1. Distribution Integrity Management Program
January 19, 2009
A discussion document
DIMP Interest Group Steering Committee
Mike Beatty, Manager, Engineering & Construction, South Carolina Electric & Gas Company
Craig Hoeferlin, Vice President, Operations, Laclede Gas Company
Phillip Murdock, Director, Asset Management, Atmos Energy
David Cicoria, Manager, Systems Operations, Columbia Gas of Virginia, a Nisource Company
Mike Grubb, Staff Executive, SGA
Fraser Farmer, Staff Executive, SGA
Some material provided by
Andrew Lu, American Gas Association

2. 49CFR192 - Federal Regulation
Needs modification to include risk-based distribution integrity management process:
High-level, performance-based flexible federal reg
Implementation guidance
Nation-wide education program (as part of implementing 3-digit One-call) <DIMP or Damage Prevention>
Continuing research & development

3. Distribution Characteristics
Distribution pipeline systems exist in restricted geographical areas that are predominantly urban/suburban, because the purpose of these pipelines is to deliver natural gas to end users – residential, commercial, industrial and institutional customers.
Distribution pipelines are generally small in diameter (as small as 5/8 inch), and are constructed of several kinds of materials including a significant percentage of plastic pipe.
Distribution pipelines also have frequent branch connections, since service lines, providing gas to individual customers, branch off of a common “main” pipeline, typically installed under the street.
The dominant cause of distribution incidents is excavation damage with third party damage being the major contributor to these incidents.
Other than as caused by excavation damage, distribution pipeline failures almost always involve leaks, rather than ruptures, because the internal gas pressure is much lower than for transmission pipelines.

4. The 7 Key Elements as noted in NPRM 192.1007 June 25, 2008
Knowledge of the system’s infrastructure
Identify threats (existing and potential)
Evaluate and prioritize risk
Identify and implement measures to address risks
Measure performance, monitor results and evaluate effectiveness
Periodic evaluation and improvement
Report results

5. Notable Required Elements in a DIMP Plan
d) Formal risk assessment of threats to an operator’s distribution system, including risk posed by operator’s employees – “Assuring Individual Performance” - “PTP”
Data integration (Leaks, corrosion data, 3rd party damages, etc.)
Mechanism or process to identify any potential problems with compression couplings
d) Requirement to identify and implement risk reduction strategies, w/ emphasis on effective leak management program (“LEAKS”) and “enhanced” damage prevention program.
Proposed requirement for operator to report all plastic pipe ‘failures’ (including fittings, couplings, valves and joints) to the state agency.

6. Notable Required Elements in a DIMP Plan
a) Special provisions are proposed for master meter and liquefied petroleum operators
f) Operator must conduct a complete DIMP program re-evaluation at least every five years
a) Operator is given 18 months from the date of final rule issuance to develop and implement a written IM program
Eliminates §
Invites comment on the desirability of requiring permanent markings on plastic pipe and the proposed approach of relying on ASTM. (Would possibly help with risk management)
SHRIMP for smaller operators - APGA

7. Threats
The categories of threats to be considered should include the eight threats identified in the Pipeline and Hazardous Materials Safety Administration (PHMSA) Annual Distribution Report, PHMSA Form as “Cause of Leaks” in Part C:
Excavation
Other outside force
Natural Forces
Incorrect Operations
Equipment
Corrosion
Material or welds (construction)
Other

8. Implementation Establish a Framework (SGA/NGA joint project)
Region = system vs. segment
Prioritize threats, using risk assessment methods, in each segment based on personnel (SME) knowledge and construction, operation & maintenance records
Assess needs, opportunities & plans to address each threat/region
Develop metrics to evaluate performance
Document
Continuous improvement cycle

