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Extending Inspection Intervals 1-18-08

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					                                                  1
  UNITED STATES DEPARTMENT OF TRANSPORTATION
               PUBLIC MEETING ON
EXTENDING GAS INTEGRITY MANAGEMENT REASSESSMENT
                   INTERVALS

                 Palomar Hotel
              Arlington, Virginia

           Friday, January 18, 2008
                   8:40 a.m.

                    Participants:

      JEFFREY D. WIESE
      Pipeline and Hazardous Materials Safety
       Administration

      MIKE ISRANI
      PHMSA

      ZACH BARRETT
      PHMSA

      DARON MOORE
      El Paso Natural Gas

      LOIS EPSTEIN
      LNE Engineering and Policy

      RICHARD B. KUPREWICZ
      Accufacts, Incorporated

      TERRY BOSS
      INGAA
      JERYL L. MOHN
      Panhandle Energy

      BOB TRAVERS
      Spectra Energy

      DAVID ADLER
      NiSource

      JOHN BRESLAND
      Environmental Protection Agency

      ANDREW LUU
      American Gas Association
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                         A G E N D A

AGENDA ITEM:                                     PAGE:

Welcome and Opening Remarks                         3

     Jeffrey D. Wiese

Background                                        17

     Mike Israni

Proposal: How Will We Accomplish and Implement    28
Change?

     Zach Barrett

Question-and-Answer Session                       45

Findings to Date                                  58

     Terry Boss

Operator Utilization

     Bob Travers                                  76
     Spectra Energy

     Daron Moore                                  79
     El Paso Natural Gas

Question-and-Answer Session                       89

Conclusion                                       103
     Jeffrey D. Wiese




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1                       P R O C E E D I N G S

2                                                      8:40 a.m.

3                    Welcome and Opening Remarks

4                         Jeffrey D. Wiese

5                (PowerPoint presentation.)

6                MR. WIESE:   Again, good morning, everyone.

7    My name is Jeff Wiese.    I'm the associate administrator

8    for pipeline safety at DOT.    I'd like to welcome you on

9    behalf of DOT to our meeting this morning.      I'm not

10   going to run through the administrative moment that we

11   covered just a second ago.    To be honest with you, I

12   think we have plenty of time to cover our agenda today,

13   so I want to relieve any anxieties you might have at

14   that.    But we won't go over the administrative moment

15   again.

16               If I can, just as a prelude to begin talking

17   about this, as I of course had a moment to talk to a
18   few people out here having coffee, and knowing that

19   I'll speak a lot faster now for all the coffee that

20   I've had, I did notice that a lot of people we have

21   done business for quite a while from all sides of the

22   spectrum.   My esteemed colleague here from INGAA asked

23   me for something, and I'd like to honor that.      He said,

24   how many people in the room have been involved from the

25   days of risk management forward.
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1                 Take a look around.    I mean, there's a lot of

2    people in this room who have been involved in the

3    enterprise since the days of risk management.       I would

4    say that the enterprise -- what I'd like to start out

5    with, just my introductory comments to you, is that I

6    think we've worked very well together.       We've done a

7    lot of work together.     We've made a lot of progress

8    working together, all sides pitching in.

9                 The state people are here.    They were part of

10   that.    The industry was here.    The advocacy groups were

11   here.    So I think we've done good work together and

12   we've come a long way.    Not to say things are perfect.

13    We have a lot of work to do.      But I think things are

14   perfect -- or, not perfect.       Sorry.   That's the coffee.

15    So we can thank Starbucks.    Let me back up and start

16   over.    You can strike those last two sentences.

17                There's a lot of work yet to be done, but I
18   think we've made good progress.      Is that one better?

19   Sorry.    Okay.

20                So with that said, I was also commenting to

21   Terry as we chatted over this issue that remember it

22   wasn't too long ago that there was a fairly significant

23   loss of confidence in the work of the enterprise

24   getting together.    We had several very high-consequence

25   accidents.    There was clearly room for improvement
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1    after we saw those things.

2               We set about, what's the process that we need

3    to use in order to make that kind of improvement.        The

4    simple solution at that time would have been, and trust

5    me, after what we've gone through and looking

6    backwards, it would have been far simpler to have

7    instituted a pig-and-dig rule, as we say sort of

8    derogatorily.   Pig and dig.   It's a lot easier to write

9    a rule like that.

10              But it's not about just testing.    I think

11   that's the case I'd like to make for you at the outset.

12    I'll run through some slides and make it for you

13   again.   But in the time-honored tradition of telling

14   you, I think it takes equal contributions from the

15   pipeline and the technology side.   So as I acknowledge

16   my friend from Texas, points about science, it's

17   crucial knowing that and having an understanding of the
18   science and the technology involved in this.

19              But it also involves contributions from the

20   process side, which is where I think we've made a heck

21   of a lot of gain.   And the people side, where I'd also

22   make the case where we've made a big gain.

23              So with that sort of prelude to telling you

24   that I think integrity management has made a

25   significant contribution in our ability to safely
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1    manage the natural gas transmission pipeline system, I

2    just thought I would run through for you really quickly

3    the goals we set out at the very beginning of integrity

4    management, even before gas integrity management.        Mind

5    you, we had a number of years of experience working in

6    the hazardous liquid field before we got to gas.

7              The goals were pretty much the same.      We

8    wanted to start out for sure to accelerate integrity

9    assessments of gas pipelines in high-consequence areas.

10    That was more of the pig-and-dig side of this.      But as

11   importantly I guess I should say, we wanted to improve

12   integrity management systems within companies.    The

13   point of that exercise is pig-and-dig will provide you

14   a certain amount of protection for a certain amount of

15   time, but we want to make sure that all companies, not

16   just the leading companies but all companies, know how

17   to do this on a continuous basis.   They have the
18   processes set up in place to give you that return on

19   value constantly.

20             I think it was crucial for us to improve the

21   government's role in this, both at a state level and a

22   federal level.   I see a lot of our state partners in

23   the room here, and I know that they would agree we

24   would have worked pretty hard on that.   We've done a

25   lot of training of people.   We've had a very rigorous
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1    oversight program.   Some might say -- what's your

2    favorite word in the state government now?      Protocols?

3     Anyone here?   Do I see a show of hands?

4               I walked into a state meeting at one point,

5    and I'll play with my friends from the states, and they

6    said as I walked in -- they had me stand outside, and

7    when they finally let me in, the slide on the wall,

8    what did it say, Don?   Do you remember?    "No more

9    protocols."   Yeah, okay, remember that meeting?

10              So that was a -- what?    Yeah, yeah, they love

11   them.   We know you love them.   But they were constantly

12   saying "No more protocols."

13              At any rate, that's a point of saying we've

14   worked pretty hard together to make sure that we had a

15   rigorous approach to oversight.     It's my hope and my

16   belief that we've worked together in order to shore up

17   public confidence.
18              Again, not knowing who I'm speaking to here.

19    I know a lot of you, but there are some I don't know,

20   and I don't know where you're from.

21              I will say that there's a lot of information

22   on this program available on our website.     That was

23   another thing we did to try to push the transparency of

24   what we were doing, was to publish even our inspection

25   protocols on the website.     So if you want to know more
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1    about how we're approaching it, what gas integrity is

2    about, how we've proceeded and what we're

3    accomplishing, even at a performance metrics level,

4    please use this website.     It will be a matter of the

5    record.   The presentation will be there if you need it.

