Minutes

2006 National NAPSR Meeting

Embassy Suites Hotel

Hot Springs, AR

 

 

Tuesday, October 31, 2006

 

Board Members: 

 

Chairman                                            Don Martin (Arkansas)

Vice Chairman                                    Phil Sher (Connecticut)

Secretary                                            Ron Law (Idaho)

Treasurer                                            Hans Mertens (Vermont)

Past Chairman                                    Ed Steele (Ohio)

Eastern Region                                   Don Ledversis (Rhode Island)

Eastern Region                                   Massoud Tahamtani (Virginia)

Central Region                                    Gaven Nicoletta (New York)

Central Region                                    Annmarie Robertson (Indiana)

Western Region                                  Alan Rathbun (Washington)

Western Region                                  Raffy Stepanian (California)

Southern Region                                 Glynn Blanton (Tennessee)

Southern Region                                 Mark McCarver (Mississippi)

Southwest Region                              James Mergist (Louisiana)

Southwest Region                              Bruno Carrara (New Mexico)

 

 

Chairman Don Martin called the meeting to order. Chairman Martin introduced Randy Bynum, Commissioner, Arkansas Public Service Commission, who welcomed NAPSR to Arkansas. He talked about the state and historic Hot Springs area. He thanked us for allowing Don to serve as National Chairman. Don Martin presented special gifts to board members – personalized Hog Heads.

 

Chairman Martin appointed a nominating committee to seek candidates for the position of NAPSR secretary:  Charles Kenow, Vernon Gainey (Chair), and Dennis Fothergill.

 

Introduction to NAPSR and State Pipeline Safety Programs – Phil Sher – NAPSR Vice Chairperson and State of Connecticut

 

  1. Welcomed Vice Admiral Thomas Barrett, Administrator from PHMSA
  2. Announced that Deputy Brigham McCowen was unable to attend the meetings, and also Stacey Gerard with OPS, and Tom Fortner with OPS, are unable to attend the national meeting
  3. Importance of NAPSR and their partnership between the states and federal government
  4. Contribution that each state makes is very important to the public
  5. Differences that impact each state
  6. NAPSR bi-laws and the mission to strengthen the pipeline safety program to bring cost effective safety, and to establish a good relationship with PHMSA

 

Introduction of George Mosinskis – New Administrative Manager

 

Chairman Martin introduced George Mosinskis as the new NAPSR Administrative Manager.

George Mosinskis thanked NAPSR for putting their trust in him and hiring him as the Administrative Manager.

Approval of Last Year’s Annual Meeting Minutes

 

Don Martin announced that the board approved last year’s annual meeting minutes at the closed session meeting on 10/30/06, and adopted a motion that new officers take over on November 6, 2006.

 

Address to NAPSR from the Pipeline and Hazardous Material Safety Administration (PHMSA) – Vice Admiral Thomas Barrett – PHMSA Administrator

 

1.      Importance of a partnership between state and federal agencies

2.      Mission

a.      Safety first

b.      Systems approach by understanding design, production, and maintaining the impact of the pipeline system

c.      Use 21st century solutions for 21st century problems

3.         Data risk management approach

a.      Not how much data, but how it is used, and what it tells you.

4.         Leadership goes with accountability

5.         How to deal with small operators

 

Pipeline Safety Reauthorization – Ted Wilke - PHMSA Pipeline Safety Acting Associate Administrator

 

1.         Credibility of the pipeline program

2.         Desire of PHMSA and Administration to ease the burden on the states

a.      Strengthen damage prevention efforts

b.      Provide civil enforcement authority

c.      Provide technology

3.         Key Provisions

a.      One call civil enforcement

b.      State damage prevention programs

c.      Cap of state pipeline safety matching funds

d.      Damage prevention technology grants

e.      Safety orders

f.        Authorization of appropriations

g.      Distribution integrity management

h.      Pipeline control management/fatigue

i.         Implementation of NTSB SCADA recommendations

j.         Low stress transmission (pipelines)

k.       Report on leak detection technology

l.         Pipeline security inspection and enforcement

m.    Technical assistance grants to communities

n.      Enforcement transparency

o.      Public education and awareness grant for “811”

