and validate the integrity of distribution mains. The risk-management approach inherent in DIMP recognizes that many factors must be considered when determining what programs, including replacement, are appropriate to maintain the safety, reliability, and integrity of a distribution system. As required by the rule, Public Service published its DIMP plan in August 0 and submitted it to the Commission on September, 0. Q. WHAT SPECIFIC DIMP PROGRAMS ARE CURRENTLY INCLUDED IN THE PSIA? A. The following programs are part of Public Service s DIMP program and are collected through the PSIA rider mechanism: Renewal Programs 1. AMRP (a separate PSIA category), which replaces certain pipe types, such as cast iron, bare or black steel, and PVC within the distribution system;. CAB Gas Service Replacement Program (a separate PSIA category), which replaces pipes that are made of Cellulose Acetate Butyrate material;. Programmatic Pipe Replacement Program, which programmatically replaces poor performing distribution mains and services not covered by the AMRP or CAB programs;. Distribution Valve Replacements, which replaces existing distribution system isolation valves to improve isolation capabilities;
49 Asset Knowledge Programs. PDP Distribution, which improves distribution asset records;. Intermediate Pressure Distribution Line ( IP Line ) assessments, which assess the health and condition of IP lines, primarily using inline inspection tools;. Indirect Survey, which utilizes above ground technology to assess the health and condition of distribution lines;. Bridge Crossings/Exposed Pipes, which inspects the condition of pipelines installed on bridges or are otherwise exposed to the elements causing atmospheric corrosion;. Accelerated Leak Survey, which performs annual leak surveys on mains and services for the worst performing pipe types; Public Safety Enhancement Programs. Federal Code Mitigation, which effectuates repairs or changes to certain assets based on changes to the Federal Code;. Shorted Casing, which tests and repairs pipelines in casings to reduce leakage risk; 1. Unprotected Pipe, which identifies, tests, repairs/protects and maps distribution coated steel pipe that is not currently cathodically protected from corrosion; and 1. Above Ground Facility Protection (also referred to as Meter Barricades), which installs protection to above ground facilities to protect from vehicle and other damage. Q. HOW DOES PUBLIC SERVICE RECOVER THE COSTS ASSOCIATED WITH THE DIMP PROGRAM? A. The costs of the Company s DIMP efforts will continue to be collected through the PSIA, which expires on December 1, 01. Since the costs vary significantly from year to year, making it difficult to establish a representative level during a base rate case, Public Service continues to support recovering the costs associated with our DIMP programs through the PSIA. Thus, Public Service requests that the PSIA be extended for a minimum of five years, or until December 1, 00.
50 Q. IS PUBLIC SERVICE PROPOSING ANY CHANGES TO THE DIMP PROGRAM IN THIS PROCEEDING? A. Yes. Public Service is requesting that recovery of the costs associated with the CAB Gas Service Replacement Program be moved from the PSIA into base rates. The Company is also requesting acceleration of two DIMP projects: AMRP and the Programmatic Risk-Based Pipe Replacement Program. a. CAB Gas Service Replacement Program Q. PLEASE DESCRIBE THE CAB GAS SERVICE REPLACEMENT PROGRAM. A. In 00, Public Service identified CAB services as a type of pipe susceptible to deterioration, similar to the types of pipe covered under the AMRP. CAB is a polymer that Public Service and many other gas companies used in the 10 s through about, primarily for service lines. Over time, the CAB material is becoming less ductile, which means that CAB services are more susceptible to brittle cracking under bending forces, such as frost-heave, traffic loads, or insufficient compaction of disturbed soil. Based on this less ductile tendency, as well as higher-than-average leakage rates, CAB services are at or near the end of their useful lives. There are approximately,00 services made of this material remaining in Public Service s system. From 00 through the third quarter of 01, Public Service has replaced over 1,000 CAB services. The remaining services have been identified for replacement by the projected end of the program in 01, the first year of
51 the MYP. Thus, Public Service requests that recovery of costs for this project be moved from the PSIA to base rates as of January 1, 01, the second year of the MYP. See the Direct Testimony of Company witnesses Mr. Wishart, Ms. Jackson and Ms. Deborah A. Blair for further details. b. Acceleration of the AMRP and the Programmatic Risk- Based Pipe Replacement Program Q. PLEASE DESCRIBE THE AMRP PROGRAM. A. This program, initiated in 00, focuses on replacing the poorest performing pipe types of cast iron, bare or black steel, and PVC within the distribution system. Primarily due to deterioration of the material, mains of these material types have the highest leak rates on the system, and these rates continue to increase the longer the pipe stays in the ground. Cast iron and bare steel were the earliest types of main installed by the gas utility industry, and continued to be installed until the mid-10 s. PVC was primarily installed in the 10 s and 10 s. Cast iron and bare steel are susceptible to the time-dependent threat of corrosion. Cast iron may also graphitize, meaning that it is susceptible to a form of corrosion that transforms iron into graphite flakes and iron oxides. Cast iron pipe that has experienced the prolonged effects of graphitization simply crumbles apart to the consistency of the surrounding soil. Based on the higher leak rates, as well as this graphitization threat, mains of this type in the Public Service system are effectively at or near the end of their useful lives. 0
52 PVC tends to become brittle over time and is prone to damage from tree roots and other minor soil disturbances. Additionally, glue applied to PVC pipe and sockets can eventually deteriorate over time, leaving those joints porous and susceptible to leaks. Q. WHAT HAS BEEN THE PROGRESS OF THE AMRP SINCE ITS IMPLEMENTATION? A. From the inception of the Company s AMRP in 00 through 01, approximately miles of pipe (over miles of cast iron pipe, over 0 miles of bare steel pipe, and over 0 miles of PVC pipe) have been replaced. Significantly, since the 01 Rate Case, Public Service has removed all of the remaining known cast iron pipe from its system. The goal of the Company s AMRP is to remove all of the remaining bare steel and PVC from its system. In order to evaluate progress on identifying and removing high risk pipe materials from the system, Public Service continues to improve data elements associated with its assets and to better understand the integrity of its system through pipeline assessments and field inspections. Annual leak surveys, along with input from Subject Matter Experts ( SMEs ), are utilized in determining the prioritization of the projects from year to year; i.e., if we have an area where we see an increase in leaks or threats that pose a risk, we will re-prioritize the work to address that issue. Attachment CFC- provides a summary of historical AMRP results. 1
53 Q. PLEASE DESCRIBE THE PROGRAMMATIC RISK-BASED PIPE REPLACEMENT PROGRAM. A. The Programmatic Risk-Based Pipe Replacement Program identifies and programmatically replaces distribution mains, not covered by the AMRP or CAB programs, that have a higher relative risk to public safety than other distribution main and service segments. The program is currently focused on three general pipe types: (1) older vintage steel and/or problematic steel pipe that has been previously referred to as the Coated Steel Main Replacement Program, which includes a specific type of vintage coated steel referred to as mill wrap; () pre-1 Aldyl-A mains and services; and () coupled Intermediate Pressure (IP) mains. The pipe segments targeted for replacement are risk-ranked based on history of leakage, pipes with problems in the coating or cathodic protection as identified through direct assessment, issues posed by legacy construction practices, and engineering judgment provided by SMEs. The PDP-Distribution project is designed to address data gaps associated with these pipe types and new information, as it is received, will be integrated into the overall strategy. Q. WHAT CHALLENGES DOES PUBLIC SERVICE FACE ON ITS PIPELINE SYSTEMS? A. With the completion of the removal of the cast iron main from our gas system in 01, Public Service continues to make great strides in modernizing its pipeline infrastructure; however, significant work remains.
54 Considerable quantities of pipe in service are constructed from vintage materials (bare steel, Aldyl-A, PVC, and mill wrap steel) or were installed utilizing inferior techniques (couplings) that will eventually require replacement. A review of the leak data is contained in Attachment CFC- shows that Public Service s leak ratio on its distribution mains is remaining fairly stable despite the fact that several hundred miles of poor performing pipe type have been removed from the system. This data supports the conclusion that substantial replacement efforts remain and that the current pace of replacement, especially for AMRP and vintage coated steel, will need to be accelerated in order to finish the effort over a reasonable timeframe to ensure public safety. Q. WHAT IS PUBLIC SERVICE S PROPOSAL REGARDING AMRP AND THE PROGRAMMATIC RISK-BASED PIPE REPLACEMENT PROGRAM? A. Just as the Company removed all the cast iron from its system, Public Service plans to remove all known bare steel, PVC, pre-1 Aldyl-A, and mechanically coupled pipe from its system. In addition, the Company has identified certain sections of vintage mill wrapped steel that has reached the end of its useful life and needs to be replaced. As the Company continues to understand the health and condition of its pipelines through data projects, leak ratios, and through pipeline assessment results, the exact number of miles of pipeline that needs to be replaced may change as will the order in which we remove those identified pipelines. Because these identified pipes
55 are known to be problematic throughout the industry and continue to deteriorate further the longer they are in the ground, the Company is requesting to accelerate the removal of these pipes on its system. Q. WHAT IS THE COMPANY S PLAN AND WHAT ARE THE BENEFITS OF ACCELERATING THE REMOVAL OF THESE PROBLEMATIC PIPES? A. Since bare steel, PVC, pre-1 Aldyl-A, mechanically coupled pipe, and identified sections of vintage mill wrapped steel have reached the ends of their useful lives and they continue to deteriorate, the Company believes it should accelerate the removal of these identified pipes for public safety reasons. Obviously, these pipes cannot be replaced overnight, as they must be removed in a planned manner that takes into consideration the availability of Company and contract resources, the continued operation of the gas system as pipes are taken out of service, and coordination with communities in which these pipelines reside. As filed in the Company s 01 PSIA Plan in Proceeding No. 1AL- 1G, the Company plans to spend approximately $ million in capital to remove these poor performing pipes in 01. The Company recommends doubling the amount spent annually to remove these pipe types, thereby addressing the significant need to accelerate efforts to replace leak-prone mains and services constructed using materials that are susceptible to corrosion and leaks. In response to heightened public concern about the safety, reliability, and integrity of the nation s pipeline infrastructure, the recently-enacted 0 Pipeline Safety Act requires pipeline operators,
56 regulators, and all industry stakeholders to develop and carry out plans to address the replacement of deteriorating and leak-prone pipeline infrastructure. Public Service believes that accelerating the removal of these pipe types by doubling the amount of capital expenditures on these initiatives is in the best public safety interest of our customers. Q. ARE OTHER GAS UTILITIES ACCELERATING THEIR REPLACEMENT PROGRAMS? A. Yes. In states such as Kentucky and New Jersey, such programs have been established allowing local gas distribution companies to recover the costs of replacing or repairing pipeline infrastructure at an accelerated rate. For example, on May, 0, the Kentucky Public Service Commission authorized Atmos Energy to implement a pipeline replacement program cost recovery surcharge that will be used to replace all bare steel mains over a 1 year period. Also, in February 01, the New Jersey Board of Public Utilities approved an accelerated gas main replacement program for South Jersey Gas. These utilities, among others, emphasized that their facilities are safe and maintained in accordance with current state and federal safety standards; further, there were explanations that the replacement of certain system segments should be expedited and segments in higher population areas should be addressed sooner, rather than later. 1 1 For further information about these programs, among others, reference the PHMSA website outlining numerous state replacement programs.
57 Q. PUBLIC SERVICE PROPOSED AN ACCELERATION OF THE AMRP AND VINTAGE COATED STEEL PROGRAM IN THE 01 RATE CASE. WHY IS THE COMPANY MAKING A SIMILAR PROPOSAL IN THIS CASE? A. In the 01 Rate Case, the Commission determined that it was not appropriate to grant Public Service s request for explicit approval of its plans to accelerate its pipeline inspection and replacement activities in this proceeding. If Public Service wants the Commission to rule on the merits of accelerated spending in these areas with cost recovery through the PSIA, such request may be part of the new application concerning any request to extend and to expand the scope of the PSIA, as discussed above. 1 Public Service believes that the proposal being made by the Company in this proceeding respects the previous outcome of the 01 Rate Case and provides a reasonable direction for an acceleration of the spending on important pipeline inspection and replacement activities for two main reasons. First, PSIA projects cannot be considered separate and apart from other additions to rate base. As I discussed earlier, under federal rules, Public Service is responsible for discovering and evaluating the risks of its system and for addressing those risks in a proactive manner. In other words, Public Service must know its assets; identify the risks and threats to those assets; and be proactive in mitigating those risks and threats. It is in accomplishing and sustaining this goal that Public Service s focus on operating our system in a proactive and predictive manner bears fruit for our customers. Public Service cannot engage in a meaningful discussion 1 Decision No. C1-1,.
