SUMMARY OF TRANSMISSION INTEGRITY MANAGEMENT PROGRAM

Transcription

1 Page 1 of 6 SUMMARY OF TRANSMISSION INTEGRITY MANAGEMENT PROGRAM Program Overview: The Company s Transmission Integrity Management Program ( TIMP ) was established to comply with federal TIMP regulations that prescribe how operators validate the integrity of their gas transmission assets through systematically performing assessments, identifying risks, and evaluating and prioritizing repairs to mitigate the risks and threats identified. The program is focused on a more comprehensive understanding of the health and condition of gas transmission pipelines, particularly those located in High Consequence Areas ( HCAs ). Other pipeline assets located outside of HCAs may also be drawn into the program under the TIMP rules, depending on the overall criticality of a pipeline and the potential consequences of its failure (such as the number of people who may be impacted). The TIMP rules incorporate elements from a national standard for managing system integrity of gas pipelines -- the American Society of Mechanical Engineers ( ASME 31.8S ). ASME 31.8S contains principles and processes for pipeline operators to follow when developing and implementing an effective integrity management program. This standard applies to the entire pipeline system, not just pipelines located in HCAs. The Company has adopted this standard, as it is consistent with the requirements of the TIMP regulation. Program Scope: The TIMP is focused on steel pipelines of various vintages typically operating at pressures of greater than 150 psig, as well as other pipeline features, such as valves. Program Description The TIMP initiatives to be pursued by the Company in 2014 fall within the following four categories: Transmission Pipeline Assessments and Repairs; Pipeline Data Project ( PDP ) for providing verifiable and traceable pipeline asset information; Maximum Allowable Operating Pressure ( MAOP ) initiative required for validating and documenting the safe, allowable pressure associated with pipeline specifications and operations; and Automatic Shut-off/Remote Control ( ASV/RCV ) initiative for gas transmission valves. Each of these categories will be discussed separately in the remainder of this TIMP summary, except the PDP and MAOP projects. These two initiatives will be discussed together, as both relate to gathering, validating and maintaining pipeline data TIMP Activities Overall Status Update: The Company is still in the process of updating and adjusting 2013 estimated costs for each of the TIMP projects to account for completed work through the end of the third quarter of 2013 and the anticipated work that remains during the fourth quarter. Moreover, the full impact of the widespread flooding within the Company s service territory in mid September 2013 is currently unknown. Priority of restoration work and constraints on the system due to flood damage will

2 Page 2 of 6 likely affect the Company s ability to complete TIMP work planned for the fourth quarter of Overall TIMP 2014 Financial Information: 13 Month Average Plant In-Service Revenue Requirement Total TIMP $29.3 M $12.5 M $132.4 M $26.4 M TIMP Project Details Transmission Pipeline $14.5 M $5.3 M Assessments and Repairs MAOP Validation $11.3 M $7.1 M PDP $0.5 M $0.0 M ASV/RCV Installations $3.0 M $0.1 M Total TIMP $29.3 M $12.5 M TRANSMISSION PIPELINE ASSESSMENTS AND REPAIRS Transmission Pipeline Assessments and Repairs Overview: The Company has selected ILI as its primary assessment methodology. However, additional methods may also be utilized, depending on the risk factors or data collected on the pipeline. These additional methods include Direct Assessment and pressure tests. Assessments are required under the federal regulations for pipelines in HCAs at regular intervals. The TIMP rules require the Company to apply the knowledge gained from these assessments to the rest of the system. Due to the large number of anomalies and threats identified, the Company has expanded assessments beyond HCAs to more fully understand the risks on pipelines throughout our system Status Update The Company completed over 280 miles of pipeline assessments from January through August 2013, and is in the process of completing repairs as necessary based on these in-line inspections ( ILI ) and direct assessments. Some work related to both ILI assessments and repairs was delayed over the summer due to the rapidly expanding West Fork forest fire near Pagosa Springs. These delays may result in the postponement of some planned 2013 ILI assessments into Plans: The scope of the 2014 work plan includes approximately 180 miles of assessments on pipelines within and outside of HCAs. Some pipelines will be undergoing a baseline assessment, the first assessment of the pipeline, while others will be reassessed per TIMP requirements. Due to the necessity to meet the challenges posed by permitting, weather constraints, and coordination of resources anticipated in 2014, the Company will also begin to evaluate, engineer, and prepare for

3 Page 3 of 6 a portion of the planned 2015 assessments. In addition to incurring costs for the ILI assessments, the Company will also incur costs for the digs necessary to confirm the extent of identified anomalies, and to complete necessary repairs. Cost estimates for the assessments and dig-related work are based on costs from 2011, 2012, and early A number of factors could cause deviations from the Company s planned line assessment activities in These factors include: vendor availability of highly specialized ILI tools, additional data obtained on assets that may require a change in the priority of planned assessments, and adverse weather and operating conditions that prevent planned assessments from being performed (e.g., unforeseen flooding or wildfires that disrupt expected pipeline operating conditions) Financial Information: Transmission Pipeline Assessments and Repairs $14.5 M $5.3 M The capital expenditures associated with transmission pipeline assessments are primarily attributable to baseline assessments and associated infrastructure investments, such as the installation of launchers and receivers, fittings to allow an ILI tool to navigate through a pipeline, and new pipelines and regulators necessary to maintain service to customers during an assessment. expenses are incurred for validation digs, repairs, and reassessments of pipelines for which the baseline assessment by ILI has already been completed. Timeline: Transmission pipeline assessments began in 2004 to comply with the deadlines for baseline assessments mandated by the Pipeline Safety Improvement Act of 2002 and they will always be a part of the Company s TIMP program. The Company met the federal deadline of assessing all pipelines in HCAs by December 17, Reassessments and necessary repairs are being conducted on those pipelines in accordance with the TIMP regulations. These regulations also require that when an operator identifies a new HCA, or installs a new segment of pipe, it must complete a baseline assessment of the pipe within ten (10) years from the date the HCA was identified or the new pipe was installed. In accordance with the accelerated timetable proposed in the Company s pending gas rate case in Proceeding No. 12AL-1268G, the Company s plan is to complete ILI assessments within ten years. PIPELINE DATA PROJECT (PDP) AND MAXIMUM ALLOWABLE OPERATING PRESSURE (MAOP) PROJECT PDP and MAOP Overview: The PDP creates a single access point for complete, accurate, and reliable pipeline asset information that is available in real time. This allows the Company to further increase its knowledge and understanding of key system assets and better integrate this knowledge when assessing and ranking risks. The MAOP initiative focuses on the requirement to have traceable,