6                 I think, if you go to our new website, the

7    PHMSA.DOT.gov, you would be able to find your way

8    there.    I'm still learning that one because I knew the

9    old website so well.

10                Okay.   I'm not going to spend time and read

11   all these bullets to you, but I really wanted to give

12   you a sense of this beyond the pig-and-dig concept.         A

13   lot of what we're doing depends on process,

14   establishing processes to manage for safety.     So all

15   I'm going to do really for this slide and the next

16   slide is just show you the elements of the integrity

17   management program the companies have to work on.
18                This has been a pretty heavy lift for

19   companies.    In a lot of cases, I think many companies,

20   and the leading companies for sure, had many of these

21   elements in place.      There's another page to this, and I

22   think it's switched.     Yeah, that's the continued page.

23                All of these have to be in place, and PHMSA

24   and our state partners audit against all of these

25   program elements.     So I'm just pointing them out.   I'm
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1    not going to spend much time on them.

2              It's a fairly extensive effort.    This is not

3    an easy job either for the companies or for ourselves,

4    but I think we've made good progress.

5              Just quickly, some stats.     The overall system

6    -- I'm rounding, so forgive me for rounding.      Roughly

7    290,000 miles of transmission pipeline, 19,000 of which

8    is located in a high-consequence area.

9              If I can, I'd like to put something on the

10   record to say that I've had dialogue with a lot of

11   people, including the U.S. General Accountability

12   Office -- I think that's their new title -- about this,

13   the notion of only 19,000 miles being in high-

14   consequence areas.   I'd just like to say the integrity

15   management program was always intended to be a

16   supplement.   It is not a replacement for, it is a

17   supplement to all of the other protections that have
18   been in place for years.

19             Interestingly enough, and this was validated

20   by the General Accountability Office, which we'll go

21   into that report a little bit more later, we used our

22   GIS -- because I was a little concerned about that

23   being such a low number.   Was this an adequate

24   supplement.

25             We used data from the Census Bureau and went
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1    through and used our GAS to look on a 1,000-foot buffer

2    nationwide around all the gas transmission pipeline.

3    What does that mean to people.    Roughly two-thirds of

4    the people in this country who could have been affected

5    by a pipeline failure on a transmission pipeline lived

6    in those high-consequence areas.

7                So the point of that is to say people are

8    disproportionately located in these high-consequence

9    areas.    So while 19,000 in a relative sense may be

10   small, for the job that it was designed to do, to

11   provide added protection for people, I think it's

12   producing a lot of value.

13               Progress being made so far to date.   Over

14   12,000 of those miles have been assessed to date by the

15   companies, and over 70 -- in the non-HCA, the point I

16   should make is the supplemental benefits again to the

17   integrity management assessments is they're far wider
18   than just the HCAs.    The companies can't just assess,

19   generally speaking, within an HCA.    So it's really

20   having a multiplier effect.

21               Another thing I'd like to point out is I'd

22   like to say that a lot of significant pipe anomalies

23   that were there have been identified by the companies

24   and they have been repaired.    Roughly 2,000 conditions

25   so far.
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1              I guess I didn't put it on this slide.         One

2    of my slides points out the effective date of this rule

3    was, what, four years ago.    I think we're at four.      So

4    really, with only four years into this program, there's

5    been substantial work done already, and a lot of the

6    anomalies in the non-HCA pipe have also been removed.

7    No company that I've met worth their salt is going to

8    want to identify an anomaly, HCA or not, that's

9    significant and not repair it.    It's not in a company's

10   interest to have a failure on a pipeline system.

11             Okay.    So at any rate, I've just got a couple

12   more slides.    I mostly wanted to say and sum up on some

13   of these things that I think the baseline assessments

14   have served their purpose in integrity management.

15   They will continue to serve their purpose.       Major

16   problems are being found and fixed.    I do believe the

17   pipe is in better condition as a direct result of this.
18             I think the companies probably, importantly,

19   have a lot more data on their pipeline system.       As we

20   spoke yesterday with some folks, we are pushing a data-

21   driven, risk-focused agenda.     The companies need to be

22   able to document and defend their decisions.       Our

23   oversight is really going to be pushing on that.         Why

24   are you making that decision.     What's your basis.      So I

25   think the companies are in a better position to do that
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1    now, having acquired a lot of data, and I think that

2    they understand the risks that they're facing.

3                 We talked a little bit about the process side

4    of this, and so I'd like to say a lot of progress has

5    been made on that.    A lot of the enforcement actions --

6    I think I referenced enforcement a bit -- that we've

7    taken really were focused more on the process side,

8    making sure that companies had adequate processes in

9    place.   I think they've worked hard on procedures and

10   processes.    I think we've added a lot of benefit to the

11   quality end and, clearly, documentation and records are

12   in better shape.    That's one of the great sources we

13   and others have, proving that I can follow direction

14   occasionally.

15                The other part of this I would say, as I

16   referenced earlier, we've spent a lot of time with

17   state and federal inspectors, a lot of training.      Most
18   of our inspectors have nine intensive courses just to

19   be basically qualified.    We added five more, as I

20   recall, for all of our gas inspectors and spend a lot

21   of time in a team environment trying to make sure we're

22   making the best possible decisions we can make.

23                So our senior inspectors I think are much

24   better prepared to do oversight than they were prior to

25   this, and having a team approach really allows us to
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1    bring people with different skill sets together to make

2    a better holistic argument.

3               Our progress to date, at least at the federal

4    end, which I have good statistical data for, is we're

5    virtually done with the oversight for companies that

6    have HCA mileage.   So that process has been done.

7    There have been 39 enforcement actions taken to date,

8    but as I said to you, the bulk of those have to do with

9    process and procedure, pushing the company to have the

10   processes and procedures in place that will continue to

11   add value, continue to help shore up our confidence

12   that the companies know how to manage their assets.

13              Also, clearly, we have a few people in the

14   room, although I can't spot them when I'm standing up

15   in front of an audience, from standards organizations

16   and industry who work on the standards groups, as well

17   as state regulators and federal who are in there.
18   We've done a lot of work to advance new technologies

19   and tools that are available to companies, but I would

20   also say to shore up standards.   The standards are

21   growing.   We continue working with the standards

22   organizations.   As I made a case to some of you

23   yesterday, we've brought them closer in.

24              We have formed a memorandum of agreement with

25   the standards groups to bring them into the research
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1    program.   So they're learning about developments at the

2    earliest possible time that can influence and shore up

3    the quality of the standards that we have.

4               These are just some of the technologies that

5    we've been working on collaboratively.

6               I think I made this case earlier.    Really,

7    just to shore it up, some of the standards developed as

8    we approached Gas IMP dealt with the qualifications of

9    people and their ability to deploy the tools.     Again, I

10   made the case earlier about all three:   having the

11   tools available for the pipeline, having a process to

12   deploy those tools, and people who are qualified to do

13   it.

14              I'd like to say I think that the Gas

15   Integrity Management Program is really positively

16   impacting the operators and the reliability of what

17   they're doing.   It's helping them allocate capital to
18   highest risks, which I think at the end of the day is

19   what we're trying to do, reduce threats to the public

20   and to the environment and to make sure that the

21   highest risks are dealt with first.

22              Overall I'd like to say that I think you're

23   reducing corporate risk.   Again, no company wants a

24   failure, and it's fairly significant consequences above

25   and beyond what happens with us when any company has a
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1    failure.