9. Timeline
DOT Inspector General issues report to Congress on DIMP (June 2004)
AGF Study on “Safety Performance and Integrity of the Natural Gas Distribution Infrastructure” (Jan 2005)
DIMP Phase 1 Report is published by PHMSA (Dec 2005)
GPTC working on DIMP Guidance Material. Final “draft” is completed and awaits issuance of regulation (late 2006)
2006 PIPES Act passed, mandating DIMP by Dec 31, 2007 and EFVs by June 1, (Dec 2006)
NPRM on DIMP issued (June 25, 2008)
Comments due Sep 23, 2008
Final Rule for DIMP anticipated (mid- 2009)
DIMP Plan will be required within 18 months from Rule issuance (late-2010)

10. PHMSA - data driven PHMSA wants to be data driven in DIMP reporting
AGA/PHMSA task group on national metrics
Christina Sames, AGA - indicators to demonstrate improvements
Internal vs. external reporting metrics

11. Guidance Need particular support for smaller operators
Should develop guidance to assist operators in determining:
threat prioritization methods
risk control practices
performance measures that are most appropriate for their risk control program.
Implementation guidance (GPTC - Gas Piping Technology Committee)
SHRIMP
NGA/SGA Framework

12. GPTC Final draft issued (Oct 13/06)
Approval of draft - Nov 6/07 - ANSI Reno meeting
Sync with NPRM in July 2008
Sync with final rule in mid-2009
Good working relationship industry<>PHMSA. Important not to have major industry objections later in the process.
GPTC web site.

13. SHRIMP simple, handy, risk-based, integrity, management, plan
A Plan implementation resource
Being developed by APGA - John Erickson
Focus > smaller operators (also for large)
A software tool using interactive rule/expert techniques to derive a DIMP document
Proscriptive, not customizable
Consistent with Final Rule & GPTC guidelines
Like tax preparation software
Expert working group - APGA, AGA, PHMSA …
Consultants - to make the software
Grant from PHMSA
Available upon issuance of Final Rule
Extension to include interfaces to workflow etc for DIMP reporting

14. NGA/SGA Generic Distribution Integrity Management Plan
A joint NGA/SGA project
A Plan implementation resource
Generic part + customizable part
Expert working group (DIWG) – NGA, SGA
Consultants - to make the Plan Apr 2009 to July 2009
Available 1 month after issuance of Final Rule
Available to joint industry project participants

15. Prevention & Mitigation
Damage prevention programs
Leak management programs
Public Awareness programs
Operator Qualifications programs
Other programs
DIMP or separate initiatives?
Stand-alone programs?

16. State Damage Prevention Programs
Some states have implemented effective comprehensive damage prevention programs that have resulted in significant reductions in the frequency of damage from excavation. Effective programs include nine elements:
Enhanced communication between operators and excavators
Fostering support and partnership of all stakeholders in all phases (enforcement, system improvement, etc.) of the program
Operator’s use of performance measures for persons performing locating of pipelines and pipeline construction
Partnership in employee training
Partnership in public education
Enforcement agencies’ role as partner and facilitator to help resolve issues
Fair and consistent enforcement of the law
Use of technology to improve all parts of the process
Analysis of data to continually evaluate/improve program effectiveness
Potential obstacle: Other utilities may have different priorities (e.g. telecoms want lost revenue recovery)

17. State Damage Prevention Programs
Not all states have implemented such programs.
Federal legislation and/or funding is likely needed to support the development and implementation of such programs by all states. Work on this legislation can begin immediately.
This represents the greatest single opportunity for distribution pipeline safety improvements.

18. Leak Management
Management of gas leaks is fundamental to successful management of distribution risk, and an effective leak management program is thus a vital risk control practice. Effective programs include the following elements:
Locate the leak
Evaluate its severity
Act appropriately to mitigate the leak
Keep records, and
Self-assess to determine if additional actions are necessary to keep the system safe.

