DIMP Distribution Integrity Management Program

1. DIMPDistribution Integrity Management Program Black Hills Energy 1815 Capitol Avenue Omaha, NE 68102 Randy Paap, Director Gas Engineering Services Direct: 402.221.2105 Fax: 402.829.2105 Email: randy.paap@blackhillscorp.com

2. Distribution Integrity Management • Basic idea is to analyze your risks, and reduce them • Regulations require a written program • Program must address seven elements 2

3. Seven Elements of DIM Program Know the distribution system/infrastructure and how it is operated and maintained Identification of Threats (existing and potential) Evaluation and prioritization of risks Identification and implementation of measures to address risks and implement appropriate measure to manage risks Measurement of performance and monitoring results Periodic evaluation and improvement program Make periodic reports to government agencies

4. Knowledge of Infrastructure Material Plastic pipe failure reporting Consideration of compression coupling failure Operating Conditions Use best information available – do not have to dig up system to get data

5. Evaluation of Potential for hazards • Leak management (next slide) • Enhanced damage prevention, including reporting of hazardous leaks removed • Need to define “hazardous leak” • What are you using now— • GPTC Guide definition or other? 5

6. Damage Prevention • Is “damage” just excavation damage, or any damage that causes a leak? • Definition of damage includes damage to facilities that support the pipeline. • Does this include non-pipeline materials? 6

7. L-E-A-K-S Management Locate the leaks in the distribution system. Evaluate the actual or potential hazards associated with these leaks. Identify methods/criteria for evaluating the severity of leaks and need of action. Do you use the GPTC guide criteria? Need to define “hazardous leak” Act appropriately to mitigate these hazards. Determine how local conditions and system knowledge should affect the frequency and type of leak surveys Keep records. Describe records that should be maintained to permit trending and identification of underlying problems. Self assess to determine if addtional actionsare necessary to keep people and property safe. Identify performance metrics and the types of analyses in which the operator should consider them 7

8. Identification of Threats • Corrosion • Natural forces • Excavation • Other outside forces • Material or welds • Equipment • Operations • Other 8

9. EFVs Each newly installed or replaced service line serving a single-family residence for which a suitable valve is commercially-available and where conditions are suitable. Operating continuously throughout year not less than 10 psig; No history of liquids/contaminants in gas flow; Where installation is not likely to cause a loss of service to residence; Interfere with required operation and maintenance activities. Repeals requirement to notify customers of EFV availability. Need some clarification on what constitutes a repaired line for purposes of requiring the installation of an EFV

10. Plastic Pipe Issues Participation in Plastic Pipe Data Collection monitors in-service performance of plastic pipe (administered by AGA) Currently not mandatory and reporting is not consistent Changes are needed to current system of data collection, analysis and communication Markings on plastic historically do not include permanent markings—to determine type, age or other key parameters of the pipe

11. Plastic Pipe Data Collection • Does not include third party damage • Guidelines are needed for the definition of “failure” • 90 day reporting requirement is unwieldy – would prefer an annual report 11

12. Monitor Effectiveness of Actions Requires submission to PHMSA annually the number of leaks repaired (by cause), the number of excavation damages and the number of tickets and the number of EFVs installed. PHMSA will use data to evaluate the effectiveness of new distribution IM requirements until sufficient time has passed that trends in the overall number of incidents, deaths, serious injuries, and property damage should be apparent

13. Prevention Through People—PTP Current regulations: 192.614—Public Awareness; 192.615—Emergency Plans;192.616—Qualification of Pipeline Personnel; Evaluation required by DIMP—PTP would integrate existing efforts and address the risks association with human factors per Section 12 of the PIPES Act and as part of mitigating risks. Could include regulations and a system to identify and communicate noteworthy best practices. Comments on PTP concept are requested by PHMSA – how operators are currently addressing human factors, including fatigue, in their ongoing efforts to manage the integrity of pipelines.

14. Prevention Through People • Isn’t this already addressed with existing regulations? • Welding, fusion, etc. are already covered by training, operator qualification certification, and inspection • Excavators are already covered by RP1162, one-call, common ground alliance 14

15. Prevention Through People • Natural forces and other outside forces are really beyond our control • Human factors, such as fatigue are hard to manage – how do you insure that employees come to work full of energy? • Proposal is vague – the Gas Piping Technology Committee is not confident that it can even craft guidance 15

16. Individual Performance • Does “Prevention Through People” apply to contractors, plumbers, and excavators? 16

17. Deviating From Required Intervals Purpose of DIMP—Improving the knowledge of condition of pipeline and using information to identify new risk control solutions focusing on risk reduction efforts. Operators could propose extended intervals for threats and areas where risk is low.

18. Intervals—PHMSA Seeking Comments Advantages/disadvantages of allowing of setting intervals driven by thorough analysis of individual operator performance data Should there be some limit on amount operator can deviate from currently-prescribed intervals e.g. no more than twice the interval? How would a State establish guidance for implementing such a process? What additional performance data and analysis would be required? What costs to States would be associated with such a process? What cost savings to operators could result from such changes? On what basis should a state judge the operators’ engineering basis adequate?

19. Mitigation Measures • Accelerated replacement of troublesome pipe • More leak surveys • Modification of maintenance procedures • Implementation of new technology 19