2               We will continue to foster this continuous

3    learning environment where companies can hopefully, and

4    regulators, can continue to make better decisions about

5    what we're doing and how we manage and achieve our

6    safety and environmental goals.    I would say that

7    integrity management really has fostered a much deeper

8    dialogue, perhaps deeper than some might wish, but a

9    much deeper dialogue with the industry than we had

10   prior to it.

11              So just in summary for my part of this, I

12   appreciate your coming today and giving us an

13   opportunity to talk with you.    I appreciate those of

14   you who are taking your time to come and share your

15   point of view with the crowd.

16              I mostly wanted to say to you what I've tried

17   to say repeatedly around integrity management.   It's
18   not about just the science.    That's crucial and we have

19   to continue to make progress on that, not just about

20   the pipeline and what you know about it.    It clearly

21   involves equal contributions from the processes that

22   you put in place to manage and to deploy your people

23   and having people who are qualified to do it.

24              In closing, I'd like to say I actually

25   believe that the enterprise, not just the regulator,
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1    not just the industry, but the enterprise is in a much

2    better position to judge the merits of a science-based

3    rationale than we were five years ago.    This has been

4    validated independently.    We'll hear more about it.

5              The General Accountability Office has

6    validated this themselves.    They did a pretty

7    exhaustive year-long audit of us, spoke with a lot of

8    people in industry, a lot of vendors, and some time ago

9    said that they preferred the science risk-based

10   approach to setting assessment intervals.

11             The administration had made that proposal, as

12   some of you know, in the reauthorization of the

13   Pipeline Safety Program that happened in 2006.

14   Congress wasn't ready to take it on at that time.    They

15   came back and asked GAO to do that audit and asked us

16   to comment on it.    I think we've both commented

17   favorably and said we're in a much better position to
18   do this now, trying to give the confidence to the

19   Congress to give DOT the authority to prescribe risk-

20   based regulations.

21             Until the day that that happens, really we

22   don't have that option, so we're gathered together

23   today to talk about the notion of special permits.      How

24   can we use authority that we have to deal with this

25   challenge of the seven-year reassessment interval on a
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1    more science-driven basis.

2              So again, I think that really concludes my

3    remarks, and I appreciate your listening and your

4    patience for our late start.    So, thank you very much.

5                            Background

6                            Mike Israni

7              (PowerPoint presentation.)

8              MR. ISRANI:   Good morning.

9              PARTICIPANTS:   Good morning.

10             MR. ISRANI:   I'm Mike Israni.   I'm senior

11   technical advisor at PHMSA Pipeline Safety. This

12   workshop is about special permits, consideration for

13   seven-year reassessment intervals.    So the best way to

14   begin would be for us to tell you how we arrived at

15   these reassessment intervals.

16             So what I will cover in my presentation would

17   be what assessment intervals Congress mandated in the
18   Pipeline Safety Act of 2002, how PHMSA determines the

19   reassessment intervals and the deviation from those

20   reassessment intervals that we allow, what the General

21   Accounting Office audit report says about these

22   reassessment intervals, what PHMSA's position is on

23   those seven-year reassessment intervals, and finally,

24   I'll also show you a flow chart that we use for the

25   maximum allowable operating pressure about the
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1    procedure to go about special permits.

2               Special permits are the same thing as the

3    waivers currently defined in our regulations.    It's no

4    different, it's just a different term we use.    The key

5    difference being here that, normally in the waivers, we

6    have individual waivers that come to us and we put

7    those in the Federal Register and ask for comments.

8    And based on the comments and on our own evaluation we

9    respond, and then we again have to go to the Federal

10   Register for those waivers.

11              In the special permits, we follow the same

12   procedure, except we can bundle a number of these

13   waivers together since this particular issue would

14   raise a similar situation with lots of companies.      So

15   we would bundle up, like on a monthly basis, whatever

16   requests we get from the industry.   We can bundle up

17   those and put the waiver in the Federal Register.
18              So let's look at first what assessment

19   intervals Congress mandated in the Pipeline Safety Act

20   of 2002.   Congress required PHMSA to ask the operators

21   to complete the baseline assessments by the year 2012,

22   and that was a 10-year baseline assessment -- was it 10

23   years or seven years?   Ten years, 10 years.   Fifty

24   percent of the high-risk assessments to be completed by

25   the year 2007.
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1                The Congress also put reassessment for each

2    and every pipeline to be completed at seven years, and

3    this was the issue that is bringing us to this

4    workshop:   reassessment for all the pipelines every

5    seven years.    Congress, in their mandate, told us about

6    these assessment intervals regardless of the stress

7    level, meaning there were no different maximum limits

8    on these intervals for low-stress pipeline or the ones

9    which are greater than 30 percent SMYS and 50 percent

10   SMYS.   They were all required to go to seven-year

11   reassessment intervals.

12               When we prepared the Integrity Management

13   Rule, we took the approach which determines assessment

14   intervals based on the risk.    We had evaluation

15   involved in this.    Our approach involved continual

16   identification of the risks to determine assessment

17   intervals, and we wanted these evaluations to be done
18   as often as needed.

19               Under the periodic evaluation, we also wanted

20   operators to consider the previous completed integrity

21   assessment results, their recommendation, results of

22   all the data that they collect normally from their own

23   inspections or from the history, to integrate all that

24   information and do the risk assessment.     They also had

25   to remediate -- all the decisions they make about
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1    remediation.    Also, they would consider additional

2    prevention and mitigating measures.

3                 Our assessment intervals also were based on

4    stress levels in the pipeline.    For the pipelines with

5    lower stress levels, we had longer intervals for them,

6    and for the higher stress levels, we had shorter

7    intervals for them.    But our intervals were in

8    coordination with the maximum intervals established by

9    the ASME B31.8 Supplement.    We followed the ASME B31

10   Supplement guidance on establishing these intervals,

11   which were done with -- based on the corrosion growth

12   of the defects -- the length of the pipeline.

13                But there was a constraint on the seven-year

14   statutory requirement that all operators had to comply

15   with.   This table shows you the reassessment intervals

16   we currently have in our regulations.    It shows you the

17   assessment method and different stress levels, what
18   assessment intervals they have.    For example, the

19   pipeline which is at or above 50 percent SMYS,

20   currently they have 10 years maximum reassessment

21   intervals.    For pipelines between 30 percent up to 50

22   percent, they have 15 years maximum reassessment

23   intervals, and below 30 percent SMYS they have 20-year

24   reassessment intervals.

25                But the seven-year reassessment interval
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1    mandated by the statute was required for all of these

2    at all stress levels.    So all of them had to comply

3    with those requirements, and we established something

4    called the -- direct assessment method which was

5    focusing on the corrosion component of it, meaning

6    internal and external corrosion at seven-year intervals

7    all the operators at all stress levels had to carry

8    out.

9              There were some concessions given to the

10   pipelines below 30 percent SMYS as they had certain

11   different electrical inspections in their chart, and we

12   have the tables in the Integrity Management Rule which

13   show how they go about doing those intervals in lieu of

14   seven-year reassessment intervals.