19. Excess Flow Valves
Congress passed PIPES Act in 2006 mandating the installation of EFVs as of June 1, 2008.
After June 1, 2008, EFVs must be installed where:
New/replacement services lines serving single residential customers
Operating pressure > 10 psig
Contamination will not prevent proper operation
EFV in size required is commercially available

20. Performance Tracking
Track damage prevention metrics both for internal use in evaluating the effectiveness of an operator’s program (by operators) and for evaluating progress at the national level.
Once reportable Performance Measures are finalized, develop a national baseline from which trends in performance can be monitored, and a means of tracking trends from the baseline.
Form a joint stakeholder group to conduct an annual data review, to resolve issues, and to produce a national performance measures report.

21. Performance Measures 7 performance measures as noted in § 192.1007:
# hazardous leaks eliminated/repaired, by cause
# of excavation damages
3. # of excavation tickets
# of EFVs installed
5. Total # of leaks eliminated/repaired, by cause
Total # of hazardous leaks eliminated/repaired, by material
Any additional measures to evaluate effectiveness of operator’s program in controlling each identified threat

22. Data Reporting Considering changes to data reporting:
Require additional information for incidents when cause is excavation damage – identify useful information from review of the Damage Information Reporting Tool (DIRT) and state reporting requirements
Expand incident report form to add information on the causes of incidents resulting from vehicles hitting gas facilities
Report hazardous leaks eliminated by material in addition to cause; indicate presence of protection (e.g., coating, cathodic protection)
Report hazardous leaks eliminated rather than all leaks eliminated/repaired during the year and the known system leaks at the end of the year scheduled for repair
Add a check box (and appropriate criteria) on whether the regulations clearly require reporting or whether the report is submitted at the discretion of the operator

23. Plastic Pipe Data Collection
In 2001, national effort was initiated to collect data on plastic pipe performance
AGA is the administrator of this database
PHMSA has expressed concern with the transparency of how the effort is being managed; specifically how the data is collected , who has access to it and whether it is effective based upon how it is currently set up.
The DIMP NPRM asks questions whether the reporting should be mandatory; who should manage the database; and if it makes sense to start a new effort to improve availability of results and sharing of “information” to all operators.
Obstacles may include anti-trust issues, legal disclosures, and data integrity.

24. Plastic Pipe Data Collection – AGA perspective
Companies submit data to the PPDC because they trust that it is kept strictly confidential.
PPDC has been successful and changing the reporting structure or the administrator will jeopardize this success.
Those who are involved in PPDC are in favor of keeping it status quo.
If there were a national problem with couplings or a particular plastic pipe, then the PPDC is equipped to identify such a problem for the industry.
It doesn’t make sense to have two separate plastic pipe databases.

25. Assuring Individual Performance
Prevention Through People is a concept that was promoted by Admiral Barrett, and it has been used in public meetings to discuss CRM.
Under “What are the required IM program elements?”, it would require operators to evaluate and manage the contribution of human error and intervention to risk. (cites human factors, including fatigue management)
This section must consider existing programs the operator has implemented to comply with Damage prevention programs, public awareness, OQ and drug & alcohol testing.
Read Section XI. Prevention Through People on p of Federal Register NPRM.

26. Assuring Individual Performance – AGA perspective
PTP was not included in DIMP Phase 1 Report.
OQ, DP, Drug & Alcohol Testing and Public Education requirements should sufficiently address how an operators manages human error.
Operator error historically has been the cause of a very small % of reportable incidents. (< 5% in past 10 years)
What does an effective fatigue management plan look like?
How can an operator directly control the actions of people that it does not employee?

27. Service Line Inspections
DIMP is supposed to be a performance-based rule, yet there are existing sections in the code that are counter to this philosophy - - § Atmospheric Corrosion and § Leakage Surveys.
In 2007, AGA worked with NAPSR and PHMSA to form a government-industry Service Line Inspection Committee to discuss issues relating to leak surveys and corrosion inspections on both inside and outside meter installations.
Objective: To collect data from service line inspections performed throughout North America and evaluate the true effectiveness of these surveys and inspection requirements and the potential consequences of changing the regulations.
Report to be issued by consultant by October 2008.
Study will hopefully support industry’s case for special permits under DIMP Rule.