4.         Other Provisions

a.      Integrity management enforcement

b.      Direct sales lines

c.      Permit streamlining

d.      Emergency waivers

e.      Emergency restoration of operations

f.        Petroleum transportation capacity study

g.      Cost recovery for design review

h.      Synchronization of reauthorization periods

i.         Emergency response grants

j.         Incident reporting form

k.       Corrosion R&D

l.         Cost recovery for extraordinary events

m.    Executive signature IM performance reports

n.      Inspector staffing

o.      Technical assistance grants to universities

p.      Corrosion control regulations review

5.         “Not Included” Provisions

a.      Gas pipeline integrity reassessment interval

b.      International provisions

c.      Limitations of inflationary adjustments of penalties

 

PHMSA Pipeline Safety Recent and Future initiatives – Ted Wilke – PHMSA Pipeline Safety Acting Associate Administrator

 

Current Challenges and Future Directions

1.           NAPSR Concerns

a.      Regulatory burdens outstripping resources

b.      Recognize time needed for change

c.      Support state efforts

d.      Performance measurement

e.      Strengthen PHMSA state programs office

f.        Need to strengthen partnership

g.      Training for inspectors

2.           Goals for Partnership in Pipeline Safety

a.      Improve safety performance

b.      Be a model regulator

c.      Help states/local government build capacity

d.      Support efforts to enhance

3.           Improve Safety Performance Overall

a.      Improve safety, not just reduce incidents

b.      Continue to reduce serious incidents – deaths and injuries

c.      Cut down on environmental damage form spills

d.      Reliability of pipeline supply is a safety issue for communities

4.           Be a Model Regulator

a.      Be responsive to public concerns

b.      Be “All over it” when bad things happen

c.      Raise safety standards and expectations

d.      Risk-based decision-making

e.      Improve safety not just compliance

5.           Help States/Local Government Build Capacity

a.      Share responsibility

b.      Strengthen partnerships

c.      Provide tools and capability

d.      Use best practices

e.      Provide training

f.        Communicate directions

6.           Challenges – 2006

a.      High profile events

b.      Reauthorization

c.      Regulatory Initiatives

d.      New leadership

e.      Need for staffing in state programs

7.           Challenges – 2007

a.      Working with states to implement initiatives

b.      Complexity of key issues, risks, and priorities

c.      Finding the resources to get the job done

d.      Better data & data quality

e.      Less rulemaking activity

8.           Themes for the Future

a.      Integrity management

b.      Reduce high-consequence events

c.      Establishing priorities based on risk

d.      Shared responsibility

e.      Be transparent in actions and communications

f.        Organizational excellence

g.      Regulatory Agenda

9.           Path Forward

a.      Regulatory Agenda

b.      Better Data (Quality)

c.      Inspection Integration

d.      Assessment of Pipeline Operator Performance

10.       Strengthening the Partnership

a.      Assistance to States

b.      Strengthened Damage Prevention Programs

c.      Growing Partnership

d.      Commitment

11.       Impetus for a Distribution Integrity Management Program

12.       Damage Prevention – 9 Points

 

 

Wednesday, November 1, 2006

 

Training and Qualifications – Richard Sanders – Manager, PHMSA

 

  1. Appurtenances
    1. Risers – seals
    2. Couplings – gaskets
    3. Key hole – coating
    4. Remote meter reading
    5. Soft-closure
    6. Marking of materials
    7. Composite materials
    8. Cold fusion joints
  2. OQ Update
  3. Assessment evaluation for OQ course
  4. Welding issues
  5. LNG issues
  6. WinD.O.T. issues
  7. ASTM D 2513
  8. Plastic pipe institute

 

PHMSA Pipeline Safety Program development Initiatives – Jeff Wiese – Director, PHMSA Pipeline Safety Program Development

 

  1. Growing Safety
    1. Growing critically of Nation’s pipelines
    2. Increase in energy demand
    3. Supply and consumption
    4. Research and development is drying up

 

 

 

 