15             Now, I want to emphasize that these are the

16   maximum assessment intervals, and throughout the

17   regulation we made it very clear that a pipeline, when
18   they do their risk analysis and they find a pipeline

19   needs to be reassessed at a shorter interval than the

20   seven years, then they have to do that.    That's what

21   the whole risk-based program was based on.    These are

22   the maximum intervals.    Not every single operator

23   reaches the maximum limit to do these.    Some have to do

24   -- a certain segment needs to be done earlier than

25   this.
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1               There were certain deviations allowed in our

2    reassessment intervals.   For example, if there was a

3    lack of inspection tools available because of all these

4    operators using them at the same time, we were allowing

5    that flexibility of our reassessment intervals.     We

6    also allowed the flexibility to maintain the product

7    supply.   If there was a shortage of supply and if the

8    operator could demonstrate that the local product

9    supply -- we had to maintain that, there was some

10   flexibility given on that.   We wanted these waivers for

11   the flexibility to arrive at PHMSA 180 days before so

12   we can analyze those.

13              Deviation was also allowed for certain

14   pipeline operators who had an exceptional performance-

15   based program.   Operators with a mature program could

16   qualify to fall in that category would be the ones who

17   meet all the requirements that we had in the regulation
18   and above and beyond what currently was in the

19   regulation.   Those operators are given certain

20   flexibility on the maximum reassessment intervals,

21   except for the seven-year intervals.    Because of our

22   statutory requirement, we could not budge on that.       So

23   operators still had to do for corrosion the

24   confirmatory assessment every seven years.

25              The General Accounting Office, as Jeff
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1    mentioned, took a good two years interviewing all of us

2    at PHMSA, in industry, and vendors, the smart pig

3    vendors, and a number of other people, state folks.

4                From their study and survey, these are the

5    conclusions they put in their September 2006 report.

6    They concluded that the mandatory seven-year

7    reassessment interval is preserved.    They agree.    They

8    said that most operators have found few major problems

9    during the baseline assessment.   It wasn't very severe

10   -- that problems would be in the pipeline.

11               And they also found they were -- their

12   concern was about the availability of these resources.

13    So far they haven't found such a case.   This was from

14   the survey of the operators.   They also found that

15   serious accidents caused by corrosion are very rare.

16               In other words, they were trying to find out

17   was the seven-year mandatory intervals that was
18   focusing on the corrosion, wasn't as big an issue as we

19   had this.   So their overall conclusion was that they

20   were not really in favor of having this mandatory fixed

21   seven-year interval.   They thought it was too

22   restrictive, too conservative.

23               Now, what is PHMSA's position on the seven-

24   year interval.   Based on the GAO report as well as what

25   we had originally when we were developing the integrity
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1    rule based on the risk, we feel that the seven-year

2    reassessment interval was overly conservative.     So we

3    agree with the GAO report recommendations.

4                However, we -- the stature requires, and we

5    feel confident, that seven-year intervals would give us

6    some interim report on what's happening in the

7    pipeline.   Because this program is just beginning, that

8    will help to have that.   But it was going against the

9    risk management principles for why we did this program.

10    We had originally delivered the rule without

11   consideration of the seven-year reassessment interval.

12    So we believe that this -- we agree with all the

13   recommendations and the conclusions that the General

14   Accounting Office provided to us.   If we established

15   that risk-based criteria to qualify for not complying

16   with seven-year interval assessments, we want to

17   emphasize again that the operators would, from the risk
18   analysis, find certain testing or inspections to be

19   done earlier than seven years.

20               They would still be required to do that,

21   meaning we would have the proposed rule as -- our new

22   proposed rule, if you go with it, would have the same

23   requirement as what we had minus the seven-year

24   intervals but certain criteria that we still have

25   established to ensure that we are not making a wrong
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1    judgment here.

2              Some of those factors and the criteria --

3    jointly agree, and we have to form some kind of

4    committee or group that would work together to create

5    that criteria -- might be prepared for the maximum

6    allowable operating pressure.

7              I would now like to go into details of this

8    ILI or pressure test assessments only and -- corrosion

9    and make -- deal with factors that we have to

10   reconsider during the criteria establishment.

11             Finally, I've shown you here an example of

12   the special permits flow chart that we are currently

13   using for the maximum allowable operating pressure.

14   We're going to follow the same procedures, the same

15   process, of going with the special permits in the case

16   of the reassessment intervals.   Because it's a

17   mandatory requirement, we still have -- special permit
18   or waivers from the operators.

19             So when we receive the application for a

20   special permit, we'll need a hard copy to the associate

21   administrator of pipeline safety.   Copies need to be

22   also included for the regional director, the director

23   of engineering, and an additional copy for the staff.

24   A docket number will be established for each and every

25   request that we receive.   There will be a separate
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1    docket number for each and every request that we

2    receive.

3               So even though we put that special permit

4    notice in the Federal Register, we'll have a separate

5    docket number for each and every waiver.   The reason

6    for that is if someone objects to this and has a

7    comment on the individual docket number, they can go

8    and comment on that individual docket, or they can see

9    the detailed information about the individual request,

10   what the individual company requested in there, what

11   justifications they give.   So commenters will look at

12   the individual docket number and comment on that.

13              That procedure so far works fine.   We are

14   likely to follow the same procedure.

15              We will notify the operator when we receive

16   these copies, and as we go through all the information

17   the operator provides, we're going to ensure that all
18   the information that we need, the criteria that they

19   are providing, it meets the baseline for what we need,

20   if there are any missing items.

21              Then we prepare the draft and we post this

22   draft on our internal website first, meaning our PHMSA

23   website.   That's the bottom box on the left-hand side.

24    After that, it goes through our own office for

25   clearance through our office staff and legal people,
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1    regional director.        Everybody weighs in.   Is this

2    criteria justified.

3                 We put it in the Federal Register.     We wait

4    for the comment.    As I mentioned earlier, in fact what

5    we have done on a monthly basis, we issue this Federal

6    Register notice notifying the following companies have

7    given these special permit requests.       Each and every

8    company's individual docket, people can comment on

9    that.

10                So pretty much we're going to follow this

11   procedure.    When we receive comments and we don't have

12   negative comments, we notify the operator and notice

13   also goes to the Federal Register stating that these

14   have been all approved.

15                So the process will be the same -- on the

16   time span.    So this concludes my talk on how we're

17   going to go about on the special permits.        We'll take
18   questions at this stage.

19                MR. WIESE:    I think we'll -- maybe in

20   Andrew's time we'll take questions en bloc.

21                MR. ISRANI:    Okay.   We'll take questions

22   later, after the next presentation.       Thank you.

23

24

25
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1    Proposal: How Will We Accomplish and Implement Change?

2                         Zach Barrett

3              (PowerPoint presentation.)

4              MR. BARRETT:   I'm Zach Barrett.   I'm

5    currently the director of state programs, but probably

6    more importantly for this, I was lead for the Gas

7    Integrity Management Oversight Program.   I wanted to

8    speak to you this morning a little bit about a proposed

9    special permit process for us for reviewing special

10   permits and kind of some of the expectations and things

11   that we would expect from operators, and some of the

12   review criteria that we would have around that.

13             One of the important things I'd like to

14   emphasize before I get into this is that we're trying

15   to -- the process that we're trying to put in place

16   kind of follows the pipe-people-process structure that

17   you've heard Jeff talk about in the past.    In this
18   presentation it's kind of the process-the people-the

19   pipe structure the way it's laid out.

20             But we feel that those three elements are

21   important to have a good review and to assure safety

22   and to assure improvements.   So what you're going to

23   see is going to follow that structure.

