1. HCAs & Pipeline Assessment Intervals Is There a Need for Change? Richard B. Kuprewicz President, Accufacts Inc. For Pipeline Safety Trust New Orleans Conference 11/20 & 11/21/08

2. Is There A Need For Change? The Answer is yes! Different yes for many sides/factions in this room Will briefly present Short regulatory perspective Summary on integrity inspections Weaknesses in present approach Recommended changes 2

3. Current Federal Regulations Liquid Integrity Management (49CFR195.452) Phased (via Large / Small Operator) Regulation in 5/29/2001 & 2/15/2002 7 year Baseline assessment Large operator 50% by 9/30/2004, all by 3/31/08 Small operator 50% by 8/16/2005, all by 2/17/2009 ~ 5 year maximum reassessment interval HCA determined by “could affect” Captures ~ 43% of liquid transmission pipeline mileage or ~ 73,000 miles Gas Transmission Integrity Management PSIA of 2002 10 year Baseline Assessment 50% inspected by 12/17/2007, 100% by 12/17/2012 7 year reassessments PHMSA Regulation in 2003 (49CFR192 subpart O) Maximum Reassessment Interval ranging from 7 to 20 yrs based on stress levels HCA determined essentially by C-fer empirical correlation sweep Captures about 7% of gas transmission pipeline mileage or ~ 19,000 miles 3

4. Anomalies Requiring Immediate Repair Liquid Transmission Pipelines Metal Loss > 80% nominal wall thickness Remaining strength calc burst pressure at anomaly < MOP Dent on top of pipe with stress concentrator Dent on top of pipe > 6% pipe diameter Anomaly in evaluator’s judgment requires immediate repair Gas Transmission Pipelines Remaining strength calc failure pressure at anomaly < 1.1 x MAOP Dent on top of pipe with stress concentrator Anomaly in evaluator’s judgment requires immediate repair 4

5. Liquid - Schedule Repairs 60 – Day Conditions Top dent > 3% diameter Bottom dent with stress concentrator 180 – Day Conditions Dent > 2% diameter affecting curvature at girth/longitudinal seam Top of pipeline dent > 2% diameter Bottom of pipe dent > 6% diameter Calc showing operating pressure less than MOP at anomaly Metal loss > 50% of nominal wall Predicted metal loss >50% of nominal wall at another pipe crossing, widespread circumference or could affect girth weld Confirmed crack indication Corrosion of or along a longitudinal seam Gouge or groove > 12.5% of nominal wall thickness Other Conditions that may need to be scheduled E.g., anomaly in or near a casing, crossing, or near another pipeline 5

6. Gas - Schedule Repairs 1 – Year Conditions Dent on top of pipe > 6% diameter Dent > 2% diameter affecting pipe curvature at girth or at longitudinal welds Monitored Conditions Not Requiring Repair Bottom Dent > 6% of diameter Top Dent > 6% of diameter not exceeding critical strain levels Dent > 2% diameter affecting curvature at girth or longitudinal welds but not exceeding critical strain levels 6

7. 7 From PHMSA web site http://primis.phmsa.dot.gov/iim/index.htm

8. 8 From PHMSA web site http://primis.phmsa.dot.gov/gasimp/PerformanceMeasures.htm

9. Changes Needed In Current IM Approach U.S. Regs lead the world in area of Integrity Management (IM) Some areas build off technology developed in other countries U.S. approach is “Model One” - first of its kind U.S. has more transmission mileage than other top fifteen countries combined! Since inception of IM rule through 2007 - Tens of thousands of repairs have occurred on U.S. pipelines Liquid Pipelines ~ 26,000 repairs in HCAs, another ~ 59,000 outside HCAs Gas Transmission ~ 2,500 repairs in HCAs, non HCA repairs not required to be reported Utilize Learning Curve from First Cycle of IM Assessments Be aware history doesn’t define the future Always room for improvement Need public report repairs by anomaly cause Limitations / traps in consensus standards Reward those doing the right thing 9

10. On Setting Regulatory Reassessment Intervals For corrosion Address the different risks of selective vs. general corrosion Selective corrosion can easily substantially exceed 12 mils/yr Burst calculations models moot if assuming wrong corrosion rate! PHMSA knows the difference between general and selective corrosion Respect that PHMSA may be prevented from disclosing corrosion rates in certain cases Other time-dependent anomalies need to be addressed Move to newer stronger pipe (X-70, X-80, X-100, X120) Delayed third party damage failure much more likely Stress loading (i.e., land movement) complications Reassessment interval changes must be based on sound science and sound assumptions Are field realities in sync with assumptions in consensus standards? Given uncertainties of present technology, a safety margin is still required for re-inspection intervals Illusionary more “bad” inspections (whether mileage or frequency) are not better than fewer good inspections matching the risks! 10

11. On Addressing HCAs and Public Confidence Expand HCAs Increase the pipeline miles prudently inspected/re-inspected For Liquids Address other sensitive areas beyond current HCAs definitions of: commercial navigable waterways, populated areas, unusually sensitive area Capture High Impact and Risk Areas E.g., sensitive parklands / protected areas For Gas Address the “exotics” where C-fer zone is way too small More Public Transparency Required PHMSA must report damage database by anomaly type Mandate reporting of all pipe repairs, even beyond HCAs, by type of damage 11