  1. NPMS
    1. Location of gas and liquid pipeline maps available to the public
    2. Not to be used for excavation purposes
  2. PMSA’s Public Awareness
    1. Public safety regulations
    2. Participant in American Petroleum Institute
    3. Operator workshops in 2003 and 2005
    4. Final rule published May 2005 requiring RP 1162-style programs by June 20, 2006
  3. Clearinghouse Results
  4. Implementation Inspections
  5. Integrated Inspections
  6. Working together on an agenda
    1. Model regulator
    2. Focus on system performance
    3. Build capacity at state & local (&Fed) level
    4. Improve pipeline security with DHS
  7. Model Regulator
    1. Data driven, risk-based approach to allocation of resources
    2. Collaborative problem ID and targeting
    3. Broadening IM approach across system
    4. Investigative, analytical, and communicative
    5. Structured approach to learning
    6. Transparent to the public
  8. Systems Safety
    1. Relying on the IMP principles
    2. Driving performance through leadership focus
  9. Building Capacity
    1. State, local and federal inspectors
    2. Other partners who share a role
    3. Public – Credible communication and awareness
  10. Requests
    1. Data Quality Team
    2. DIMP Oversight Model Team
    3. Risk-based Inspection Workshop

 

American Gas Association Presentation – Lori Traweek

 

  1. Overview of Challenges and Opportunities
    1. Stakeholders value safety, costs, and customer satisfaction
    2. Different approach to balancing reliability and cost-effectiveness without compromising safety
  2. Challenges to Bringing in New Supply
    1. Concerns about LNG Terminal Sitings
    2. Barriers to Alaska natural gas pipeline
    3. Much of the lower 48 supply is not accessible.
  3. Overall Effect
    1. Price volatility
    2. Increased un-collectables
    3. Increased pressure from commissions to keep cost to consumers low
  4. Balancing Efficiency and Reliability Without Compromising Safety
    1. Promoting supply development and energy efficiency
    2. Encouraging commissions to promote innovative rate design
    3. AGA board-level safety task force
  5. Safety Task Force Recommendations
    1. Elevate safety improvement to a key strategic priority for AGA
    2. Commit board time for a full, annual report of safety performance
    3. Fully support AGA role to standardize, report and analyze industry safety performance
    4. Provide forums for exchange of leading practices
    5. Strengthen partnerships with insurers and other industry groups who provide safety data
  6. Gas Utility Contractor Safety
    1. Revise the AGA contractors safety guidelines
    2. Focus on educating members about the benefits of contractor safety 2007
    3. Contractor safety workshop and safety summit 2007
    4. Data collection and analysis in 2008
  7. Customer Safety in the Home
    1. Statistics available but need to be refined
    2. Working with Aegis and members to identify meaningful incident data
    3. Data collection and analysis
  8. Balancing Efficiency and Reliability Without Compromising Safety
    1. Promoting supply development and energy efficiency
    2. Encouraging commissions to promote innovative rate design
    3. AGA board-level safety taskforce
    4. Promoting sound and effective regulations and legislation
    5. Working with our state, federal and public partners out interests are aligned with out customers

 

American Gas Association – Phil Bennett

 

  1. Regulatory
    1. Transmission IMP audits
    2. DIMP rule
    3. Enforcement transparency
    4. Gas controller requirements
    5. Improved data collection & analysis
    6. Permit streamlining
    7. Infrastructure safety communications
    8. Security

 

SCADA Control Room Rulemaking Concepts – Mike Israni, PHMSA

 

Control Room Management – Insights from the CCERT Program & NTSB

  1. Congress has Required PHMSA to Investigate the Value of Controller Certification
    1. Develop tests and other requirements for certifying the qualifications of individuals
    2. Establish and carry out a pilot program for 3 pipeline facilities
  2. The NTSB has Made 5 Recommendations on Control Room Management
    1. Rec P-05-1: Require liquid operators to follow APR RP 1165 for use of graphics
    2. Rec P-05-2: Require pipeline companies to have a policy for the review/audit of alarms
    3. Rec P-05-3: Require controller training include simulations for recognition of abnormal operating conditions
    4. Rec P-05-4: Change liquid accident reporting form
    5. Rec P-05-5: Require operators to install computer-based leak detection systems
  3. PHMSA has Completed the Controller Certification Project & Pilot Program
    1. Little value in a national administered standard certification test
    2. Validating controller-related processes, procedures, training & credentials
    3. Need to ensure adequacy of training & qualification
    4. Issues exist with control event displays and alarms
    5. Need to manage shift change to ensure exchange of information
    6. Operators need to apprise and train their controllers about fatigue
  4. Operator qualification report to congress summarizes results from CCERT project (Due December 17, 2006)
  5. How our approach addresses controller performance issues
    1. Relies on current regulations
    2. Uses advisory bulletins
    3. Develops new regulation only as needed
    4. Addresses recognized issues & NTSB recommendations
    5. Deals with the diversity of controller responsibilities and control room configurations
    6. Periodically validates control room layout
  6. PHMSA may consider a proposal to require pipeline operators to have risk management programs for control room management
  7. Operator risk management programs would address the following concerns:
    1. Failure to consider the length of shifts
    2. Too many or too few alarms or excessively complicated
    3. Shift change presents challenges in management
    4. Operators do not always consider controller training
    5. The content and thoroughness of safety and pipeline integrity procedures