24             Initially, for permit criteria, what we're

25   expecting to see is that, for process criteria, we
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1    expect that you would have a good gas integrity

2    management program or plan.   Just in general, in

3    reviewing, kind of building on what Jeff has said about

4    the acceptable IMP programs, we have reviewed most of

5    our major operators' integrity management programs to

6    date in area that are fairly germane to this:

7    identifying HCAs, identifying your threats to an HCA,

8    looking at the assessment methods that were chosen to

9    assess the HCAs, looking at the repair criteria.

10             Usually in those areas we didn't find a lot

11   of problems with operators.   Most operators are

12   identifying HCAs well, they're identifying their

13   threats well, and they're identifying their tools to

14   assess their threats well.    They're doing well in

15   making repairs and having repair processes.

16             For personnel, having qualified personnel is

17   obviously very important, too.   If people are not
18   qualified to do the work that you're doing or are not

19   tested well or are not there, we feel that that's an

20   important piece.   So we'd be expecting, in our review

21   of some of our OQ requirements, some of our review of

22   our O & M procedures, review of our other pipe

23   inspections that we do, to kind of get an indication

24   that we feel that your personnel are qualified and

25   doing well in implementing the process and plans and
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1    procedures that you have in place.

2                 And then lastly, the technical criteria for

3    the pipe itself.    What type of pipe would be in

4    consideration for these special permits at this stage

5    of the game.    We're certainly open to reconsidering as

6    time goes on, but this is where we'd like to start.

7                 Again, for information necessary to review

8    special permits, we certainly have on file, for the

9    process and procedures look, your amp audits.

10                Also, some of my slides will have PHMSA

11   audits.   I tried to go through -- I missed this one --

12   to say "PHMSA state audits" involved here because

13   certainly the states and tri-states would have an

14   opportunity to also review    a special permit.     As Mike

15   says, there's not much difference in the waiver process

16   that they have in place.    If they were choosing to

17   accept our criteria and guidelines, they could also
18   choose to supplement that with their own procedures and

19   processes.

20                Again, personnel qualification.     We look at

21   the OQ proposed plans.    We're looking for the

22   operators, obviously, to bring us their proposed

23   segments for the special permits and the plans and

24   justifications, that we'll get to later in this

25   presentation, for review.
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1               Then there's a reporting proposal.   It's part

2    of the ticket to the gate to get into a special permit

3    program.   We expect that you will provide us

4    information for reporting on those segments that are in

5    the special permit so that we might keep up with that.

6     As part of our transparency efforts, we'll probably

7    work to probably post those on our websites and that

8    sort of thing.

9               As far as the time period and the timeline,

10   we're expecting in the month of February for a given

11   year that operators will bring us a letter of intent.

12   A letter of intent for this project is, look, we

13   believe that we have been a cooperative company.   We

14   have a good safety history with PHMSA.   Our safety

15   culture is in place, and we believe that we would like

16   to apply for a special permit.   It's like kind of a

17   top-screen type thing.
18              During March and within the next 30 days of

19   the submission of the letter of intent, we'll review

20   that and give an operator an indication whether or not

21   we will be accepting of a special permit proposal or

22   not.   So that might save a few folks a little time.

23   Obviously, if you've just had some accidents or some

24   problems on your line, we're probably not going to be

25   too welcoming to a special permit proposal coming in,
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1    so that's what that's about.

2               During the period of March 11th through March

3    31st, that's when we're expecting you to submit more

4    detailed information on the segments that you're

5    proposing to put in for a special permit.   We would

6    expect to see an individual segment be presented as

7    opposed to "We would like a special permit for Line

8    what have you."   We would expect this to be on an

9    individual basis and have detailed information on an

10   individual basis for each segment, each HCA that you're

11   presenting for a special permit.

12              And then within the March to the June 30th

13   period, within that 90 days, you would get indication

14   or not whether you were approved for the special permit

15   or not.

16              The reasons for these timelines is we

17   realize, or we're sensitive to the fact, that you have
18   a budgeting process for getting your projects in for

19   the coming year, and this should meet that budget

20   process.   So that's why the dates have been chosen.

21              For some of the information -- this is

22   probably not all the information.   We'll certainly

23   develop on this criteria.   But, some of the information

24   that we'll be looking for for the more detailed

25   application, if you've made the screening through the
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1    letter of intent and we've approved your letter of

2    intent, obviously your name, your PHMSA operator ID,

3    contact information.    Who is the point of contact that

4    we can discuss our issues that we might have with the

5    special permit.

6              And a description of the segment:      what

7    threats exist in the segment, milepost to milepost

8    what's in the segment.    Date of last integrity

9    assessment.   What type of integrity assessments have

10   been on the pipeline.    This could also include a

11   history of assessment of the pipeline.    Some of our

12   operators have been running in-line inspection tools

13   through a segment for some time and it's not something

14   new to them, so they may want to also list that they

15   have also been running in-line inspection tools on this

16   segment in previous years, not just the last integrity

17   assessment.
18             We're also interested in the results that we

19   would get, the detailed results.    Did you have any

20   immediates that showed you, did you have any other

21   concerns that we should be aware of.

22             We're also interested in the justification

23   for extending by the seven-year interval.       That would

24   include -- the seven-year interval, as Mike has pointed

25   out, is only applicable to corrosion, the corrosion
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1    threats.   So we would be looking at your justification

2    why, based upon your latest integrity assessments and

3    what you're finding there, as to what your repairs are,

4    and the mechanisms of corrosion that you have

5    identified on that line that you would have a good

6    justification for why it would not be a problem to

7    extend past the seven-year interval.

8               We'd also like a statement from an executive

9    company officer that all the details and all the data

10   that's being provided to us and that he is also on

11   board with extending the interval.

12              So some of the application for the process

13   pieces began -- process-people-pipe.    We feel those

14   three elements are needed.   We'd be looking, again,

15   that you have an integrity management program in place

16   and that you've implemented that integrity management

17   program.   Certainly we will look at the results of your
18   integrity management program audits to determine if

19   there were any issues that we have there that's germane

20   to going past the seven-year assessment.

21              We'll also look to see that you've

22   implemented operations and maintenance plans.   We would

23   also look at our reviews, our 1M reviews and also our

24   standard inspections to see that we feel like you're

25   implementing well against your plans.   That goes to
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1    kind of the total safety culture that you're a company

2    that we have confidence in, that you have good process

3    and procedure, you have good people in place, and

4    you're operating well across the board, maybe not just

5    in the HCAs, just in these segments, but across the

6    board.    We'd be looking that you're doing well.

7                Also as you may have heard earlier in some of

8    our presentations, the drug and alcohol program is

9    certainly becoming more and more dear to our heart

10   again.    We'd also be looking that you have implemented

11   a drug and alcohol program.

12               For the criteria piece, we're also looking

13   for a public awareness program that has been

14   implemented, that you are actually making your

15   mailings, you're making your contacts with the public,

16   and we're also looking for your records to demonstrate

17   your overall, broad range of records that we'll be
18   looking at from our inspections and from your

19   justifications that you bring to us to demonstrate that

20   you have a good, appropriate handle on the management

21   of your pipeline system and the management of the

22   threats, and are taking appropriate actions to manage

23   safety.