58 regarding this transition in this proceeding without addressing both PSIA and non-psia projects and programs. These programs are also key to Public Service accomplishing its mission of providing safe and reliable service. Second, Public Service s proposal in this proceeding changes only the work plan for these programs and not the total costs. Thus, Public Service is not increasing the estimated costs associated with these programs, but rather, will enhance the safety and reliability of our system sooner.. Transmission Integrity Management Plan (TIMP) Q. WHAT IS THE TIMP? A. Public Service s TIMP was developed pursuant to the Pipeline Safety Improvement Act of 00, and the regulations promulgated thereunder by the DOT s Office of Pipeline Safety. Now administered by the PHMSA, this federal law required operators of transmission pipelines initially to assess the pipelines that are in HCAs by December 1, 01, which Public Service completed timely. TIMP is an ongoing program in which pipelines are required to be reassessed periodically based on risk, but at least every seven years. It is important to note that in addition to assessing pipelines and remediating found conditions, pipeline operators are also expected to understand threats to the entire system, to apply the knowledge gained across all pipelines in the system, and to implement preventative measures
59 to mitigate risks on all assets in the system. This program is prescriptive and extensive. Q. WHAT SPECIFIC TIMP PROGRAMS ARE CURRENTLY INCLUDED IN THE PSIA? A. The following programs are currently part of Public Service s TIMP program and costs for these programs are recovered through the PSIA mechanism: Renewal Programs 1. Edwards-to-Meadow Mountain Transmission Project (a separate PSIA category), which replaced a segment of pipeline between Edwards and the Meadow Mountain facility near Vail;. West Main Transmission Line Replacement Project (a separate PSIA category), which installs approximately six miles of new distribution and transmission pipe to tie into the existing system, replaces miles of vintage transmission pipe, and abandons almost miles of vintage transmission pipe;. Fraser to Frisco Pipeline Reroute Project, which reroutes and replaces approximately two miles of pipeline in Frisco; Asset Knowledge Programs. In Line Inspection ( ILI ) Assessments, which assesses Public Service s transmission pipeline using ILI technology; Pipeline Safety Enhancement Programs. Vegetation Management Right-of-Way ( ROW ) Clearing Program, which clears transmission pipeline right-of-ways of excess vegetation;. Maximum Allowable Operating Pressure ( MAOP ) Validation Project, which assures that key operating criteria (specifically MAOPs and maximum operating pressures) are supported by records that are traceable, verifiable, and complete; and. ASV/RCV Valve Sets, which installs mainline isolation valves or adds actuators to existing valves to more quickly minimize
60 the effect of unplanned gas release on high pressure gas transmission pipelines. Q. HOW DOES PUBLIC SERVICE RECOVER THE COSTS ASSOCIATED WITH THE TIMP PROGRAM AND WHAT CHANGES IS THE COMPANY PROPOSING WITH REGARD TO RECOVERY OF TIMP-RELATED COSTS? A. The costs of our TIMP efforts, including ILI Assessments, non-capacity related portion of West Main Transmission Line Replacement Project, Fraser to Frisco Pipeline Reroute Project, Vegetation Management ROW Clearing Program, ASV/RCV Valve Sets Project, and MAOP Validation Project will continue to be recovered through the PSIA, which expires on December 1, 01. Given the volatility of these costs, Public Service continues to support recovering the costs associated with our TIMP programs through the PSIA. Thus, Public Service requests that the PSIA be extended for at a minimum of five years, or until December 1, 00. Q. IS PUBLIC SERVICE PROPOSING ANY CHANGES TO THE TIMP PROGRAM IN THIS PROCEEDING? A. Yes. Public Service is requesting to move recovery of the costs associated with the Edwards-to-Meadow Mountain Transmission Project into base rates starting in the 01 Test Year. Also, Public Service is updating the forecasted costs associated to complete the West Main Transmission Line Replacement Project.
61 Q. PLEASE DESCRIBE THE EDWARDS-TO-MEADOW MOUNTAIN TRANSMISSION PROJECT. A. The -mile, -inch and -inch pipeline between Edwards and the Meadow Mountain facility near Vail was identified for replacement as a result of a TIMP ILI assessment. This project was completed in 01. A portion of the project costs, estimated to be. percent of the total project costs, was attributable to increasing the capacity of the pipeline by installing 1- inch pipe. This portion of the project was excluded from recovery through the PSIA. As mentioned above and also discussed by Company witnesses Ms. Jackson and Ms. Blair, since this project is complete, the Company is proposing that recovery of costs for the Edwards-to-Meadow Mountain Transmission Project be removed from the PSIA and moved into base rates as of January 1, 01. Q. PLEASE DESCRIBE THE WEST MAIN TRANSMISSION LINE REPLACEMENT PROJECT. A. The West Main Transmission Line Replacement Project involves an 0-mile pipeline serving the Fort Collins, Loveland, Longmont, and Boulder areas. The majority of this line was installed in the 10 s and 10 s, although sections of the line were replaced in the 10 s and 10 s. Based on the results of TIMP ILI assessments and evaluations that occurred between 00 and 01, the Company decided to install approximately six miles of new distribution and transmission pipe to tie into the existing system, and to 0
62 replace the remaining miles of pipe. The project also involved abandoning almost miles of vintage transmission pipe. As part of this replacement, Public Service increased the diameter of some sections of the pipe to 1-inches, in part to address current and future operations and load growth. 1 Public Service forecasts that this project will be completed in , with some minor restoration activities carrying over into 01, the last two years of the MYP. Work on the West Main Transmission Line project began in 0, with initial planning and design work and construction activity beginning in 01. The multi-year nature of this construction project has presented some unique challenges with respect to procuring construction contractors. Since 01, the overall economy has been experiencing an economic recovery with significant growth in the oil and natural gas sectors. As a result of these conditions, the Company has experienced rising cost per unit contractor bids due to industry-wide demand for these construction resources. Additionally, increased environmental requirements have required more bore installations of pipeline in environmentally sensitive areas than originally planned. Finally, the route of the West Main pipeline is dependent on the location of the right-of-way obtained, which impacts the amount of pipe needed and the scope of the project completed each year. Permitting requirements and required right of way route changes have necessitated changes in the originally planned alignment of the pipeline. As a result of these changes, 1 The costs attributable to increasing the capacity, estimated to be. percent of the total project cost, were excluded from recovery through the PSIA. 1
63 Public Service is currently estimating that the final project cost will increase from $10 million 1 to an estimated $1 million. In addition, 01 and 01 costs related to this project could potentially increase by another $ million over this current estimate to complete. This additional $ million is potential upward pressure from boring and routing changes from current plans in Lousiville and Boulder County. Public Service is in the process of obtaining construction bid packages for planned work to occur in late 01 and 01 for the project, and may have the opportunity to update these estimates in rebuttal testimony, once bids are received. B. ASSESSMENT OF INTEGRITY PROGRAMS Q. WHAT IS YOUR OVERALL ASSESSMENT OF INTEGRITY PROGRAMS IN GENERAL, AND SPECIFICALLY FOR PUBLIC SERVICE? A. Public Service has significantly enhanced the safety and reliability of our system since the 0 Rate Case, when the PSIA was approved. Just in the years since the 01 Rate Case, as part of the DIMP, Public Service has removed over 1 miles of bare steel main; removed over miles of cast iron main; removed over,00 CAB services; and added RCVs to nine sites. The CAB Gas Service Replacement Program is scheduled to be completed in 01 and the West Main Transmission Line Replacement Project is scheduled to be completed in 01. Under the AMRP, Public Service has removed the remaining known cast iron main from its system. 1 See 01 Rate Case, Campbell Direct Testimony, pp. -.
64 Under the Company s TIMP, over 0 percent of the gas transmission system has been assessed. These assessments have identified over,0 anomalies that have been repaired, signifincatly increasing the safety and reliability of the system. Specifically, over 0 anomalies were found as a result of a 01 assessment of the Frisco to Fraser pipeline and all have been mitigated. This pipeline experienced a failure in November of 01 that could have negatively impacted almost 0,000 customers. Q. HOW DOES PUBLIC SERVICE PRIORITIZE THE WORK THAT MUST BE COMPLETED ON ITS SYSTEM? A. PHMSA has urged gas utilities in an advisory bulletin to replace the highest risk pipes first. Public Service prioritizes the replacement of its facilities considering the following factors: leak incident rates, operating pressure, age of pipeline, population density, construction materials, industry knowledge and guidelines, and areas of significant construction (municipal improvement projects, etc.). Public Service believes the consideration of all these factors provides a comprehensive assessment which provides guidance to the Company in determining which pipes should be replaced first.
65 1 1 1 Q. WHAT DO YOU CONCLUDE REGARDING THE COMPANY S TIMP AND DIMP PROGRAMS IN TERMS OF ENSURING RELIABILITY AND MITIGATING SAFETY RISKS? A. Programs and projects under our TIMP and DIMP have without question supported Public Service s continued focus on operating in a proactive and predictive manner. Not only do our customers expect us to deliver on our promise and mission to deliver safe and reliable service, but their perception and tolerance of risk has changed. The four categories of elements that Public Service has identified as essential to its mission: (1) the implementation of enhanced safety processes and procedures; () the efficient management of resources; () the operation of our system in an efficient and effective manner; and () maintaining a well-trained workforce provide the framework for effective execution of our TIMP and DIMP programs.
66 IV. CHANGES IN GAS SYSTEMS AND DISTRIBUTION OPERATIONS COSTS AFFECTING BASE RATE REVENUE REQUIREMENTS Q. PLEASE SUMMARIZE WHAT YOU WILL BE DISCUSSING IN THIS PART OF YOUR TESTIMONY. A. First, I will discuss the O&M expenses for the Gas Utility and specifically the Gas Utility transmission and distribution business areas. This includes a discussion of the drivers of the variance between the 01 Rate Case test year, 1 months ending September 0, 01 ( 01TY ), and the HTY, 1 months ending June 0, 01. I will also touch upon some of the key known and measurable adjustments to the HTY O&M expenses that form the basis of the Test Years, provide a brief description of the related activities, and reference key witnesses that go into more detail on these activities. Second, I will describe the capital budget development process and present information on the proposed capital budgets for the MYP period, 01 through 01. Finally, I will address the noteworthy plant additions within the Gas Utility. Q. HOW IS THIS SECTION OF YOUR TESTIMONY ORGANIZED? A. I have broken down this section of my testimony into three parts: O&M expenses, capital costs and other adjustments.
67 A. OPERATIONS AND MAINTENANCE (O&M) EXPENSES Q. WHAT ARE THE TYPES OF COSTS THAT THE GAS UTILITY INCURS FOR OPERATIONS AND MAINTENANCE? A. The Company incurs O&M expenses in order to provide safe and reliable service of natural gas to our customers. These expenses are incurred across various departments of the Gas Utility including the transmission and distribution business areas and are related to numerous activities that support the gas system Internal labor the costs related to the O&M portion of salaries, straight time labor, overtime, premium time, and employee expenses for internal employees. Contract labor and consulting costs related to the use of contract labor and consultants which allows Public Service to increase and decrease staffing levels as workloads require rather than bringing on more full-time staff, and to retain the services of experts as needed for specific tasks or project efforts. Materials costs related to consumables, hardware, and refurbished materials used in maintenance and repair operations, as well as tools and small equipment. Transportation costs for internal fleet assets as directed to O&M accounts on an hourly basis including cars, trucks, construction equipment, and trailers.