 

GPTC Guidelines Update – Phil Sher, GPTC Second Vice Chair

 

BACKGROUND

  1. Pipeline Integrity
    1. Presumed good materials and construction practices checked by pressure test produces sound pipelines
    2. Did not consider long-term effects
  2. Integrity Management Liquid Pipeline Requirements
    1. Pipelines covered – those in high consequence area (HCA)
    2. Requires written integrity management plan
    3. Requires mitigation measures
    4. Requires preventative and mitigative measures
    5. Requires continual process of evaluation and assessment to maintain a pipeline’s integrity
  3. Integrity Management Gas Transmission Pipelines Requirements
    1. Pipelines covered – those in high consequence area (HCA)
    2. Identified site –

an outside area or open structure that is occupied by twenty or more persons on at least 50 day  in any twelve-month period; or

a building that is occupied by twenty or more persons on a least five days a week for ten weeks in any twelve-month period; or

a facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate

    1. Allowable assessment methods
    2. Take prompt action to address and evaluate anomalies
    3. Remediate those likely to pose a threat to the integrity, or reduce operating pressure
  1. Gas Distribution
    1. Transmission companies have significant similarities from company to company
  2. Report to Congress
    1. Operator shall develop a program plan that describes how is manages the integrity of its distribution system
    2. Identify threats applicable to its system
    3. Characterize the relative significance of applicable threats to its piping system
    4. Identify and implement appropriate practices to prevent, and mitigate risk from applicable threats
    5. Develop and monitor performance measures to allow it to evaluate the effectiveness of improvements implemented
    6. Periodically evaluate the effectiveness of its program and make adjustments dictated by it evaluation
    7. Periodically report to the jurisdictional regulatory authority a select set of performance measures
  3. Risk control practices
    1. High level, risk-based, performance oriented Federal regulation
    2. No need for HCA’s or identified sites
    3. Vehicle damages to gas facilities constitutes 11% of the incidents from 1999-2003
    4. 66% of vehicle damage to gas facilities occurs to meter set assemblies
    5. Vehicle damage to gas facilities and other outside forces affecting gas facilities
    6. Insufficient data to develop a coherent understanding of the nature of the problem
    7. Design, construction, installation and initial testing regulations should be effective in providing for integrity of the distribution facilities
    8. Current operating and maintenance sections should be effective in providing the elements necessary to maintain the integrity
  4. Excavation Damage
    1. Constitutes 38% of the incidents form 1999 – 2003
    2. Need to concentrate of excavation damage
  5. Risk = Likelihood * Consequence

Risk Control Practices - Likelihood

    1. Excavation damage prevention
    2. Risk-based replacement program
    3. Corrosion control – additional readings, recoating, CIS
    4. Over pressure protection
    5. Vehicle protection

 

Risk Control Practices – Consequence

a.      Effective Leak management

b.      Additional leakage surveys

c.      Odorization

d.      Additional patrols

e.      Emergency response

f.        EFV’s

  1. National Performance Measures
    1. Incident data
    2. Status of the operator in complying with the required elements of the program
    3. Amount and ratio of pipe that is not considered “state of the art”
    4. Status of the operator in meeting the requirements of the LEAKS effective leak management program
  2. Company Specific Performance Measures
    1. Operator-specific performance measures are unique and must match the specific risk control practices of its distribution integrity program
  3. Reviewing Written Plan
    1. The interval for reviewing the operator’s written distribution integrity management program should be a t intervals not exceeding 15 months, but at least once each calendar year
  4. Evaluation of IMP Program
    1. The operator should complete an evaluation of its distribution integrity management program periodically.
  5. Excavation Damage WG – 9 point plan for excavation damage
    1. Enhanced communication
    2. Partnership of stakeholders
    3. Performance measures for mark outs
    4. Partnership in employee training
    5. Partnership in public education
    6. Enforcement agency’s role
    7. Fair and consistent enforcement
    8. Use of technology to improve the process
    9. Analysis of data to continually evaluate/improve program effectiveness