24               So for acceptability, that's kind of what we

25   think the criteria is.    For acceptability, and I think
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1    I've kind of mentioned it as we went through, is that

2    you have at least one PHMSA or state audit in place of

3    your IMP program.   If there are any outstanding issues

4    from that -- if you've had the audit, we have got to

5    have had time to have communicated those outstanding

6    issues to you as the company, and any unresolved -- if

7    we have communicated those issues to you in a formal

8    enforcement type action, we will consider the level of

9    NOPVs that we have, as was mentioned before by Jeff.

10             There was a lot of -- some process pieces

11   that might not be as germane to looking at the

12   identification of threats, the identification of the

13   HCAs, your selection of tools, your application of the

14   tools, and your repair process.   We would take a look

15   at those, if there were some of those, to decide

16   whether they were germane or not to this special permit

17   or not.
18             So again, it would have at least one

19   successful state or PHMSA-coordinated IMP audit.    If

20   you have a third party that came in to audit your

21   program, we would not accept your third party's audit.

22    But if you wanted to include that as part of your

23   package as justification, we would also take a look at

24   that, also.

25             So then, of course, we'd accept or deny based
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1    upon the performance of those materials that we look

2    through.    So that's what we're thinking of as kind of a

3    general process piece of acceptance.

4                 Moving to the people piece, the people piece

5    criteria, obviously we expect you to have qualified

6    people and have an operator and qualification plan in

7    place and a drug and alcohol plan and program in place,

8    including testing in both.     We'll look at your training

9    records and those sort of things to see if they're

10   there.

11                We're looking toward that management

12   structure supporting operations and maintenance and

13   integrity management, and to demonstrate a commitment

14   to safety.    That goes to kind of the safety culture

15   issue we've been talking about, that you buy into the

16   process and procedures issues, implementing those

17   process and procedures, that you're having good success
18   across the board as we look at your indicators from the

19   records and information we have, that you're performing

20   well.    So that's one of the things that we would be

21   looking at for the criteria for personnel.

22                We also think it's important that you have

23   technical staff on board that's able to identify or

24   evaluate the conditions that you might have with a

25   specific segment you've put in to play, or HCA that
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1    you've put into play.    Obviously, it's important that

2    you have the technical ability to be able to determine

3    the threats that are in that HCA or be able to pull out

4    the threats that are applicable to the seven-year or

5    the corrosion threats.

6               But if you thought you were just having

7    external corrosion issues and you really hadn't looked

8    at the internal corrosion issues, hopefully we would

9    have identified that during the IMP audit.     That would

10   be a piece of that and we would chain that up.    But

11   also, there are other threats that could have -- the

12   interaction of threats that could also move an

13   assessment forward.   We would expect you to have some

14   discussion in your plans and procedures about the

15   interaction of threats and which threats could

16   accelerate your assessment, there is some thought given

17   to that.
18              Obviously, you can outsource your expertise.

19    That's something that's commonly done in practice.

20   But we'd just like to know that those abilities and

21   those contractual agreements are in place, that you've

22   been operating in this manner.

23              For the personnel acceptance of this

24   criteria, obviously we're looking to see that we've

25   conducted an operation and maintenance plan or a
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1    standard inspection of you, or a drug and alcohol

2    inspection, or that you have certified to us that you

3    have an active drug and alcohol program in place.

4                The reason we're not stating that you have at

5    least had one drug and alcohol inspection is because

6    our inspection program has been lacking for a few years

7    in the drug and alcohol arena.   We're beginning to tool

8    up for that again.    Our indicators that we're getting

9    back from folks that have been certifying to us is that

10   the testing levels have been appropriate and we don't

11   believe that we're seeing any indications of a concern

12   or increase there.    So until we can motivate our folks

13   and get around to start doing inspections again, we're

14   looking at having just you certify to us that you're

15   following our Part 40 and Part 199 drug and alcohol

16   programs.

17               Again, any unresolved NOPVs in any of these
18   areas we would be open for discussion to look at to see

19   if anything is germane to the seven-year waiver or any

20   unresolved notice of amendments.   We would be looking

21   for the same thing.

22               Based upon our review of your personnel

23   criteria, your OQ plans, and the process and procedures

24   that we're looking at, what you're filing to us, we

25   would give you an indication of whether we believe or
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1    not you're doing well there.

2                Okay.    This is more the pipe piece of this,

3    and this is probably more some of what you're

4    interested in.      One of the first criteria that we

5    believe is important is that you've done an in-line

6    inspection and your assessment method is either by in-

7    line inspection or pressure test.

8                At this time we're not looking at the direct

9    assessment criteria as being a criteria for a special

10   permit, and that's somewhat due to the newness of using

11   direct assessment.      Again, we know that people have

12   been using the tools for some time as individuals, but

13   it's the process itself and integrating the tools

14   together.   During our initial inspections of operators,

15   we found quite a few issues with their direct

16   assessment process.

17               We're certainly open to bringing the direct
18   assessment criteria into this procedure probably at a

19   future date, but for our initial attempt at getting

20   this together and getting this together, I guess,

21   right, where we can manage it and deal with it, we were

22   trying to limit it to something we had some familiarity

23   with and we thought we could make some quick decisions.

24               Predict your pipeline corrosion rates.

25   Obviously, your corrosion rates are going to be a
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1    strong factor in what your reassessment interval could

2    be, and so we'll be looking for justification of your

3    corrosion rates, whether you're using -- why default

4    corrosion rates, corrosion rates that might be issued

5    or NACE or in a standard are applicable to your

6    pipeline sections, or why that you would have -- what

7    information that you have available that you could

8    predict your corrosion rates based upon what your

9    internal company data is.

10             Your post-IMP repairs.   After you've done

11   your assessments and you've done your thing, we're

12   looking for analysis of what repairs have you made, at

13   what levels of corrosion indications or anomalies did

14   you feel that you needed to make repairs, and what's

15   remaining to be repaired out there.   So we're curious

16   to see how you're performing with your repairs and what

17   your criteria is for repair.
18             Obviously, we don't want to take any segments

19   that have had a ground assessment and that you've had

20   any incident or leak that's been caused by corrosion

21   subsequent to IMP.   Certainly you might have a segment

22   that had a third party damage hit or something like

23   that that it wouldn't be tied to the seven-year

24   corrosion reassessment period, but any leak or incident

25   caused by corrosion would throw you out of the seven-
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1    year reassessment.

2              Pipeline segments with special conditions,

3    MIC, SSC, SCC, non-tariff gas -- and there we're

4    thinking gas that would have some constituents that

5    would be aggressive with an aggressive corrosion

6    mechanism -- those would require additional -- I guess

7    I'm saying this now, is that if you have segments that

8    have these mechanisms in there that could be

9    interacting that we also would expect you to, in your

10   justification, address these issues and address why

11   they're not a concern in moving up the interval.

12             The seam-selective corrosion -- SSC is seam-

13   selective corrosion.   SCC is stress corrosion cracking.

14    Macrobiological-induced corrosion is MIC.     Non-tariff

15   gas; again, we're looking for wet gas or gas with some

16   corrosive components in it that could be concerning for

17   internal corrosion.
18             In looking at the document that you're

19   providing for us and the technical acceptance, we're

20   also not looking for any bare steel pipe to be accepted

21   into the waiver process or the special permit process,

22   or any pipe that you have ineffective coating systems

23   on where you're seeing that you're having disbonded

24   coating in the areas of the specific HCA or that your

25   cathodic protection requirements are the same as what
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1    it would be for bare pipe in those areas.

2               No pipe with ineffective cathodic protection.

3     If your cathodic protection readings are below

4    criteria, we're not looking to accept those into the

5    special permit.