68 O&M First Set Credits costs associated with the accounting treatment of meter set expenses. Other expenses costs incurred by the Gas Utility to perform other O&M activities. Q. DESCRIBE THE LABOR ACTIVITES THAT OCCUR THROUGHOUT THE TRANSMISSION AND DISTRIBUTION BUSINESS AREAS OF THE GAS UTILITY. A. Labor costs incurred by the Gas Utility are spread across several functional areas: Gas Engineering; Project Delivery and Technical Services; Gas Governance; Gas Operations; Gas System Strategy and Business Operations; and Distribution Operations These functional areas are focused on the reliability, safety, customer service, operational efficiency, and fiscal oversight necessary to construct, operate, and maintain the gas transmission and gas distribution systems in Colorado. Gas Engineering provides engineering technical support to ensure safe and compliant operations and maintenance of distribution, transmission, and storage assets. Project Delivery and Technical Services provides project management, financial management, project controls, records management, and geospatial support.
69 Gas Governance provides risk management, advocacy, interaction with state and federal agencies, compliance assurance, and code compliance. Gas Operations is comprised of the gas emergency response organization for the greater Denver metropolitan distribution system, statewide operation and maintenance of the high pressure gas systems, gas control, corrosion services, and technical services. Gas System Strategy and Business Operations is responsible for strategic direction of the overall gas organization, planning and budgeting of short term and long term projects, and transport customer support. Distribution Operations is responsible for direct interaction with customers requesting service changes, design and work order generation for customer requested work, field construction activities related to the distribution facilities, and the management of contractors working on certain gas assets Key Drivers Causing O&M Expense to Increase Between the 01TY and the HTY Q. WHAT ARE THE O&M EXPENSES INCURRED BY THE GAS UTILITY IN THE 01TY AND THE HTY? A. Expenses have escalated since the 01 Gas Rate Case, just as they have for many other businesses throughout the nation. O&M expenses for the Gas Engineering and Operations and the Distribution Operations business areas for the 01TY and the HTY, adjusted for known and
70 measurable changes, are provided in Table CFC-1 below. Also included in Table CFC-1 are the key drivers of O&M expense increases from the 01TY and the HTY.
71 Table CFC-1 Drivers of O&M Expenses from 01 TY to HTY 01TY Driver Amount HTY Total O&M (Adjusted) $1. million Labor $. million Vacancies Damage Prevention Gas Storage Field Maintenance Enhanced Leak Management $1. million $. million $1. million $. million Other $1. million $1. million $1. million $.0 million Additional details on the adjustments applied to the O&M expenses in Table CFC-1 are provided later in my testimony. Q. WHAT ARE THE KEY DRIVERS CAUSING THE INCREASE IN O&M EXPENSES BETWEEN THE 01TY AND THE HTY? A. There are a number of key drivers causing the increase between the 01TY and the HTY O&M expenses: 1 Labor, including merit, headcount, and overtime; Vacancy adjustment in the HTY; Damage Prevention Program; Gas Storage Field Maintenance; and, Improved Leak Management. 0
72 a. Labor and Vacancies Q. PLEASE EXPLAIN THE KEY DRIVERS RELATED TO LABOR. A. Labor costs are a significant driver of the increase in expenses, totaling approximately $. million from the 01TY to the HTY. The increase in labor is attributable to annual merit increases, an increase in authorized positions and related headcount, and overtime. First, merit increases allow the organization to remain competitive in the labor market in order to attract and retain the skills and talent needed to run a successful gas organization, as explained by Company witness Ms. Ruth Lowenthal. Second, adding and filling new positions contributed to labor cost increases. Adding these new positions was important for two reasons: (1) it supports the organizational realignment that occurred in 0; and () it facilitates the organization in an overall culture shift to focus on being more proactive towards pipeline integrity and safety and reduces the operational risk of the Gas Utility. The employees that were hired between the 01TY and the HTY have been added to the Gas Utility, enhancing the operation of Project Management, Gas Governance, and Gas System Strategy and Business Operations departments. Table CFC- below sets forth the increase in headcount by functional area: 1
73 Table CFC-: Increase in Headcount from 01TY to HTY Functional Area Number of New Positions Gas System Strategy and Business Operations Gas Governance Project Delivery and Technical Services 1 Total The Gas Governance and Gas System Strategy and Business Operations departments did not exist during the 01TY. Nine positions were added in the Gas System Strategy and Business Operations department and three positions were added in the Gas Governance department. The majority of the headcount within these two departments are incremental increases from the 01TY to the HTY. The Gas Governance department coordinates company personnel to ensure proactive statewide compliance with all gas codes, policies and standards, including the proactive identification and resolution to any areas of concern to maintain the safety of the public and cost effectively maintaining the pipeline system. The Gas System Strategy and Business Operations is responsible for the development and execution of regulatory and budgetary strategies for the Xcel Energy gas organization. The remaining twelve positions were added to the Project Delivery and Technical Services area. We continue to move to a more structured and disciplined project management approach to improve oversight for large capital projects and programs of work. After studying our own Electric Transmission and Energy Supply project management organizations, we determined that the best path forward was to have a
74 similar project management structure in the Gas Utility. As a result, a new Project Management department and a new Support Services department were formed during 01, with twelve employees. These departments are a part of the Project Delivery and Technical Services area identified in Table CFC- above. The new Project Management employees have implemented various process improvements to assist with the completion of large capital projects. The new Support Services department continues to establish and to implement consistent processes for records retention and capturing data in order to improve overall knowledge of our assets. This data provides key asset information that feed into our risk management program and integrity management analysis. In addition, as previously discussed, accurate and complete data on our assets is becoming much more critical, from both a regulatory and an integrity management perspective. The Support Services department also ensures that the Company is collecting and retaining the necessary data to not only evaluate and understand the integrity of our assets, but to identify gaps and assist in closing those data gaps. Q. YOU STATED THAT PART OF THE LABOR INCREASE BETWEEN 1 0 THE 01TY AND HTY IS RELATED TO OVERTIME. EXPLAIN. PLEASE 1 A. Overtime was a third significant driver for the increase in labor costs. Overtime expenses are not only affected by the amount of overtime that was required but are also affected by merit increases. The amount of
75 overtime between the 01 TY and the HTY increased due to an increase in responses to calls (including responses to customer notification of gas odor calls and responses to gas emergency calls), leak repairs, meter set repairs, and relighting customers who may have experienced a gas outage. Q. IN ADDITION TO THESE INCREMENTAL INCREASES IN HEADCOUNT, DID PUBLIC SERVICE ALSO FILL EXISTING VACANCIES BETWEEN THE 01TY AND THE HTY? A. Yes. Between the 01TY and the HTY, nine existing vacancies in the distribution operations organization were filled, which resulted in increased labor costs for that department. These positions are not included in Table CFC- above depicting incremental position increases, and filling these vacancies contributed to the increased labor expenses between the 01TY and the HTY. Q. PLEASE EXPLAIN THE KEY DRIVERS RELATED TO THE VACANCY ADJUSTMENT. A. The vacancy adjustment in the HTY is for vacant positions that have been filled or will be filled during in the near future. Filling these vacancies results in an increase of $1. million in HTY O&M expenses and is described more fully later in my testimony along with the other adjustments made to the HTY.
76 b. Damage Prevention Q. PLEASE EXPLAIN THE KEY DRIVERS RELATED TO DAMAGE PREVENTION PROGRAM. A. Damage Prevention Program expenses increased from the 01TY to the HTY by approximately $. million. This increase in costs is attributable to the increase in the number of locates and new procedures regarding quality control and supervision. The Damage Prevention Program is discussed in Mr. Litteken s Direct Testimony. c. Gas Storage Field Maintenance Q. PLEASE DESCRIBE THE KEY DRIVER RELATED TO GAS STORAGE FIELD MAINTENANCE. A. The Company initiated improved gas storage field maintenance to test the integrity of gas wells associated with the Company s storage fields. The Company also has begun a regular and systematic program of bottom hole testing to monitor the health of its storage fields and ensure continued reliable deliverability. This caused an increase of approximately $1. million from the 01TY to the HTY. Q. PLEASE DESCRIBE PUBLIC SERVICE S GAS STORAGE FACILITIES AND RELATED WELLS. A. Public Service has three underground gas storage facilities, which are depleted natural gas fields Roundup, Asbury, and Fruita. The purpose of underground gas storage fields is to provide supply flexibility, to ensure reliable deliveries, and to mitigate the risk associated with seasonal price
77 movements. With respect to these gas storage fields, wells are used to inject gas into a field and to withdraw gas when needed. Roundup has wells, Asbury has wells, and Fruita has one well. Q. WHAT ASSETS ARE IMPACTED BY THE GAS STORAGE FIELD MAINTENANCE? A. This program will address the on-going expenditures needed to manage and to enhance the safety and reliability of the storage fields prudently. The assets at the storage field include: (1) the gas storage wells; () the wellhead separators; () the methanol tanks and injection pumps; and () gas flow measurement equipment, such as the flow meters and associated telecommunications equipment. Q. WHAT TYPES OF ON-GOING EXPENDITURES ARE REQUIRED TO MAINTAIN THE GAS STORAGE FIELD ASSETS? A. Public Service s storage field assets require a robust and consistent maintenance program to ensure well integrity, environmental compliance, safety, and reliability. The wells can reach depths of over,000 feet below ground. Failure to maintain any component required to run the field can result in significant reliability concerns and potentially significant subsequent O&M costs. Q. HAS PUBLIC SERVICE ALREADY INCURRED SOME OF THESE COSTS IN THE HISTORICAL TEST YEAR (HTY)? A. Yes. There are $1. million of O&M expenses included in the HTY for regular and routine gas storage field maintenance.
78 Q. WHAT BENEFITS WILL RESULT FROM THE GAS STORAGE FIELD MAINTENANCE PROGRAM? A. The benefits resulting from this program are two-fold. First, the program will enhance the safety and reliability of Public Service s Gas storage fields. It will prevent gas escaping into domestic water wells, possibly resulting in injury or damage to persons and/or property, thus protecting public health and safety. Second, it will allow Public Service to manage its storage field prudently and to avoid gas escaping into areas of the underground storage fields where it cannot be recovered. Q. WHAT DO YOU CONCLUDE REGARDING THE GAS STORAGE FIELD MAINTENANCE? A. This program should be approved as the related O&M expenses are prudent and reasonable. The project further enhances the safety and reliability of Public Service s gas system. d. Enhanced Leak Management Q. PLEASE DESCRIBE THE KEY DRIVER RELATED TO ENHANCED LEAK MANAGEMENT. A. This program was initiated in order to survey, pinpoint leaks, repair leaks, and perform safety re-checks on identified leaks not classified as Grade 1 leaks. Leak management costs increased during the HTY compared with the 01TY by approximately $. million.
79 Q. PLEASE DESCRIBE THE COMPANY S LEAK MANAGEMENT PROGRAM. A. The Company has a comprehensive leak management program that is part of its DIMP and is furthered detailed in its Pipeline Compliance and Standards manual. The leak management program is comprised of the following elements: 1. Leak detection procedures,. Leak classification criteria,. Leak repair and monitoring schedules, and. Leak record-keeping requirements. The Company utilizes outside contractors to aid in the execution of its overall leak management program. Q. HAS THE COMPANY MODIFIED ITS LEAK MANAGEMENT PROGRAM SINCE THE 01 RATE CASE? A. Yes, the Company has made several modifications to its leak management program since the 01 Rate Case. First, the Company has reduced the time to remediate Grade leaks on its system to better align with industry best practices. The time to remediate Grade leaks has been shortened from 1 months to 1 months. In calendar year 01, the Company actually improved upon this important metric and was able to remediate percent of all grade leaks within months. Second, the Company introduced a new Grade gas leak classification since the 01 Rate Case. An above-ground leak causing a
80 minor escape of gas is classified as a Grade leak. The Company implemented this classification of leaks to better track and monitor above ground leaks on our system. Third, since the 01 Rate Case the Company has implemented modifications to the forms used to track and to record information associated with leak management. This modification was implemented to comply with more stringent data requirements, such as the need to track the failure of mechanical fittings. The other driver behind changes to the leak management form was to promote the collection of additional data points to be used to enhance our knowledge of the system and overall risk evaluation, two primary elements of the Company s DIMP. Q. HAS THE COMPANY INCREASED ITS SAFETY CHECKS AND RE- CHECKS FOR GRADE 1 AND GAS LEAKS SINCE THE 01 RATE CASE? A. Yes. When the Company identifies a Grade leak, it is required to perform a Safety Check on the leak every 0 days until the leak is repaired. The Company s Pipeline Compliance and Standards manual currently requires Grade leaks to be remediated within 1 months. Therefore, once a Grade leak is identified, a Company or contract crew could revisit the site of the leak three times before it is remediated. The number of Safety Checks has increased by almost 0 percent, from, to, for Grade leaks, since the 01 Rate Case.