28. Research & Development
Review Phase 1 report for R&D conclusions.

29. AGA Comments 1 of 4. Documentation for Gas Distribution Integrity Management Plans
Avoid excessive record keeping requirements
The primary concern that AGA has with sections and is that PHMSA deviates from the recommendations of the DIMP phase 1 report in that the proposed rule appears to require unnecessary and excessive documentation within an operator’s distribution integrity management plan. The regulation’s requirement that operators document all of the decisions they make in implementing distribution integrity management is not practical. Gas distribution systems are so intricate that it would require an enormous paperwork burden to document all the decisions associated with providing service to millions of customers.

30. AGA Comments 2 of 4. Plastic Pipe Data Collection and Analysis
The need to modify the Plastic Pipe Database Committee (PPDC) AGA notes that the existing Plastic Pipe Database Committee (PPDC) has done an excellent job in tracking the trends in plastic material performance and believes that eliminating this committee and creating a completely new plastic pipe database is unnecessary and counterproductive.

31. AGA Comments 3 of 4. Prevention Through People
Inability of operators to implement vague and unenforceable human factor requirements in integrity management programs The proposed distribution integrity management program regulations include requirements for operators to understand the threats affecting the integrity of their systems and to implement appropriate actions to mitigate risks associated with these threats. These include a first step towards instituting a ‘‘Prevention Through People’’ (PTP) program to address human impacts on pipeline system integrity. Human impacts include both errors contributing to events and intervention to prevent or mitigate events. As part of considering the threat of inappropriate operation (i.e., inappropriate actions by people), this proposed rule would require operators to evaluate the potential for human error. Seeking to reduce incidents by minimizing human error is commendable. However, the AGA has some fundamental problems with the PTP concept in the proposed rule. A major problem is that the concept as presented in the rule is too vague to be an enforceable regulation.

32. AGA Comments 4 of 4. Alternative Inspection Intervals
The need to efficiently implement alternative inspection intervals AGA supports the concept of alternative inspection intervals. When the pipeline safety code was adopted in the early 1970s it was reasonable and prudent to adopt a consistent set of federal pipeline safety standards for the entire nation. Now, in the 21st century, data analysis can distinguish the effectiveness of pipeline safety inspections. Operators and regulators can use this analysis to tailor their regulations to meet the needs of the local stakeholders. The underlying purpose of PHMSA’s integrity management requirements is to improve knowledge of the condition of each operator’s pipeline and to use that information to identify new risk control solutions and to better focus risk reduction efforts. Resources would be better allocated to higher risk threats. Furthermore, AGA does not believe the DIMP regulation would be cost beneficial unless an effective method to implement alternative inspection intervals is included in a final rule.

33. SGA - Assisting its members
Work with DIMP Interest Group Steering Committee to define implementation issues that should be addressed and to manage desired outcomes. Keep Interest Group on track, on timeline.
Do a survey to define current practices
Do WebCon on the 7 elements – Fall 2009
Support the ‘guidance’ process
Develop a starter shell DIMP for members (similar process to Transmission; NGA/SGA DIWG) – Fall 2009
Face-to-face meeting when Rule is issued – Fall 2009

34. More Information SGA DIMP IG web page http://www.southerngas.org
click on “Interest Groups”
then on “DIMP”
Please contact any member of the steering committee for further information:
Mike Beatty, Manager, Engineering & Construction, South Carolina Electric & Gas Company
Craig Hoeferlin, Vice President, Operations, Laclede Gas Company
David Huff, Director Distribution Operations, E.ON/U.S. (L.G.&E.)
Phillip Murdock, Director, Asset Management, Atmos Energy
David Cicoria, Manager, Systems Operations, Columbia Gas of Virginia, a Nisource Company
SGA contacts:
Randy Randolph, Staff Executive, SGA
Mike Grubb, Staff Executive, SGA
Fraser Farmer, Staff Executive, SGA