6               Again, no pipe that's assessed other than by

7    ILI or hydrostatic testing.   We've kind of gone through

8    that a bit.   No pipe with known history of MIC, SCC,

9    SSC.   Certainly, again, the caveat that you would have

10   to have additional justification for a pipe with those

11   issues.

12              If you have a pipeline that's never been

13   hydrostatically tested -- this kind of goes to some of

14   the pipe that's operating higher than the 72 percent

15   SMYS lines -- you would have to justify why the lack of

16   the pressure test does not contribute to the corrosion

17   threat.
18              Of course, we would accept or deny your

19   technical justification on those parameters, around

20   those parameters.

21              Again, as a ticket to admission into a

22   special permit, we expect that you will provide us

23   voluntarily with some reports about how we're doing

24   with these segments.   That would include things like

25   when the assessments were -- did you have any leaks or
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1    problems in that segment.    That's probably going to

2    throw you out of being able to go ahead and extend the

3    maximum interval.    We're keeping the maximum intervals

4    in this.   We're not extending behind the maximum

5    intervals.    But if you had a leak or something in year

6    six, obviously you're probably back in for year seven

7    to do the reassessment issue.     So we want to make you

8    aware of that.

9                 We would also be looking at reporting of any

10   repairs after you have ran your assessment for the

11   segment, whatever interval that you're doing that.

12   We'd like to know what was found in those areas, what

13   the repair history was, and were there any concerns

14   that would cause us to reinstitute the seven-year

15   period in years to come.

16                We will develop a matrix of fields and issues

17   that we feel that you need to do and communicate that
18   with you guys.    But I just want to communicate at this

19   point and probably have some open discussion with

20   industry and others what they feel would be appropriate

21   to bring in for this reporting period.

22                Again, if you're adding any segments to your

23   special permit, we would like to know that in the

24   reporting thing.    Taking any segments out, why the

25   segments are being removed.    And again, status on
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1    completion of the scheduled runs and scheduled repairs

2    that may be going on.

3               With that, that's a general kind of high-

4    level overview of what we're looking for and how the

5    process would work and the key elements of the process

6    that we're looking for for that.

7                     Question-and-Answer Session

8               MR. WIESE:   I wonder if -- just for a process

9    check, we guaranteed to get you out at noon.     I'd like

10   to do two things.     One is I'd like to give you an

11   opportunity now to ask this panel any questions you

12   have.   I recognize it's a public workshop and we want

13   to put things on the record for this.    But if you have

14   a position you want to put on the record, could I ask

15   that you would hold that 'til the end when you've heard

16   both panels.

17              But clearly, if there's a point of
18   clarification that you want to work out while we have

19   this panel here now, I would invite questions but

20   promise you we will provide time at the end for anyone

21   who wants to put a statement on the record.

22              So I would just ask now if there's any

23   questions for this panel.    We will take a break when

24   we're done, and then we will bring our next panel up.

25   We'll finish that.    We'll have questions for them, and
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1    then we'll have kind of an open comment period.

2               So, any questions for this panel?       Lois.

3               Please use the mic.      Daron?   You guys can

4    queue up there.    Is that working?    There should be a

5    switch somewhere there.    There you go.

6               MR. MOORE:    My name is Daron Moore from El

7    Paso Corporation.

8               MR. WIESE:    No, not picking up that mic.        The

9    mic is working, it's just not jacked in.

10              It's a new hotel.    They're debugging as we

11   go.   So bear with us.

12              MR. MOORE:    My name is Daron Moore with El

13   Paso Corporation.    Looking at Mike's slides and Zach's

14   slides, it looks like there may be a conflict on SSC

15   and perhaps MIC.    Mike said they would not be allowed

16   and Zach -- I seem to recall it may be allowed with

17   certain prescriptions.    Can you describe that perhaps
18   kind of conflict?

19              MR. BARRETT:    Right.    Initially when we

20   started looking at criteria for the special permits, in

21   some of the past things that we communicated we were

22   looking at eliminating those threats.        Then, having

23   further discussion and thinking about that for a while,

24   there may be some companies that have those threats

25   that are managing those threats well.        That's why we
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1    have decided to go with additional justification.

2                 Certainly it will be a very high-level,

3    stringent review.    If you have those activities, you're

4    going to have to knock it over the fence, so to say, to

5    convince us that you should get in.      But we thought

6    that we should allow the opportunity for a company to

7    make their case that they are managing those threats

8    and that they would not affect the seven-year.

9                 MS. EPSTEIN:   Hi.   Lois Epstein.    I'm an

10   engineer with LNE Engineering and Policy.         I'm here

11   representing the Pipeline Safety Trust.      I have several

12   questions.

13                I am wondering whether PHMSA has estimated

14   the number of operators or the percentage of operators

15   that might be going through this process?

16                MR. BARRETT:   We don't have any formal

17   numbers how many will be coming forward with the
18   process.   I think that they will come in because of the

19   interval probably the year before -- the way the

20   process is set up, the year before the seven-year would

21   be in effect.    So it's not going to be like there will

22   be everybody that might want to be in the seven-year

23   process can come in in any given year.      It would spread

24   out over several years.     Does that make sense to you?

25                MS. EPSTEIN:   It does.   The reason I'm asking
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1    the question is I have a worry.

2               MR. BARRETT:   Sure.

3               MS. EPSTEIN:   Maybe it's unjustified.   To

4    some extent there will be the tail wagging the dog at

5    PHMSA, that this might actually be an enormous resource

6    blow because it's a fairly well-defined process that's

7    going to require a lot of attention by the technical

8    staff.   A related question is whether PHMSA has

9    considered instituting a fee.     And I recognize that

10   that won't help you directly, but it will at least help

11   the federal government deal with that.

12              I know that it's controversial in some sense,

13   but this is also to some extent a privilege that

14   certain operators would be granted.

15              MR. WIESE:    I'll try, and then maybe Zach can

16   pitch in on that.

17              MR. BARRETT:   I'm not going to touch the fee
18   piece.

19              (Laughter.)

20              MR. WIESE:    Being a student of body language

21   and watching the audience from this perspective, as you

22   introduced the concept of the fee, it was interesting.

23              MS. EPSTEIN:   It's my job.

24              MR. WIESE:    I know it is, and you do it well.

25    But I will say on the fee, it's certainly an
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1    interesting concept, Lois, and we're always struggling

2    to figure out how to cover these bases.    If I could

3    start from the premise that we're not particularly fond

4    of special permits because they do impose a significant

5    work load on the agency.

6                So I will tell you that in this particular

7    case -- and I think I'm speaking for all of us when I

8    say we don't see the seven-year interval as being a

9    significant risk, generally speaking.     There are

10   clearly cases where operators ought to be assessing

11   more frequently than that, so let's start with that,

12   too.

13               Our purpose in the special permit is to

14   prescribe criteria clearly enough that companies will

15   know whether they're going to make it through or not.

16   I know that's kind of an indirect answer to your

17   question.   Alan Mayberry is sitting right here, and
18   Alan gets a lot of the special permits that come in.

19   They are pretty intensive.

20               But we are making this step to prescribe the

21   criteria as clearly as possible and to say to the

22   companies you need to know you can pass that before you

23   apply.   And, we're applying some executive

24   certification requirements to ensure that the

25   management of that company is going to stand up to what
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1    they're submitting to us.