81 In addition, the Company is required to Re-check Grade 1 leaks after the repair is made to monitor any residual gas. This practice/requirement also ensures that the leak was repaired and that no other leaks are present in the area. The number of Re-checks has increased by percent, from 1,0 to 1, for Grade 1 leaks, since the 01 Rate Case. Q. HAS PUBLIC SERVICE INCURRED ADDITIONAL O&M EXPENSES IN THE HTY AS A RESULT OF THE MODIFICATIONS TO ITS LEAK MANAGEMENT PROGRAM? A. Yes. O&M expenses for materials and outside contractors have increased over $. million since the 01 Rate Case as a result of the modifications the Company has made to its leak management program as well as the significant increase in the number of Safety Checks and Re-checks. These expenses are expected to reoccur annually. Q. WHAT DO YOU CONCLUDE REGARDING THE COMPANY S ENHANCED LEAK MANAGEMENT PROGRAM? A. The modifications the Company has made to its leak management program - more stringent requirements to remediate Grade leaks, modifications to the leak management form, and diligence in performing Safety Checks and Re-checks, all support our proactive and continuous improvement program to ensure the safety of our employees and the public. This program should be approved as the related investments are prudent, reasonable in cost, and used and useful in providing customer 0
82 service. Further, the related O&M expenses are prudent and reasonable. As explained earlier, this program will improve the safety and reliability of Public Service s gas system, but does not share the variable nature of the PSIA projects, which is why we are requesting base rate recovery of associated costs rather than PSIA rider recovery in this case. The Company will continue to monitor its overall leak management program, clarifying standards and expectations as necessary to ensure the safe and reliable operation of its gas system HTY O&M Expenses and Adjustments Q. WHAT WERE PUBLIC SERVICE S HTY O&M COSTS FOR GAS ENGINEERING AND OPERATIONS AND DISTRIBUTION OPERATIONS? A. The actual adjusted O&M expenses during the HTY totaled $.0 million. Table CFC- below identifies the amount of overall O&M costs by the categories identified earlier in my testimony. Accounting of these expenditures by FERC account is described below. 1
83 Table CFC- Cost Categories of HTY O&M Expenses Cost Category Internal Labor Contract Labor and Consulting Materials Transportation O&M First Set Credits Other Expenses TOTAL Expenses $. million $0. million $. million $. million ($.0 million) $. million $.0 million Q. PLEASE PROVIDE THE EXPENSES FOR THE 01TY AND HTY BY FERC ACCOUNT. A. Table CFC- below provides a breakdown of the Gas Engineering and Operations and the Distribution Operations business areas O&M expenses during the 01TY and the HTY by FERC account.
84 Table CFC- 01TY versus HTY Expenses by FERC 01 TY HTY Variance Mtce of Res. & Wells 1, 1,,0 1,,1 Trans Mains Exp,1,,,,1 Trans Mtce Mains 1,,,,0 1,, Trans Mtce Meas Rg 1, 1,0,, 0 Dist Oper E&S,,,1, 1,, Dist Exp Mains & Serv,,1,,0,1, Dist Op Meter & House Reg (,1,) (,1,) (,,) Dist Op Customer Install,,,0,,0,0 0 Dist Oper Other,, 1,,00 1,0, Dist Mtce of Mains,,01,,1,0,1 Dist Mtce of Meters&Hou,,0,,00 1,,1 All Other FERC's 0,0, 1,,, Grand Total 1,,,,00 1,, The specific FERC accounts identified in Table CFC- above each have positive variances greater than $00,000 and these accounts collectively represent over 0 percent of the change in Gas Engineering and Operations and Distribution Operations business area expenses between the 01TY and the HTY. Attachment CFC- is a discussion of these FERC accounts. Attachment CFC- provides a view of the unadjusted O&M expenses by FERC and by object account. Q. HAVE ANY ADJUSTMENTS BEEN MADE TO THE DATA PRESENTED AS THE HISTORICAL TEST YEAR (HTY) O&M EXPENSES IN TABLES CFC-1, CFC-, AND CFC-? A. Yes. First, the Company experienced a flood in the second half of 01 which had a significant impact on our assets and operations during September and October 01. The costs associated with the flood above and beyond normal costs of doing business have been removed from the
85 HTY. The amount of this reduction in the HTY is $. million. Second, all expenses associated with the PSIA have been excluded from the amounts presented in Tables CFC-1, CFC-, and CFC-. Third, the Company experienced a failure at the Amoco (also known as Wattenberg) compressor station. This compressor failure caused damage to the building and adjacent equipment which required a one-time O&M expense to investigate and to make repairs. The expenses associated with the compressor failure are considered to be beyond the normal cost of doing business, and therefore, $0. million of O&M expense has been deducted from the HTY in Tables CFC-1, CFC-, and CFC-. Fourth, an increase of $1. million associated with labor reflects the filling of vacancies (vacancy adjustment) that existed during the HTY. Due to the strained budget resulting from restoration efforts following the 01 flood and repairs made to Amoco (Wattenberg), the Company chose to delay filling existing vacancies in order to defer the associated expenses. During the HTY, there were vacancies. 1 of the vacancies are Public Service Gas Engineering and Operations positions, and the remaining 1 vacancies are XES (Xcel Energy Service Company) positions. Attachment CFC- provides a list of the 1 Public Service Gas Engineering and Operations vacancies and the current status of each. As demonstrated by Attachment CFC-, all but one of these positions has been or will be filled by the first and second quarter of 01. The senior associate position that will not be filled is related to an efficiency gain that
86 made the position no longer necessary, as described earlier in my testimony. XES employees are employees that work for more than one operating company; in most cases, this means the employees provide support to more than one operating company. Xcel Energy employs personnel to work for the service company in order to gain efficiencies and standardize the processes across all of Xcel Energy s operating companies. To summarize, the vacancy adjustment of $1. million for the HTY reflects the filling of 0 of the 1 Public Service Gas Engineering and Operations HTY vacancies and 1 XES vacancies that existed during the HTY. Next, the following additional adjustments have also been included. O&M First Set Credits associated with Encoder Receiver Transmitter ( ERT ) meters have been added to the HTY in Tables CFC-1, CFC-, and CFC-. The ERT module on a meter allows the Company to perform automated meter readings as opposed to physical readings of gas usage by individual customers. The standard ERT installed today is incompatible with some early meter sets and therefore a full meter set replacement is required to continue automated meter reading. Meters are pre-capitalized material and because of this, the Gas Utility expenses incurred in labor and transportation for these replacements is offset by an O&M First Set Credit incurred within the Distribution Operations business area. Since these costs over time will net to zero from an overall corporate perspective, the credits have been included.
87 Additionally, the O&M First Set Credits associated with New Business meter sets are included in Tables CFC-1, CFC- and CFC-. As economic conditions improve, more and more new homes are being built and additional new gas meters are set. During the HTY, the Company set an additional,0 meters compared to the 01TY. As with the ERT replacements described above, meters are pre-capitalized material for which the Gas Utility incurs expenses during installation for labor and transportation. However, these replacements are then offset by an O&M First Set Credit in the Distribution Operations business area. Since these costs over time will net to zero from an overall corporate perspective, the credits have been included in Tables CFC-1, CFC-, and CFC-. Finally, the gas use cost credits are included in Tables CFC-1, CFC-, and CFC- along with the expenses. These expenses and credits eventually net to zero similarly to the First Set Credits described above. However, because there is a timing gap that may prevent this from showing net zero during a specific timeframe, we have made the adjustments to net the expenses and credits to essentially zero. Q. HOW DID YOU DETERMINE WHICH EXPENSES RELATED TO THE FLOOD WERE ABOVE AND BEYOND NORMAL COSTS OF DOING BUSINESS? A. Flood costs were tracked with specific work orders to which employees charged their time, materials, and invoices for services. However, not all of the expenses charged to these work orders can be removed from the
88 HTY results. Flood related activities delayed originally planned work that otherwise would have been performed. This means only a portion of the total flood costs are above and beyond the normal course of business. In order to determine the portion of flood expenses above and beyond the normal course of business, expenses including material, overtime, and contractor expenses were analyzed to determine a three year average using 0, 0, and 01 data. Comparing this three year average to the HTY results enabled the Company to determine that $. million needed to be removed from the HTY expenses. Internal labor and transportation costs were not factored in to the normalization as those costs would have been incurred through normal course of business activities. Q. HOW DID YOU DETERMINE THE EXPENSES RELATED TO THE AMOCO (WATTENBERG) COMPRESSOR FAILURE THAT WERE NON-REOCCURRING? A. Non-reoccurring expenses associated with the Amoco (Wattenberg) compressor failure include the contractor costs, professional services costs, and material costs needed for repairs and restoration. The costs also included a one-time forensic investigation of the failure. Internal labor and transportation costs were not factored into the normalization as those costs would have been incurred through normal course of business activities.
89 . O&M Adjustments Related to the MYP Period Q. WHAT ADJUSTMENTS ARE YOU PROPOSING TO THE HTY LEVEL OF O&M FOR THE GAS UTILITY EXPENSES FOR THE MYP PERIOD, 01 01? A. The O&M expenditures included in the MYP period were developed based on the normalized HTY, as previously discussed, adjusted for five areas of known and measurable O&M cost increases: Merit and Benefits; Regulator Station Improvement Project; Enhanced Emergency Response Program (including dispatch); SCADA/Gas Control Monitoring Improvement Program; and Damage Prevention. Merit and Benefits The increases associated with merit increases are described in further detail in the Direct Testimony of Ms. Ruth Lowenthal. The increases associated with benefits are described in the Direct Testimony of Mr. Richard Schrubbe. Regulator Station Improvement Project The increases associated with the Regulator Station Improvement Project will allow the Company to replace certain regulator station equipment, add redundancy to key stations, and place each station on a five-year internal inspection cycle to enhance reliability. Additional
90 information on this program is provided in the Direct Testimony of Company witness Mr. Litteken. Enhanced Emergency Response Program The Enhanced Emergency Response Program will allow the Company to decrease the response time it takes to arrive on-scene during emergency situations. Further details regarding this program are included in the Direct Testimony of Company witness Mr. Litteken. SCADA/Gas Control Monitoring Improvement Program The increase associated with the SCADA/Gas Control Monitoring Improvement Program will allow the Company to install and to maintain additional monitoring points at key locations throughout the pipeline system. These monitoring points provide greater visibility to real time operational data allowing controllers to make better operational decisions, proactively prevent an unplanned outage or pressure event, and monitor system data to enhance safety for crews and the public in emergency situations. Additional information on this program is provided in the Direct Testimony of Company witness Mr. Litteken. Damage Prevention Deferral As described in Mr. Litteken s Direct Testimony, expenses associated with the damage prevention locating activities for our pipelines are variable and difficult to predict. A proposed deferral mechanism related to these costs is explained in more detail within the Direct Testimony of Company witness Ms. Blair.