 

GPTC ACTIONS

  1. Integrity Management Gas Piping Technology Committee
    1. B31.8 became Part 192-1970
    2. GPTC established 1970
    3. 1st edition of guide – 1970
    4. Developed guide material for distribution IMP
    5. Held off at request of states
    6. After Phase 1 report
  2. DI Guidance TG
    1. Still in draft
    2. General overview
    3. Consensus document
  3. 7 Elements of Distribution IMP
    1. Know the distribution systems and how these are operated and maintained
    2. Identify threats to address associated risks
    3. Evaluate and rank groups based on associated risks
    4. Identify and implement appropriate measures to manage risks
    5. Measure performance and monitor results
    6. Periodically evaluate and improve the program
    7. Make periodic reports to government agencies as required
  4. Know the Distribution Systems
    1. Material and specification
    2. Construction conditions
    3. Corrosion control systems
    4. Results of inspections and surveys
    5. Documentation of leaks and maintenance
    6. Geologic Conditions
    7. Operating Pressure
    8. Incident reports
  5. Identify Threats and What Happens when a Treat is Realized
    1. Corrosion
    2. Natural forces
    3. Excavation
    4. Other outside force damage
    5. Material or welds
    6. Equipment
    7. Operations
  6. Risk Evaluation – EFV’s
    1. Determine feasibility
    2. Conduct risk evaluation
  7. Risk Management Techniques and Practices

 

 

Thursday, November 2, 2006

 

Gas Gathering Line Definition Issues/Low Stress Liquid Pipelines Regulations – Dewitt Burdeaux – PHMSA Training and Qualifications

 

  1. High Risk Threats
    1. Corrosion
    2. 3rd party damage
  1. Transmission Distribution
    1. Costs
  2. Tiering the Regulations for High Pressure Pipelines
  3. No Historical Backing to Dispute Claims
  4. One-day Workshops
    1. Richard Sanders sent out email offering workshop
  5. Liquid Program
    1. A mandate to clear-up the regulatory issues associated with prude oil gathering.

 

American Public Gas Association Presentation – Bert Kalisch

 

1.      APGA and Public Gas Systems

a.      937 systems in 36 states

b.      5 million customers

c.      21,100 employees

d.      116,000 Mile of Main

e.      Systems size (meters) 54 – 500,000

f.        Larges cities – Philadelphia, Richmond, San Antonio, Memphis, Colorado Springs

2.      Complimentary Organizations

a.      APGA Research Foundation

b.      APGA Security and Integrity Foundation

c.      APGA Insurance Group

3.      Priority for 2007

a.      Safe and reliable delivery of natural gas at a fair and reasonable price

b.      Pipeline safety reauthorization

c.      Greater market transparency

d.      Diversity for electric generation

4.      Methane Hydrates

a.      Long-term solution: Methane Hydrates

b.      Like fusion – technology not yet there

c.      U.S. estimate of MH: >200,000 Tcf

d.      Since the beginning of time, man has not intentionally burned more than 4,000 Tcf

5.      Trading

a.      Futures (~10% of the trades) are regulated

b.      Over the counter market (~90% of the trades) is not

6.      Priorities for 2007 – Operations and Safety

a.      Distribution integrity – SHRIMP

b.      Follow-up on RP-1162

c.      Mutual aid

7.      RP-1162 Concern

a.      PHMSA had utilities submit plans for review

b.      PHMSA contracted PCCI Marine and Environmental Engineering

c.      PCCTI used an RP 1162 checklist

d.      Where PCCI found a “deviation” from RP 1162, it was cited and the relevant section in RP 1162

e.      PHMSA has forwarded these “reports” to the states with directions to “Please discuss these deviations from RP 1162 with the operator

f.        Upon conclusion of the discussions, the state is to LOGON to the Public Awareness database and code each of these deviations as “Acceptable” or “Challenged”.