4 Page 4 of 6 verifiable, and complete records of a pipeline s MAOP. The Company is gathering and validating existing MAOP records for the Company s transmissions pipelines, and completing remediation for any gaps in such records Status Update The majority of the PDP will be completed in 2013; however, the Company anticipates that a small amount of capital expenditures will be carried over into 2014 as a result of the timing of processing final invoices. In 2013, the Company reported its initial progress on its ability to validate MAOP on gas transmission pipelines through its Transmission Annual Report for Calendar Year 2012 filed with PHMSA on June 15, The primary focus for the additional reporting was related to pipe wall attributes and pressure test charts needed to validate MAOP. Through the remainder of 2013, the Company will continue to obtain additional data attributes on pipeline features such as flanges, fittings, and valves. The Company is also implementing new software that will automate MAOP calculations based upon the data that has been collected throughout this project. All data related to the design and construction of a given pipeline is being stored in a central database per industry standards where the software will access the data to calculate MAOP, calculate class location, and identify high consequence areas Plans: The PDP will be completed in early Under the MAOP project plan, the Company will complete approximately 29 pressure tests addressing approximately 50 miles of pipe. Also, the Company will replace approximately 2.7 miles of pipeline that lack sufficient historical MAOP documentation needed to meet recent criteria established by PHMSA to have traceable, verifiable, and complete records. Due to these data gaps, as identified through the MAOP Validation project, PHMSA does not recognize pressure testing as an acceptable method to establish MAOP, and therefore a partial or outright replacement strategy is warranted Financial Information: MAOP Validation $11.3 M $7.1 M PDP $ 0.5 M $0.0 M The majority of the PDP and MAOP costs are capitalized. Facilities and equipment for the contract labor are the only expenses associated with the PDP and are minimal. There will be some capital costs associated with preparing a pipeline for a pressure test similar to, but less extensive than, preparing a pipeline for an in-line inspection tool. The expenses related to the MAOP validation project are primarily associated with performing the actual pressure test once facilities are installed. Timeline: The PDP began in 2011 and facilitated the first phase of the MAOP project -- the Company s compliance with PHMSA s requirement to report in mid-2013 on the number of pipelines with and without verifiable MAOP documentation. The PDP concludes in early The Company is still evaluating the timeline of the MAOP remediation (i.e., mitigation of any pipelines without

5 Page 5 of 6 verifiable MAOP records through pressure testing or replacement), but expects this activity will take 10 or more years to complete. Federal mandates will influence this timeline. AUTOMATIC SHUT-OFF VALVE/REMOTE CONTROL VALVE (ASV/RCV) ASV/RCV Overview: The most notable change within the TIMP since the Company s October 2012 PSIA filing is related to the ASV/RCV gas transmission valves. Section 4 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 calls for the Secretary of the U.S. Department of Transportation ( DOT ) to require by regulation the use of automatic or remotely controlled shutoff valves, or equivalent technology, where it is economically, technically, and operationally feasible. On August 25, 2011, PHMSA issued an advanced notice of proposed rulemaking addressing ASV/RCV s and seeking comments on several broad areas for potentially expanding the TIMP rules. PHMSA has completed its study on ASV/RCV s, but has not yet issued a ruling. The Company plans to install these types of valves on various transmission pipelines as warranted to address existing TIMP requirements, which require the installation of an ASV/RCV at locations where it has been determined to provide an efficient means of adding protection in the event of a gas release, as well as in anticipation of potential new federal requirements. The goal of the ASV/RCV project is to install mainline isolation valves or add actuators to existing valves in order to quickly minimize the effect of an unplanned gas release on high pressure gas transmission pipelines. Long lead times on valve equipment and availability of construction resources could affect the exact timing of the proposed valve installations. However, any planned 2014 installation work not completed as scheduled would probably be deferred into a subsequent year, which could ultimately extend the full duration of this multiyear project Status Update The replacement of valves related to the ASV/RCV project is likely to be delayed because of resource constraints and system limitations resulting from the impact of recent floods. As a result, the capital expenditures on the ASV/RCV project will likely be less than originally forecasted Plans: Nine valve sets have been identified for evaluation and installation in Detailed engineering estimates for this work will be completed in the first quarter of Determination of the extent of the work necessary (e.g., full replacement or just installation of an actuator) may increase or decrease the final number of valve sets. The Company will strive to limit 2014 capital expenditures to the $3 million of proposed capital expenditures and readjust the scope of the project as necessary.

6 Page 6 of Financial Information: ASV/RCV Installations $3.0 M $0.1 M The capital expenditures associated with the ASV/RCV project include actuator installations, valve installations, and valve replacements. Timeline: Preliminary engineering for these valves began in 2012, and the first valves under this program were installed in Although finalization of the federal regulations will likely affect the timeline of the project, the Company s current plan is to complete installation on legacy pipelines within 10 years.