91 Q. DOES THE NORMALIZED HTY O&M ADJUSTED FOR KNOWN AND MEASURABLE CHANGES REFLECT A REASONABLE LEVEL OF COSTS LIKELY TO BE INCURRED IN 01 THROUGH 01? A. Yes. The Gas Utility O&M expenses presented in this case provide a very good indicator of expected expense levels. We normalized the base HTY costs to exclude the costs required to address the flooding that occurred in September 01 and the Amoco (Wattenberg) compressor failure, as these costs are not expected to be reoccurring annual expenses. Additionally, the Company has not included expenses for contingencies or expenses related to additional regulatory requirements that are expected to evolve over time. Severe weather and significant system events can also cause upward pressure on O&M spending. However, only the known and measurable increases explained above have been included in the MYP. The Company s level of O&M included in the MYP period strikes a good balance between providing a high level of service and controlling costs for the benefit of customers. Q. PLEASE EXPLAIN HOW COST EFFICIENCIES AND PRODUCTIVITY CHANGES HAVE BEEN INCORPORATED INTO THE TEST YEARS O&M. A. Improving operating productivity has always been a focus of the Company. We routinely evaluate processes and technologies to identify more efficient ways of doing business. In 01, Public Service has made 0
92 efficiency gains in four areas: Gas Construction, Gas Operations, Distribution Design, and Contract Management. In Gas Construction, Public Service has revised its processes and procedures to streamline the process of siting and installation of customer meters. Meter set requirements on gas applications were standardized in order to ensure customers have a clear understanding of the requirements regarding clearances, location, and protection of meter sets. Public Service also updated the meter set information that is provided to field technicians. These changes have resulted in reduced trips by field technicians to customer locations. Further, Gas Construction piloted a new process related to the design and construction of new gas services in high volume areas. By centralizing the design and construction functions, there have been improved efficiencies in work planning, scheduling, and material logistics. Additionally, these changes have led to improving the customer s overall experience and reducing design and construction timelines. Gas Operations has also reorganized some of its crews to allow for better and more efficient management of gas leaks. By reducing the size of the crews addressing leaks at one service center, additional leak locations were able to be addressed in a similar timeframe. This gives company crews more time to address other work and prevented the use of additional contract labor. Further, Distribution Design implemented new design tools and software that is expected to further reduce recurring trips into the field. 1
93 Distribution Design also established a basic minimum requirements standard for sketches issued by design to construction, which is expected to streamline the construction process and decrease construction delays. Finally, Contract Management implemented a new units-based contract for gas construction and meter replacement activities. This improvement is expected to produce an estimated annual savings of $. million per year over the five-year term of the contract. While the contracts were previously based on time and equipment rates, the new units based contracts are a lower cost per unit when compared to the previous time and equipment contracts for the same activity. Q. ARE THERE ANY OTHER BUSINESS AREA COSTS YOU ARE SPONSORING OTHER THAN THOSE PREVIOUSLY DISCUSSED? A. Yes Energy Supply and Transmission. Q. ARE THERE ANY ADJUSTMENTS MADE TO THE HTY LEVEL OF O&M EXPENSES FOR ENERGY SUPPLY OR TRANSMISSION IN THE MYP? A. No. B. CAPITAL COSTS Q. HOW ARE CAPITAL EXPENDITURES BUDGETED FOR THE COMPANY S GAS UTILITY? A. There is a well-defined process for identifying, ranking, and budgeting gas distribution, transmission, processing, and gathering and storage projects. The key steps necessary to ensure the preparation of a comprehensive capital budget are summarized below.
94 Step 1 - Engineering and operations personnel identify potential problems and solutions. Step - Each problem (risk) and solution is reviewed for accuracy, completeness, and reasonableness. Step - As each risk and solution is considered, it is scored based on certain criteria, such as the likelihood of occurring, and the consequences of not addressing it. Step - All potential solutions are ranked or prioritized. Step - After the ranking is completed, business leadership reviews the list, the level of risk associated with the various projects, as well as overall capital levels based on financial criteria. Step - Projects chosen to be funded are assigned a capital project number based on the type of work. These capital projects are classified as either specific or routine. Step - Capital project numbers for large pools of small projects (e.g., main installations, main renewals, etc.) are automatically tied to closing patterns based on the attributes of the work. For larger individual projects, in-service dates are assigned. Project managers then forecast expenditures based on the particulars of a project and its projected in-service date. Step - All capital projects that are included are reviewed and approved, both at the business area level and at the corporate level.
95 Step - Work is deployed during the year. The determination of the estimated in-service date of each large project and the closing patterns associated with different types of work pools (noted in Step above) determine the date the project goes from Construction Work In Progress ( CWIP ) to Plant-In-Service on the Company s books and becomes a plant addition. The process of moving projects from CWIP to Plant-In-Service is described in more detail by Company witness Ms. Lisa Perkett. Ms. Perkett discusses this process as it relates to pulling together the Company s capital budget across all business areas at the corporate level. Since I am representing the Gas Utility Operations business area, the focus of my testimony is on how the capital projects are developed and ultimately become gas distribution, transmission, processing, gathering, and storage assets. Q. IN SUMMARIZING THE NINE STEPS ABOVE, YOU REFER TO RISKS, SOLUTIONS, MITIGATIONS, AND PROJECTS. CAN YOU EXPLAIN WHAT YOU MEAN BY THESE TERMS IN THE CONTEXT OF DEVELOPING A CAPITAL BUDGET? A. Yes. Risks are potential detrimental impacts or threats to safety, the quality/reliability of our service, environmental quality, our ability to meet our legal obligations, or our financial standing. These identified risks drive the need for initiatives to address the risks. These initiatives, in turn, often require capital expenditures. In the capital budgeting process, potential solutions or mitigations are essentially projects; i.e., work to be
96 performed that will mitigate a certain risk, or set of risks. These projects are the focus of the capital budget process. Projects are evaluated against each other based on their costs, how effectively they address certain risks, and how critical the risks are. Q. PLEASE EXPLAIN HOW THE PIPELINE INTEGRITY PROJECTS FOR WHICH THE COMPANY RECOVERS ITS COSTS THROUGH THE PSIA ARE FUNDED THROUGH THE EXISTING CAPITAL BUDGETING PROCESS. A. Pipeline integrity projects are funded through the normal capital funding process. Integrity assessments and related projects are essential to the overall safety and integrity of the system. Therefore, the work associated with these assessments is considered non-discretionary and essentially move to the top of the project list. The nature of these integrity projects makes it difficult to predict exact expenditures. This is because we often times may find something very different from what was anticipated prior to the completion of an assessment on a pipeline. We may find there are gaps within our current asset information records or the assessment results may indicate that the condition of an asset may require significantly more repairs than anticipated, or may even require replacement. Q. ARE THERE ADDITIONAL ASPECTS TO CONSIDER WITH RESPECT TO INTEGRITY PROJECTS AND THE IMPACT OF THE PSIA? A. Yes. Many projects require significant planning if they are to be executed in an efficient and effective manner. This is true of many of our gas
97 projects as well. This planning includes not only the system design and planning effort, but community work, permitting, scheduling with other efforts, etc. Therefore, many of these projects must start well in advance, generally over a year in advance and sometimes even longer. One of the benefits of the current PSIA mechanism is a degree of certainty in project planning. We can begin other key or critical work on the system knowing that if we run into major integrity issues, we have some certainty about our ability to execute without concern about delaying the project until a source of funding can be determined. We do not have to allocate capital funds earmarked for other projects to perform this vital integrity work. Q. WHAT IS THE APPROVED CAPITAL EXPENDITURES BUDGET FOR GAS UTILITY OPERATIONS BUSINESS AREAS AND HOW DOES THAT BUDGET RELATE TO THE PLANT ADDITIONS FOR THE MYP PERIOD APPLICABLE TO THIS RATE CASE? A. The approved Gas Utility operations capital expenditures budget is $.0 million in 01, $. million in 01, and $1. million in 01, which includes installation and removal expenditures. Excluding budgeted PSIA expenditures; the budgets are $. million, $. million, and $. million respectively as shown in Table CFC-, below. This amount does not include Allowance for Funds Used During Construction ( AFUDC ), which is a component of plant additions. Each budgeted project has an associated in-service date or closing pattern as described earlier, which determines whether the capital expenditures are converted
98 into plant additions for a given year. Plant additions can result from construction projects started in previous years with a future year in-service date or projects started and completed in that same year and placed in service in the same year. Q. ARE THERE ANY ADJUSTMENTS TO PLANT IN SERVICE RELATED TO THE AMOCO (WATTENBERG) INCIDENT? A. Yes, currently this facility is not being operated and the book value of that asset was moved into a Plant Held for Future Use account by the Capital Asset Accounting department. Therefore, an adjustment to plant in service has been incorporated into the revenue requirement calculations to adjust for this event. For further details, see Ms. Blair s Direct Testimony. Q. PLEASE DESCRIBE THE GAS UTILITY OPERATIONS CAPITAL EXPENDITURES (EXCLUDING AFUDC) FOR THE MYP PERIOD BASED ON TYPE OF WORK. A. In Table CFC- below, I have separated the capital expenditures into three sections. In the first section, I list the capital expenditures by type of work, such as new service, capacity, asset health, etc. However, I have removed a couple of major projects from that section and listed them separately in the second section of the table. The third section identifies the components of the proposed PSIA projects. These pipeline integrity programs or projects represent over half ( percent) of the overall gas capital budget for 01-01, or $. million. Since these PSIA initiatives have already been addressed in more detail previously, this section will focus on the remaining
99 $. million in capital expenditures routine work by type and major projects listed in the first section of Table CFC- below. Table CFC- Type of Work Total Percent of Total New Service $0. $. $. $1. 1.% Capacity $0. $0. $0. $ % Asset Health $. $.1 $. $..0% Mandates $1.0 $1. $. $..% HP Gas $0.0 $1. $. $..% Equip Purchase $. $.1 $.0 $..% Fleet $. $. $. $1.0 1.% CIAC ($.) ($.) ($.) ($.) -.% Other $1. $1. $. $..% Subtotal $. $.1 $0. $..% Major Projects Front Range Pipeline Reinf-DeerCrk West $1. $. $.0 $1. 1.% Downtown Denver Reinforcement $0.0 $0.0 $.0 $.0 0.% Subtotal $1. $. $.0 $1. 1.% PSIA Projects AMRP $.0 $.0 $.0 $.0 1.% CAB gas service replacement project $.1 $0.0 $0.0 $.1 1.% West Main Replacement $. $.0 $0. $0..% DIMP $.0 $. $. $.1 1.% TIMP $. $. $. $1. 1.1% Subtotal $1. $1.1 $. $..% $.0 $. $1. $.1 0.0% Q. PLEASE DESCRIBE THE GAS CAPITAL EXPENDITURES CATEGORIZED AS ROUTINE WORK LISTED IN TABLE CFC-, AND EXPLAIN THE DRIVERS FOR EACH TYPE OF WORK. A. Table CFC- lists budgeted capital expenditures by work type. Each type of work represents a unique group of like projects. The routine work projects in section one of Table CFC- represent core, day-to-day gas utility work and include costs associated with new customers, increased capacity requirements, reconstruction or relocation of existing