g.      There appears to be no opportunity for a state agency to challenge whether a “deviation” really exists or explain why a deviation might be accepted

h.      Accepting a deviation may appear to demonstrate that a state is not enforcing the rule

i.         If the checklist and PCCI’s analysis were accurate, this would be less of a concern, but – the checklist goes beyond what RP 1162 requires

j.         PCCI also discloses no knowledge of RP 1162 or utility public education practices

k.       This raises a questions about PCCI’s ability to apply a knowledgeable and reasoned judgment to apply the checklist to the submitted plans

l.         PCCI cited deviation in the APGA model plan because we labeled the section containing the statement of management commitment and support “Public Awareness Policy”

m.    APGA has now changed its model plan to read “Management Commitment and Support”

8.      APGA Security and Integrity Foundation

a.      To promote the security, operational integrity and safety of small operators

b.      To help prevent, mitigate and/or repair damage caused by accidental or deliberate events

c.      To provide education, training, materials and tools to enhance the ability of small operators

9.      SIF (Security and Integrity Foundation) Board of Directors

10.  Evolution of SIF

11.  Cooperative Agreement: K1

a.      Qualify 1000 individuals

b.      Build a database

c.      Newsletter

12.  K1: Phase 4

a.      Sessions began in September

b.      Held sessions in Alabama, New Mexico, Mississippi

c.      Sessions are scheduled for Arkansas, Tennessee

d.      To date, SIF has qualified 175 employees

13.  Cooperative Agreement: K2

a.      SHRIMP

b.      Identify more covered tasks

c.      Prepare to offer training on SIF tasks

14.  How can NAPSR Help?

a.      Continue to participate

b.      Disseminate information

c.      Expertise

d.      Participation

e.      Promotion

 

APGA Security and Integrity Foundation – Gerry Lee – OQ Program Manager

 

1.      Report Language – FY05 Appropriations Bill

a.      Small gas distribution systems

2.      2005 PHMSA Cooperative Agreement

a.      Agreement started September 15, 2005

b.      One year term

c.      Very smooth and expeditious process

d.      First years focus – operator qualification

3.      SIF Summary of work

a.      Phase 1 – Identify B31Q covered tasks

b.      Phase 2 – Assess training and evaluation materials

c.      Phase 3 – Acquire/develop/modify training and evaluation materials

d.      Phase 4 – Conduct training and evaluation

 

4.      2006 PHMSA Cooperative Agreement

a.      Distribution Integrity Management

b.      Operator qualification

5.      SIF – NAPSR Partnership

a.      Work with SIF in scheduling qualification

b.      Input on locations to conduct classes

c.      Identify possible local trainers/qualifiers

d.      Input to the operator database

e.      Inform and encourage your operators to take advantage of the opportunity

 

Arkansas One Call Center Presentation – Roger Cox, Arkansas One Cal Center

 

1.      Arkansas Utility Protection Services, Inc.

a.      One-Call’s measured response to member frustrations

b.      ARKUPS – wholly owned and not for profit subsidiary of AOC

c.      The mission was to provide a quality line locating service at a fair and stable price

d.      The reach far exceeded the vision

2.      Mapping

a.      The dilemma – updating the land base

b.      Advantage – AOC//ARKUPS

c.      120 Vehicles – 3.5 million miles/year

d.      GPS devices installed on each vehicle

e.      Uploaded to FTP site

f.        Corrections downloaded back to field

g.      64/75 counties are verified using GPS

3.      ACO//ARKUPS New Project

Effective locating training

a.      Better understanding of AOC

b.      Develop greater technical skills

c.      Importance of communication

d.      Defining “damage prevention” as much more than just being in compliance with the law

4.      Arkansas One-Call

a.      Mandatory membership

b.      Arkansas regulatory pipeline program

c.      NJUNS

d.      Developing relationships to create the future we want to see

 

811 Implementation – Khrysanne Kerr, Celeritas Technologies

 

  1. Overview of 811
  2. Goals

Reduce damages

    1. General public resonates with 911
    2. National awareness campaign
    3. Crosses state lines
  1. Logo Development

Request for Proposal

    1. Eight firms submit proposals
    2. RBMM selected
    3. www.call811.com
  1. National Awareness Campaign
    1. Request for proposal
  2. Fleishman Hillard, Washington DC – selected to handle the campaign
    1. Market research
    2. Strategic plan
    3. Campaign elements
    4. Strategic launch
    5. Key messaging
    6. Launch planning
    7. Material development
    8. Communications
    9. Building the campaign
  3. Market Research