100 facilities, equipment purchases (such as for meters or regulators), and purchases of fleet vehicles. Each of these categories is addressed below. New Service: New service projects comprise approximately $1. million, or 1. percent, of the capital expenditures. New meter sets are projected to average approximately 1,000 meters per year between 01 and 01. This level of forecasted new meter sets remains well below pre-recession levels, which ranged from,000 0,000 meters per year. Projects required to support this growth include the installation of new mains and service laterals. Capacity: Pipeline and regulator station capacity projects comprise approximately $1.1 million, or 0.1 percent, of the forecasted capital expenditures. These projects include infrastructure work related to increasing gas main and regulator station (expanded or new installations) capacity to mitigate low-pressure issues. This type of work is driven by increased load, either from existing customers or new customers. Asset Health: Projects classified as Asset Health are related to infrastructure that is experiencing equipment failure or leaks that require repair in accordance with the Xcel Energy s Pipeline and Compliance Manual. Some of these projects may have a resulting increase in O&M expenses. For example, a main renewal is a capital expenditure, but the air testing and tying over of existing service lines is an O&M expense. The Asset Health capital expenditures total $. million, or.0 percent, of the budgets. Replacing gas main for pipe
101 types other than cast iron, black or bare steel, or PVC is included in this category, as is the renewal of service lines. Replacement projects performed under the AMRP Replacement programs are not included in this category, but are separately categorized as part of PSIA projects. Mandates: Mandated projects are required to meet federal, state, or local requirements. This category includes relocating facilities that are in direct conflict with street expansions within public rights-of-way and safety-related work required by a governing authority. These projects are normally identified during meetings between Gas Planning and the local operating areas. Mandated projects comprise approximately $. million, or. percent, of the capital budgets. An example of a government-mandated project is the relocation of facilities for the RTD FasTracks Commuter Light Rail Train program. These projects are monitored monthly, and adjustments are made based on customer requests. HP Gas: High Pressure ( HP ) Gas projects are related to the Company s gas transmission, processing, gathering, and storage assets. HP Gas comprises approximately $. million, or. percent, of the budgeted capital expenditures. These amounts exclude capital expenditures related to TIMP, the West Main Replacement, and the Deer Creek Pipeline Reinforcement, which are separately identified. Examples of projects under this designation include transmission pipeline relocation, installation of a new transmission regulator station, equipment 0
102 replacement at a storage field, installation of a compressor station control system, or installation of new gas processing facilities. Equipment: Equipment purchases total $. million and constitutes. percent of the capital expenditure budgets. While equipment purchases are classified as a type of work, they are routine purchases of gas meters and regulators. The main driver of the equipment budget is meter purchases. For 01-01, percent of all meter purchases are designated for replacements due to normal wear and tear, or potentially defective meters categorized as Failed Lots and Do Not Register. These budgeted expenditures do not include the costs related to the Inside Meter Replacement Project for which the Company is requesting Commission approval in this rate case, as discussed in detail by Company witness Mr. Litteken. The balance of percent is for meters and regulators designated for new customer growth. Due to the economic downturn, these percentages are approximately reversed from six years ago, when 0,000 new meters were being set and 1,000 meters were being replaced. Fleet: The fleet budget accounts for approximately $1.0 million of the forecasted capital expenditures, or 1. percent. Each year we evaluate replacing those fleet units that have become the most unreliable and the most costly to maintain due to normal wear and tear and general deterioration over time as these fleet units are utilized extensively in day to day operations. 1
103 Other: Funding is needed for other requirements outside of the actual construction of gas facilities. Those requirements are as follows: Right-of-Way Capital expenditures associated with obtaining rights-of-way and easements are planned at $. million for ERT module replacements the budget accounts for $. million of the forecasted capital expenditures to replace the ERT modules that have reached their expected life. These modules provide the automated mechanism to read gas meters remotely. 1 1 Other capital requirements capital expenditures associated with franchise costs and special tools and equipment are estimated at $0. million Q. HOW ARE ROUTINE BUDGETS DEVELOPED? A. The budget for new gas service routine work is developed using a costper-meter methodology. This process begins with forecasting the number of new meter sets for each local operating area. Inputs and assumptions regarding inflation factors are used to determine the assumed cost increase or decrease to the components that constitute the new business costs. These factors (labor, non-labor, contractor, materials, equipment and fleet inflation rates, bargaining labor increases, and corporate overhead rates) reflect both corporate and operating company rates. Historical data is used to determine the major drivers or components that constitute new business costs. These components are labor (both company and contracted), labor loadings, material (excluding meters and
104 regulators), equipment, transportation, overheads, and other costs. Using these components, we then develop a cost-per-meter component matrix for each local operating area. This matrix allows us to apply the related inflation factors to the specific components that make up the overall cost per meter. We also use this data to analyze the various components of the variances between forecasted and actual costs. After the preliminary forecast has been determined, the data is reviewed with management in each local operating area to determine if there will be substantial changes to the operations (e.g., crew mix, major projects, and labor issues). Adjustments are made based on the outcome of these reviews. The budget for reconstruction routine projects is based on the averages of historical values escalated by the corporate inflation rate (approximately percent per year). This total budget is then allocated to each service area using the average historical ratio during the past five years. The allocation is adjusted to ensure that unique, one-time projects in a service area do not impact the calculation of the average five-year historical expenditures. Work completed as part of the AMRP and the integrity management programs do not factor into this calculation. Routine project requests, such as for new business growth, reinforcements, or rebuilds include a five-year expenditure history and estimated in-service date. This routine grouping of projects serves to allocate funding for performing core business functions, such as
105 connecting new customers, reconstructing facilities, and purchasing new meters, regulators, and fleet. Q. PLEASE DESCRIBE WHAT IS INCLUDED IN THE MAJOR PROJECTS CATEGORY OF TABLE CFC- ABOVE. A. Two major projects make up $1. million, or 1. percent, of the capital expenditures. The Deer Creek Pipeline Reinforcement project is a $1. million project and makes up 1. percent of the budget. This project addresses increasing capacity needs due to growth in Evergreen, Central City, Black Hawk, and other mountain areas. The Downtown Denver Reinforcement project incurs $.0 million of project costs during this time period, or 0. percent, of the budget. This pipeline upgrade project addresses the need for increased capacity in the downtown Denver area. The initial spend in 01 initiates the permitting and engineering process, the majority of the spend on this project resides outside the timeframe. Q. WHAT WERE THE KEY DRIVERS OF THE BUSINESS AREA S CAPITAL ADDITIONS BETWEEN JULY-DECEMBER 01? A. First, the primary driver of capital additions during this timeframe was the final completion and placing in-service of the -mile Cherokee Natural Gas Pipeline. This high-pressure steel pipeline begins at a new Fort Lupton natural gas metering facility and routes through an existing urban corridor to Xcel Energy's Cherokee Generating Station, just north of downtown Denver. The completion of this project was an integral step
106 within the overall Clean Air-Clean Jobs plan. This project accounts for almost half of the capital additions during this timeframe. Second, a number of programs within the PSIA contributed another 0 percent of the capital additions between July-December 01. The main drivers within the PSIA were the West Main Transmission Line Replacement Project, AMRP, the CAB Gas Service Replacement Program, and pipeline assessments within the TIMP. Finally, the balance of capital additions is divided among various routine work types performed in the course of gas utility work. One specific example is the main relocation work required from the RTD FasTracks initiative that resulted in $. million in capital additions, or percent of capital additions between July-December 01. Q. PLEASE PROVIDE AN OVERVIEW OF THE GAS UTILITY S KEY CAPITAL ADDITIONS INCLUDED IN THE MYP? A. The nine routine work types listed in the top section of Table CFC-, previously addressed in my testimony, represent the capital expenditures associated with core, day-to-day, gas utility work and include the costs associated with adding new customers, reconstruction or relocation of existing facilities, equipment purchases (such as for meters or regulators) and purchases of fleet vehicles. These expenditures represent nearly half of the capital additions expected during 01, 01, and 01. The remaining portion of capital additions, roughly 0 percent, is attributable to the integrity work performed as part of the PSIA. The key drivers of PSIA capital additions during are the West Main Transmission Line
107 Replacement Project, AMRP, the Programmatic Risk-Based Pipe Replacement Program, and TIMP initiatives focused on transmission pipeline assessments and MAOP validation. Please see Attachment CFC-1 Project Capital Additions: 01 to 01 for the capital additions included in the MYP. Q. ARE THE CAPITAL ADDITIONS PRESENTED IN ATTACHMENT DAB- 1, AND INCLUDED IN ATTACHMENT LHP-1, SPONSORED BY COMPANY WITNESS MS. LISA PERKETT, REASONABLY REFLECTIVE OF WHAT YOU EXPECT PUBLIC SERVICE TO PLACE IN SERVICE DURING THE MYP? A. Yes. Q. PLEASE EXPLAIN THE PROCESS YOU FOLLOW TO MANAGE CAPITAL COSTS AFTER THE CAPITAL BUDGET IS DEVELOPED. A. The project controls group within the Project Delivery organization is tasked with monitoring all distribution capital dollars to ensure that authorized projects align with the established budget. Detailed monthly reports are produced that compare actual capital expenditures to budgeted levels for programs (routine) and non-routine projects. I meet monthly with this group and key stakeholders within the organization to review program and nonroutine project capital expenditures and variances. Adjustments and corrective measures are implemented as needed.
108 Q. WHAT INCENTIVES ARE IN PLACE TO PROMOTE THE ACCURACY OF THE CAPITAL BUDGET? A. Management employees that have job responsibilities with a direct impact to capital budget expenditures (e.g. Engineering, Project Delivery) have specific budgetary goals that are incorporated into their performance evaluations. Performance is measured on a monthly basis to ensure adherence to these goals and to provide for action plan development to address variances. Performance Management Plans for all Directors and Managers include a metric associated with their capital budgets. This metric is aimed at developing accurate budgets and managing to the budgeted levels. The scorecard for Public Service also contains a Key Performance Indicator associated with capital budget accuracy. Q. HAVE YOU TAKEN ADDITIONAL STEPS TO ENSURE THE ACCURACY OF THE CAPITAL BUDGETS? A. Yes. I have explained in detail how we establish a rigorous budgeting process that identifies the optimal mix of projects and expenditures for a given year. The up-front inputs into this process need to be accurate to minimize variances between budgeted and actual expenditures. In other words, good up-front planning improves our success in the field. Over the past couple years, we have improved the planning, as well as the accuracy of, our initial cost estimates for projects. We have also begun implementing a more structured and disciplined project management process for larger and/or more complex programs of work. This
109 improvement includes more up-front planning after they have been approved in the capital budgets. The timelines are more accurate, overheads (engineering) are more accurate, and we are less likely to have unexpected occurrences in the field once the project is deployed. Once a project has been deployed and is under way, the project manager meets regularly with the key staff (i.e., siting and land rights, sourcing, construction/operations, etc.). Issues and concerns are identified and solutions developed. The overall goal is to achieve safe and timely completion of the project at no more than the budgeted cost. The practical payoff is that our budget estimates have a higher degree of accuracy. Q. ARE THERE ANY OTHER REASONS THAT YOUR UP-FRONT ESTIMATES ARE ACCURATE? A. Yes. We use various thresholds to determine the reviews and approvals required when the projected costs of projects vary from their original budgets. A monthly process is in place to monitor, update, and correct the budgets and forecasts as the projects progress. Q. IN YOUR OPINION, ARE THE GAS PLANT ADDITIONS SET FORTH IN ATTACHMENT LHP-1 SPONSORED BY MS. PERKETT REFLECTIVE OF WHAT IS EXPECTED TO BE PLACED INTO SERVICE DURING 01-01? A. Yes. Those gas plant additions do reflect what is expected to be placed into service during
110 C. OTHER ADJUSTMENTS Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR DIRECT TESTIMONY? A. I explain other adjustments made to the HTY, specifically with respect to revenues related to Natural Gas Liquids. I also explain the revenues related to the Cherokee Generating facilities Natural Gas Liquids Revenues Q. WHAT WERE THE COMPANY S ACTUAL REVENUES ASSOCIATED WITH THE SALE OF NATURAL GAS LIQUIDS OUT OF THE RIFLE GAS PLANT ( RIFLE ), THE BAXTER GAS PLANT ( BAXTER ), AND THE ROUNDUP STORAGE FACILTY ( ROUNDUP ) DURING THE HTY? A. As described in Attachment CFC-, Page 1 of, total revenues from the sale of, gallons of natural gas liquids from Rifle, Baxter, and Roundup totaled $1,, during the HTY. The average price per gallon during the HTY was $ Q DID THE COMPANY MAKE ANY ADJUSTMENTS TO THE HTY RELATED TO THE NATURAL GAS LIQUIDS REVENUES? 1 0 A. Yes. In the fourth quarter of 01, after the end of the HTY, the Company reduced the price per gallon for natural gas liquids from $1. to $0.. 1 The Company s th quarter 01 liquids revenues are contained in Attachment CFC-, Page of. As demonstrated by Attachment CFC-, there has been a significant drop in natural gas liquid prices from the end
111 of the HTY, which is June 0, 01. The Company is proposing to adjust the HTY natural gas liquid revenues for the 01 Test Year, the 01 Test Year, and the 01 Test Year to reflect this known and measurable change. Q. DOES THE COMPANY ANTICIPATE A REDUCTION IN REVENUE ASSOCIATED WITH NATURAL GAS LIQUID SALES IN THE MYP PERIOD? A. Yes. The Company anticipates that revenues associated with the sale of natural gas liquids from Rifle, Baxter, and Roundup will continue to decline over the MYP period. The decline is caused by the anticipated changes in gas supplies received into Rifle, coupled with an expected reduction in the market price of natural gas liquids at all three locations over the MYP period. Q. PLEASE DISCUSS CHANGES IN GAS SUPPLIES RECEIVED AT RIFLE, WHICH IS LOCATED IN WESTERN COLORADO. A. To serve gas loads in various mountain communities, the Company purchases supplies from several points of interconnection into our western 1 system. One supply source is from western Colorado wellhead production, which is delivered into Rifle. Public Service then extracts and sells the associated liquid hydrocarbons. The other source of gas received at Rifle is from CIG, which is pipeline-quality gas. Gas received from CIG has a two-fold benefit over the natural gas liquids; it does not 0
112 require processing, and Company can utilize its No-Notice storage service to more effectively support our system operations in this area. Q. CAN RELIANCE ON NATURAL GAS LIQUIDS FROM RIFLE BE ELIMINATED? A. No. Public Service continues to work with CIG with the goal of accessing quantities of pipeline-quality gas adequate for the needs of mountain communities that are served by these western supplies. Supplies received from CIG pipeline are sufficient to serve summer loads, but it will be a number of years before CIG can deliver quantities necessary for reliable winter deliverability. Until that occurs, the Company must continue receiving supplemental winter supplies from western wellhead production delivered into Rifle. The Company has entered into an agreement with Rocky Mountain Natural Gas, as partner in the operation of Rifle, with each party purchasing a baseload quantity of,000 Dth/day, which is the minimum daily volume considered necessary to support effective plant operations. Purchases will be made for the period of November through March, with zero flows through Rifle from April through October period. This operational agreement ends March 1, 01. This baseload volume of,000 Dth/day from November through March represents 0,000 gallons of natural gas liquids per year, which is a reduction of approximately 00,000 gallons recovered during the HTY. 1
113 Q. PLEASE EXPLAIN WHY YOU EXPECT THE PRICE PER GALLON OF NATURAL GAS LIQUIDS TO CONTINUE TO DECREASE DURING THE MYP PERIOD? A. As I discussed earlier and as reflected in the HTY adjustment, the actual average price per gallon for natural gas liquids received in the 01 fourth quarter was $./gallon, which was a decrease from $1./gallon. Additionally, the February, 01 futures NYMEX price shows a further reduction in the average annual price per gallon, as depicted in Attachment CFC-. The average annual prices/gallon in the 01, 01, and 01 Test Years are expected to be $0., $0.0, and $0.1, respectively. Q. PLEASE SUMMARIZE THE LIQUID REVENUES DURING THE MYP. A. The decline in revenues from the sale of liquids from Rifle, Baxter, and Roundup is caused by anticipated changes in gas supplies received into Rifle, coupled with a reduction in the market price of liquids at all three locations as reflected in the February, 01 NYMEX futures price. A reduction in the quantity of gas at Rifle will reduce the quantity of liquids extracted and sold by Public Service by an estimated 00,000 gallons annually. Additionally, the average NYMEX Natural Gas Liquids futures pricing reflects a significant decrease in the value of liquids. Applying futures pricing to the anticipated reduced quantity of liquids extracted through Rifle, plus Baxter and Roundup liquids, which are expected to continue producing at historical levels, the total revenues recovered from
114 liquids sales are expected to fall to $, in 01, with slight recovery due to price increases of $, in 01 and $00, in 01.. Revenues Related to Cherokee Q. PLEASE DISCUSS REVENUES ASSOCIATED WITH THE CHEROKEE GENERATING FACILITIES. A. The Company placed in-service new pipeline facilities in October 01 which provide gas deliveries to the Cherokee generation facilities as provided for in the Clean Air Clean Jobs Act Emissions Reduction Plan under CPUC Proceeding No. M-E. The Company has included revenues from the Cherokee generating facility in the 01, 01, and 01 MYP Test Years
115 V. SUMMARY AND CONCLUSION Q. PLEASE SUMMARIZE YOUR DIRECT TESTIMONY IN THIS PROCEEDING. A. Public Service has and continues to meet our mission to provide safe and reliable service to our customers. With the approval of the PSIA in the 0 Rate Case, the Company has made great strides in enhancing the safety and reliability of the our gas system, such as removing and replacing cast iron pipe from our system as part of AMRP. However, we cannot become complacent; work still needs to be done. To continue its mission to provide safe and reliable service, Public Service has effectuated a plan to focus the Gas Utility on operating in a proactive and predictive manner. A significant part of that plan is Public Service s proposals for a number of non-psia programs and the acceleration of certain PSIA projects. These programs and projects will not only allow Public Service to focus on operating in a proactive and predictive manner but will also enhance the safety and reliability of our gas system. A proactive and predictive gas utility cannot afford to be complacent. As such, Public Service is also requesting an extension of the PSIA for a period of no less than five years, or until December 1, 00. The PSIA is an important component of the Company s long-term plan to provide safe and reliable service and our efforts operate our gas system in a proactive and predictive manner.
116 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes.
117 Attachment A Statement of Qualifications Cheryl F. Campbell I received a Bachelor of Science degree in Chemical Engineering and a Bachelor of Science degree in Business Administration from the University of Colorado in 1. I received a Master of Science degree in Finance from the University of Colorado in 10. In August 01, I was appointed by the United States Secretary of Transportation to the Department of Transportation s Technical Pipeline Safety Standards Committee also known as the Gas Pipeline Advisory Committee. I was hired by Colorado Interstate Gas ( CIG ) as an Associate Engineer in the Design & Evaluation Department in 1, progressing to department Manager during my tenure in the Department. My experience in Design & Evaluation included transmission system design, economic evaluation, gas balance planning, and both short and long term planning studies. I transferred to Supply Management in 10. In this role I was responsible for managing CIG s system supply contracts to ensure adequate purchases to meet contractual obligations. I was also involved in storage and supply planning to meet CIG s market obligations. In late 1, I began working for CIG Merchant Division, the unbundled merchant arm, and in late 1, I began working for Coastal Field Services. My experience in these areas includes gas scheduling, allocations, transportation contract management, nominations, imbalance management, fullservice agency for small customers, Operational Balancing Agreement
118 management, contract negotiation, budgeting and planning studies. I was promoted to Director of Volume Management for Coastal Field Services in 1. In late January of 001, coincidental with the close of the Coastal/El Paso merger, I joined the Rates Department as Manager of Rate Design for the El Paso Western Pipeline Group. My responsibilities included the preparation of cost allocation and rate design studies for general rate filings and certificate applications with the Federal Energy Regulatory Commission. In addition, I was also responsible for other economic studies and special projects assigned to the Rates Department. In 00, I took a position as Vice President of Marketing for a small computer firm based in Dallas, TX. My responsibilities in the role included developing and implementing a marketing and advertising presence for a small computer software company and developing an Energy Services sister company to the main software company. In 00, I accepted a position with Xcel Energy as Director of Gas Asset Strategy. In this role, my responsibilities included developing and implementing decision-making and policy-setting processes for engineering, construction, operations, maintenance and retirement (lifecycle) of Xcel s gas delivery assets. We also balanced operational and financial performance with risk to develop strategic direction and policy. In April 00, I accepted the role of General Manager, Gas System Design for Public Service Company of Colorado. My responsibilities include strategic leadership in the areas of gas systems engineering, gas control, gas marketing and transportation, operations and maintenance for the high pressure gas transmission
119 pipelines and compressor stations, underground storage operations, and various support functions. In January 00, I was promoted to Vice President, Gas System Design, Operations and Maintenance for Public Service Company of Colorado. In 00, Gas Emergency Response and Repair was transferred to my area. As a result of a corporate wide reorganization, I was promoted in September 0 to my current position of Vice President, Gas for Xcel Energy Services Inc. ( XES ) the service company subsidiary of Xcel Energy, Inc. ( Xcel Energy ), a registered holding company. In this capacity, I am responsible for all of Xcel Energy s regulated natural gas utilities including Public Service Company of Colorado, Northern States Power Company, a Minnesota company, and Northern States Power Company, a Wisconsin company. I previously have sponsored testimony in CIG s rate proceedings before the Federal Energy Regulatory Commission in Proceeding Nos. RP0- and RP01-0. I also have sponsored direct and rebuttal testimony in Public Service s rate cases before the Colorado Public Utilities Commission in Proceeding Nos. 0S- G, 0S-G, AL-G, and 1AL-1G.
120 Attachment CFC-1 Page 1 of 1 W y o m i n g N e b r a s k a Steamboat Springs Rollins Pass Denver Highlands Ranch U t a h Grand Junction Pueblo K a n s a San Luis Valley San Juan Basin r i z o n a N e w M e x i c o O k l a h o m a $ 0 County City Xcel Energy Gas Service Area Xcel Energy Gas Transmission Pipeline Miles
121 Attachment CFC- 1 of 1 PSCo Gas Utilities OSHA Recordable Injury Count Journey to Zero, Xcel s safety program, was implemented in 00 1 Number of OSHA Recordable Injuries
122 Attachment CFC- 1 of 1 Damages per 1,000 Locates - PSCo Approximately a % reduction in Damages per 1,000 Locates from 00 to Improving Performance * Damages per 1,000 Locates include both gas and electric utilities 1
123 AGA s Commitment to Enhancing Safety: February 01 Update AGA and its members are dedicated to the continued enhancement of pipeline safety. As such, we are committed to proactively collaborating with public officials, emergency responders, excavators, consumers, safety advocates and members of the public to continue to improve the industry s longstanding record of providing natural gas service safely and effectively to 1 million Americans. AGA and its members support the development of reasonable regulations to implement new federal legislation as well as the National Transportation Safety Board safety recommendations. Below are voluntary actions that are being addressed by AGA or individual operators to help ensure the safe and reliable operation of the nation s. million miles of pipeline which span all 0 states representing diverse regions and operating conditions. In addressing these actions, AGA and its individual operators recognize the significant role that their state regulators or governing body will play in supporting and funding these actions. It is the consensus of AGA members that the actions listed below enhance safety and gas utility operations when implemented as an integral part of each operator s system specific safety actions. However, both the need to implement and the timing of any implementation of these actions will vary with each operator. Each operator serves a unique and defined geographic area and their system infrastructures vary widely based on a multitude of factors, including facility condition, past engineering practices and materials. Each operator will need to evaluate the actions in light of system variables, the operator s independent integrity assessment, risk analysis and mitigation strategy and what has been deemed reasonable and prudent by their state regulators. It is recognized that not all of these recommendations will be applicable to all operators due to the unique set of circumstances that are attendant to their specific systems. Building Pipelines for Safety Construction Expand requirements of the Operator Qualification (OQ) rule to include new construction of distribution and transmission pipelines. Review established oversight procedures associated with pipeline construction to ensure adequacy and confirm that operator construction practices and procedures are followed. Emergency Shutoff Valves Support the use of a risk based approach to the installation of automatic and/or remote control sectionalizing block valves where economically, technically and operationally feasible on transmission lines that are being newly constructed or entirely replaced. Develop guidelines for consideration of the use of automatic and/or remote control sectionalizing block valves on transmission lines that are already in service. Work collaboratively with appropriate regulatory agencies and policy makers to develop these criteria. Expand the use of excess flow valves to new and fully replaced branch services, small multi-family facilities, and small commercial facilities where economically, technically and operationally feasible. Operating Pipelines Safely Integrity Management Continue to advance integrity management programs and principles to mitigate system specific risks. This includes operational activities as well as the repair, replacement or rehabilitation of pipelines and associated facilities where it will most improve safety and reliability. Collaborate with stakeholders to develop and promote effective cost-recovery mechanisms to support pipeline assessment, repair, rehabilitation, and replacement programs. Develop industry guidelines for data management to advance data quality and knowledge related to pipeline integrity. Support development of processes and guidelines that enable the tracking and traceability of new pipeline components. Excavation Damage Prevention Support strong enforcement of the Call Before You Dig program through state damage prevention laws. Improve the level of engagement between the operator and excavators working in the immediate vicinity of the operator s pipelines. Enhancing Pipeline Safety Safety Knowledge Sharing Review programs currently utilized for the sharing of safety information. Identify and implement models that will enhance safety knowledge exchange among operators, contractors, government and the public. Stakeholder Engagement and Emergency Response Evaluate methods to more effectively communicate with public officials, excavators, consumers, safety advocates and members of the public about the presence of pipelines. Implement tested and proven communication methods to enhance those communications. Partner with emergency responders to share appropriate information and improve emergency response coordination. Pipeline Planning Engagement Work with a coalition of Pipelines and Informed Planning Alliance (PIPA) Guidance stakeholders to increase awareness of risk based land use options and adopt existing PIPA recommended best practices. Advancing Technology Development Increase investment, continue participation, and support research, development and deployment of technologies to improve safety. Evaluate and appropriately implement new technological advances.