Results from a National Survey of Adults and Professional Excavators

  1. Additional Market Research
    1. One call center executive directors
    2. CGA stakeholders
    3. NTDPC
    4. General public
    5. Professional excavators
  2. Research Objectives
    1. Fine-tune language and messaging
    2. Garner reactions and specific feedback
    3. Improve understanding of why most people do not call before they dig
    4. Determine if people know when to call
    5. Test general awareness of local call-before-you-dig services
  3. Research Methodology
    1. A total of nine focus groups were conducted across seven different cities
  4. Key Findings about Communicating 811
    1. Homeowners are already aware of call-before-you-dig services
    2. Additionally, homeowners generally understand why it’s important to get their lines marked before starting a digging project
    3. Homeowners know who to call and they know why it’s important.
  5. CGA 811 Stakeholder Summits

Friday November 17, 2006 – Omaha, NE

Wednesday, November 29, 2006 – Spokane, WA

            Tuesday, December 5, 2006 – Phoenix, AZ

            Thursday, December 14, 2006 – Fargo, ND (tentative)

  1. What Can I Do?

Visit www.call811.com

Incorporate 811 into 2007 marketing plan

Share the message

Call Center involvement

Wait until after April 2007

 

CGA DIRT Program – Annemarie Robertson for Brian Tooley, Verizon Business

 

1.      Dirt (Damage Information Reporting Tool)

What is it?

a.      DIRT is a secure, web application used for collecting and reporting of underground damage information

b.      Anonymity and confidentiality are paramount issues amount among stakeholders

c.      4 ways to submit data:

Individual incidents reported singularly on the damage report form

Bulk data submission via the ADL (Automated Data Loader)

Universal front-end loader

Virtual private DIRT

2.      Virtual Private DIRT – What is it?

a.      Secure, isolated copy of the DIRT application

b.      Dedicated database space

c.      Customized look & feel

d.      Flex field customization

e.      Enhance public safety

f.        Supports industry stakeholders

g.      Provides answers

3.      DIRT

a.      Enhances public safety

b.      Supports industry stakeholders

c.      Provides answers

4.      Path Forward: CGA Focus

a.      811

b.      Compliance & enforcement

c.      Virginia pilot program

 

Potential Hazards with Sewer Laterals – Dan Weakland and Walt Kelly – NPL

 

1.      Who is NPL?

a.      The safe installation & maintenance of reliable energy distribution systems

b.      Over 500 crews

c.      Over 2600 employees

d.      Operate in 20 states

e.      One of the largest users of One Cal centers in U.S.

2.      The Issue

a.      The often forgotten underground world

b.      Utilities are installed using trenchless technology

c.      Gas line + sewer line + rotary rooter = disaster

d.      The exposure: low frequency high severity

e.      The big concerns: catastrophic human tragedy and huge costs

f.        Sewer lines need to be marked

g.      Installation solutions

3.      Status Today

State Legislation

a.      States that have updated one call laws: Arizona, Georgia, Minnesota, Nevada, Oregon, Virginia, and Wisconsin

b.      States updating laws: Arizona, Georgia, Kansas and Nevada

c.      States with champions starting grass roots efforts: California, Colorado, Indiana, Tennessee, Texas, and Washington

d.      Good state prospects in need of a champion: Illinois, Iowa, Maryland, Ohio, and Oklahoma

LDC Policies and Procedures

a.      Large west coast LDC has policy of requiring and enforcing that every main and sewer lateral be day lighted before excavating

b.      Midwest LDC has policy of requiring and enforcing that all sewers are pre-located before gas is introduced

e.      Southeast LDC had completed a system review using cameras

LDC Policies and Procedures

a.      American Gas Association

b.      Common Ground Alliance

c.      Distribution Contractors Association

d.      National Underground Contractors Association

e.      North American Society for Trenchless Technology

What is Needed?

a.      Local champions to change state laws

b.      Government regulatory agencies to get involved in legislative changes and enforcement

c.      More LDC’s to take up the cause

d.      For all to understand that this is not just a contractor problem. It is an Industry Safety Problem

 

 

NAPSR Closed Session (separate minutes)

 

 

Don Martin adjourned the 2006 National NAPSR Meeting