124 Gas Utility Industry Actions To Be Implemented Target Dates * 1. Confirm the established MAOP of transmission pipelines Note: Confirmation of established MAOP utilizes the guidance document developed by AGA, Industry Guidance on Records Review for Re-affirming Transmission Pipeline MAOPs, October 0.. Review and revise as necessary established construction procedures to provide for appropriate (riskbased) oversight of contractor installed pipeline facilities. Construction oversight document released /1.. Implement applicable portions of AGA s technical guidance documents: 1) Oversight of new construction tasks to ensure quality; ) Ways to improve engagement between operators & excavators a. Under DIMP, evaluate risk associated with trenchless pipeline techniques and implement initiatives to mitigate risks On an aggregate basis of AGA member companies, complete > 0% of class & locations + class 1& HCAs: //1 Remaining class & + 1& HCAs, based on PHMSA guidance: //1 Per DOT, MAOP confirmed for all but,01 miles Remaining class 1& by //1 Trans: 1/1/1 Dist: 1/1/1 Within 1 yr of AGA guidance 1/1/1 b. Under DIMP, identify distribution assets where increased leak surveys may be appropriate 1/1/1. Integrate applicable provisions of AGA s emergency response white paper and checklist into 1/1/1 emergency response procedures Emergency response white paper & checklist complete. Extend Operator Qualification program to include tasks related to new main & service line /0/1 construction. Expand EFV installation beyond single family residential homes to small commercial and multi-family /0/1 residential services. Implement appropriate meter set protection practices identified through AGA Gas Utility Best /1/1 Practices Program. Roundtable is being held October 1, 01.. Incorporate an Incident Command System (ICS) type of structure into emergency response protocols /0/1. Extend transmission integrity management principles to transmission pipelines outside of HCAs using 0% of population within PIR by a risk-based approach Note: Document on integrity management principles is on hold due to PHMSA s 00; 0% of population by Integrity Verification Process initiative 00. Begin risk-based evaluation on the use of ASVs, RCVs or equivalent technology on transmission block July 01 valves in HCAs Controller General Study completed January 01 * Target dates are based on an operator s evaluation of these actions in light of system variables, the operator s independent integrity assessment, risk analysis, and mitigation strategy. Target dates also assume state regulatory approval that action is prudent and reasonable and therefore recoverable in rates. Per AGA surveys, all target goals have been met by most AGA members Gas Utility Industry Actions That Exceed CFR Part 1 Incorporate systems and/or processes to reduce human error to enhance pipeline safety Advocate programs to accelerate the risk-based repair, rehabilitation and replacement of pipelines Support development of processes and guidelines that enable tracking and traceability of pipeline components Encourage participation in One-Call by all underground operators and excavators Influence and/or support state legislation to strengthen damage prevention programs Use industry training facilities and evaluate opportunities to expand outreach/education programs to internal and external stakeholders Support and enhance damage prevention programs through outreach, education, intervention and enforcement Use a risk-based approach to improve excavation monitoring Develop, support, enhance and promote CGA initiatives targeted at damage prevention, including data submission and Support public awareness programs targeted at damage prevention Continue AGA Safety Committee initiatives, such as sharing lessons learned through the Safety Information Resource Center, safety alerts through the AGA Safety Alert System, safety communications with customers and supporting AGA s Safety Culture Statement Explore ways to educate, engage and provide appropriate information to stakeholders to increase pipeline public awareness Conduct organizational response drills to improve emergency preparedness Participate in state, regional and national multi-agency emergency response training exercises Reach out to emergency responder community in order to enhance emergency response capabilities Verify participation in a mutual assistance program, if appropriate; integrate into emergency response plans Collaborate with stakeholders near existing transmission lines to increase awareness/adoption of appropriate PIPA recommended best practices Promote benefits of R&D funding. Support R&D investment, pilot testing and technology implementation Support technology development and deployment in critical applications Collaborate on R&D
125 AGA s Commitment to Enhancing Safety: AGA Actions AGA ACTIONS COMPLETED Implement discussion groups to address safety issues including discussion groups for employee technical training and knowledge transfer, material supply chain issues, DIMP implementation, public awareness, work management, GPS/GIS and work management systems, contractor/quality management, odorization, public awareness, and damage prevention. Participate in DOT events on Automatic Shut-off Valve and Remote Control Valves, Pipeline Data, Distribution Integrity Management, Incident Reporting, Public Awareness, Leak Detection System Effectiveness and Understanding the Application of Automatic/Remote Control Shutoff Valves, Integrity Verification Process Develop, with INGAA and API, a public document to explain ratemaking mechanisms used for pipeline infrastructure Create a Safety Information Resources Center for the sharing of safety information Hold regional operations executives roundtables to discuss safety initiatives: Annually Sponsor workshop with INGAA and National Association of State Fire Marshals (NASFM) on emergency response Develop a technical note on industry considerations for emergency response plans Develop Emergency Response Resource center with a streamlined mutual assistance program Develop a task group comprised of AGA staff and members to work closely with Pipelines and Informed Planning Alliance (PIPA) to ensure AGA member concerns are addressed in joint PIPA initiatives Work with INGAA, research consortiums and other pipeline trade associations to provide the NTSB with a compilation of the progress that has been made in advancing in-line inspection technology Host a roundtable focused on operator experience and lessons learned: Annually at the AGA Operations Conference Work with INGAA, API, AOPL, Canadian Gas Association and Canadian Energy Pipeline Association on a comprehensive safety management study that explores initiatives currently utilized by other sectors and the pipeline industry. With PHMSA, create a Data Quality & Analysis Team to analyze data PHMSA collects, determine what the data is telling us, issue reports, identify missing information and how best to collect that data, and key metrics that indicate safety concerns. AGA ONGOING ACTIONS Promote the use of innovative rate mechanisms for faster repair, rehabilitation or replacement. Maintain a clearinghouse on effective cost-recovery mechanisms that states have used to fund infrastructure repair, replacement and rehabilitation projects. Support legislation that strengthens enforcement of damage prevention programs and Support the Common Ground Alliance, use of and other programs that address excavation damage Continue the work of the AGA Best Practices Programs to identify superior performing companies and innovative work practices that can be shared with others to improve operations and safety. Continue the Plastic Pipe Database Committee s work to collect and analyze plastic material failures Promote the AGA Safety Culture Statement and a positive safety culture throughout the natural gas industry Conduct workshops, teleconferences and other events to share information including pipeline safety reauthorization, DIMP/TIMP, fitness for service, records, in-line inspection, emergency response, and other key safety initiatives Hold an annual executive leadership safety summit. Recognize statistical top safety performers, promote safety performance and encourage knowledge sharing through AGA Safety Awards Support PHMSA and NAPSR workshops and other events Search for new and innovative ways to inform, engage and provide appropriate information to stakeholders, including emergency responders, public officials, excavators, consumers, safety advocates, and the public living near pipelines Participate in the Pipeline Safety Trust s annual conference to provide information on distribution and intrastate transmission pipelines, AGA and industry initiatives, and receive input Build an active coalition of AGA member representatives to work with PHMSA and other stakeholders to implement PIPA recommended practices pertaining to encroachment around existing transmission pipelines Advocate to state commissioners the inclusion of research funding in rate cases in an effort to increase funding for R&D Work with PHMSA and other stakeholders on opportunities to increase R&D funding and deployment of technologies Advocate acceptance of technologies that can improve safety Develop publications dedicated to improving safety and operations
126 AGA s Commitment to Enhancing Safety: AGA Actions Continued AGA ACTIONS WITH TARGET DATES Develop guidance to determine a distribution or transmission pipeline s fitness for service and MAOP, and the critical records needed for that determination. (/0/1) - Completed Create a Safety Alert Notification System that will allow AGA or its members to quickly notify other AGA members of safety issues that require immediate attention. (/0/1) - Completed Develop a more comprehensive technical paper that presents benefits and disadvantages of the installation of ASV/RCV block valves on new, fully replaced and existing transmission pipelines. (/0/1) Completed Create technical guidance for oversight of new construction tasks to ensure quality. (1/1/1) Completed (Track progress of industry s implementation of guidelines and summarize results annually) Utilize DIMP to evaluate the risks associated with trenchless pipeline techniques and implement, where necessary, initiatives to prevent and mitigate those risks. (1/1/1) Completed. Guidance created for new installations. Multiple events to highlight how different companies are addressing the potential risk associated with historic trenchless pipe installations. Based on the results of the safety management study, identify and begin to implement initiatives that will enhance the appropriate sharing of safety information. (1/1/1) Safety management study complete. New key initiative: Pilot test of Peer-to-Peer reviews. Reviews began mid-01 and remaining reviews to be completed by April 01 Include meter protection in 01 AGA Distribution Best Practices Program. (/0/1) Completed. Topic included in the 01 Best Practices Program. AGA ACTIONS TARGET DATES NOT APPLICABLE Work with PHMSA and distribution operators on ways to address risk to meters from vehicular damage, natural and other outside forces. Engage PHMSA and NAPSR in discussions on whether TIMP should be expanded beyond HCAs and the benefits and challenges of applying integrity management principles to additional areas. Highlight in DOT workshops, NAPSR meetings and discussions with Government Accountability Office that: 1) Many AGA members are required to manage DIMP and TIMP programs that overlap. The effectiveness, inefficiencies and duplication of multiple integrity management programs must be explored. ) Low-stress pipelines operating below 0% SMYS should be treated differently. Work with industry and regulators to evaluate how the grandfather clause can be modified to reduce and/or effectively eliminate its use for transmission pipelines. Work with industry and regulators on meaningful metrics, including leading indicators, that indicate pipeline safety issues Work with other stakeholders to develop potential technological solutions that allow for tracking and traceability of new pipeline components (pipe, valves, fittings and other appurtenances attached to the pipe). Develop guidelines that provide for an improved level of engagement between operators and excavators. Work with PHMSA to establish time limits for telephonic or electronic notice of reportable incidents to the National Response Center after the time of confirmed discovery by operator that an incident meets PHMSA incident reporting requirements Work with other stakeholders to improve pipeline safety data collection and analysis, convert data into meaningful information, determine opportunities to improve safety based on data analysis, identify gaps in the data collected by PHMSA and others, and communicate consistent messages based on the data. Pilot application of PIPA guidelines with select member utilities.
127 Attachment CFC- 1 of 1 AMRP Miles Replaced Annually Cast Iron Bare Steel PVC TOTAL
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