2               MR. BARRETT:   And I would say, as you pointed

3    out, this would be somewhat of a privilege to get.    So

4    we would probably, if we got inundated with requests --

5    being in the house, the way that typically works is you

6    typically would thumb through the requests and pick the

7    ones out that you thought had really done a good job of

8    providing the detail and the justification and the

9    issues that we felt were appropriate and you would look

10   at those first because you would hope that you could

11   make a fairly quick judgment on those.     Those that were

12   more lacking would get kind of pushed towards the end

13   of the pile.

14              We're not saying that we will process

15   everything that comes in the door.    We'll put a good

16   faith effort in doing that, and operators can help us

17   by doing a good faith effort, just not kind of "Hey,
18   we'd like to try this" and throw something out towards

19   us.   We would probably move those toward the end of the

20   pile.

21              MS. EPSTEIN:   Well, I'd encourage PHMSA to at

22   least have that discussion about resources.

23              MR. WIESE:   Appreciate that.

24              MS. EPSTEIN:   And then, I haven't

25   participated in the discussions that have changed the
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1    terminology from "waiver" to "special permit."     I don't

2    think you need to spend a lot of time on that, but I'd

3    like to know the justification and whether it's an

4    issue of how that fits with the NEPA, National

5    Environmental Policy Act, requirements and EIS's,

6    Environmental Impact Statements and Environmental

7    Assessments.    My understanding is that the permits in

8    general have to do something like that.    I was

9    wondering whether the legal folks had looked at that.

10              MR. WIESE:   Well, I have several in the room.

11    Let me, being not an attorney nor practicing law in

12   any way, tell you that the honest answer to that

13   question is that PHMSA -- remember we were the Office

14   of Pipeline Safety for many years and ran kind of

15   fairly independently.    We've now sort of merged into

16   one agency.    The sister part of our agency has issued

17   special permits forever on the hazardous materials
18   side.

19              This is more of a rhetorical thing than a

20   change.   They're fundamentally still waivers.     There's

21   a lot of internal resistance about waivers because, I

22   hope you can see, it's not a waiver.    It's

23   fundamentally an alternative.    So the term "waiver" was

24   pretty loaded.    Just for the sense of one PHMSA they

25   decided to settle on "special permit."
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1                 So I understand and I won't comment on the

2    NEPA part of that, but I don't know if either of the

3    attorneys who are here care to comment on it or not.

4    Larry, do you want to?      I got a nod from my attorneys,

5    so.

6                 MS. EPSTEIN:   And maybe someone can follow up

7    in a separate conversation with me or be able to have

8    those materials -- have some sort of categorical

9    exclusion.    Maybe that's something you guys need to

10   get, too.

11                MR. WIESE:   I'll commit to respond to you as

12   a matter of the record and put something on the record

13   about the NEPA implications of special permits.

14                MS. EPSTEIN:   Okay.

15                MR. WIESE:   Great.    Thanks, Lois.

16                MR. KUPREWICZ:   Just a quick question.     I'm a

17   representative of --
18                MR. BARRETT:   Rick, they need your name.

19                MR. KUPREWICZ:   Oh.    Rick Kuprewicz.   I'm

20   sorry.   Three cups of coffee this morning.

21                MR. WIESE:   We know we can hear you.

22                MR. KUPREWICZ:   I can't hear myself.

23                MR. WIESE:   Oh, okay.

24                MR. KUPREWICZ:   A real important question for

25   me because I have to explain this to the Citizen's
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1    Committee on Pipeline Safety, which is meeting next

2    week here in Washington State.      I want to be sure I

3    understand this and get it right.

4               I'm only one voting member of that committee.

5     That could be good or bad.      But I want to understand

6    in terms of the special permit process.      I think I

7    understand that the application process is a matter of

8    public record, right, because it enters a docket.        What

9    I'm not clear about; as it gets through the final steps

10   and the final approval and granting of a special

11   permit, is that going to be posted in a public website

12   or whatever?    And the conditions granting for that

13   specific special permit.    It wasn't clear to me from

14   the presentation.

15              MR. WIESE:   I think the short answer -- and I

16   was looking for my non-attorney, the reviewer in this

17   case.   No, Alan.   And he was nodding yes.    It is public
18   -- you're right.    It's a matter of public record.

19   There is a docket out there.      Anyone is able to

20   comment.   But the conclusion and our assessment is

21   posted publicly.

22              MR. KUPREWICZ:   Okay.    So let's say a

23   particular pipeline company is granted a special permit

24   on a specific pipeline.

25              MR. WIESE:   Right.
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1               MR. KUPREWICZ:    That will be something that

2    the public should be able to access.      The most ideal

3    way is a website, understanding that isn't necessarily

4    a legal document.

5               MR. WIESE:   Yeah.

6               MR. KUPREWICZ:    Okay.    If I can pass that on

7    to the people who may raise those questions.

8               MR. WIESE:   Yes.

9               MR. BARRETT:    That's what we're doing now,

10   right, Alan?

11              MR. MAYBERRY:    Yeah.    (Off mic.)

12              MR. KUPREWICZ:    Yeah, I understand that.

13   Okay.   But what was confusing me was, I could see it in

14   the initial phase but what happens?      From my

15   perspective, I could just be missing it.      By the time

16   it gets to -- as you're evolving and evaluating the

17   process and you may change some conditions as you
18   gather condition information or communicating amongst

19   the parties.    You may have told an additional condition

20   -- again, we're talking about a specific pipeline or

21   pipeline segment.

22              I think the public, from the public

23   perspective, what I hear constantly on committees are,

24   as a public person living by a pipeline, what can I get

25   to feel confident that people have everything under
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1    control.   And what I try to explain to people who don't

2    get buried in details, don't understand that the

3    process makes sense, and usually you can get --

4    Washington State has a very liberal public record

5    process.

6                 If I say we -- that, but what I wanted to be

7    sure of is if you have a document that says you've

8    imposed an additional condition on you -- let's say

9    SSC.   "We're going to grant it to you.       You have it

10   under control."    But if the public perceives that as a

11   real risk on this segment and you haven't touched that

12   part of it -- then that final condition, the public is

13   going to come at you, probably.     If you've got a letter

14   saying here's all the conditions granted in your

15   special permit, it's on the website or wherever it is,

16   it's a public document, they can evaluate their own

17   conditions.
18                MR. WIESE:   Yeah, understood.    Alan will

19   certainly correct me if I'm wrong here, and I'll step

20   out on a limb large enough to say that generally

21   speaking, though, Rick, what would happen is we would

22   reject it.    So by the time we accept it, the conditions

23   have been worked within the special permit and that

24   application is deemed satisfactory.

25                So we will reject it if they're not meeting
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1    the terms that we've been trying to lay out here.       It's

2    that simple.    It ought to speak for itself at the end

3    of the day.

4                 MR. KUPREWICZ:    Yeah, but -- I don't disagree

5    with that.    I'm just saying that a lot of effort is

6    going to be involved here.

7                 MR. WIESE:   Sure.

8                 MR. KUPREWICZ:    You might go 90 percent into

9    the process and then find a new piece of data.       We're

10   not looking for everybody to just run the bills up

11   here.   We're just looking -- there may be a minor

12   condition here that a minor modification doesn't take

13   you to the -- option.

14                MR. WIESE:   Right.

15                MR. KUPREWICZ:    This is a safety factor, and

16   it's just real important that that final series of

17   conditions be available to the public to make sure
18   everybody is under control.        That's all we're asking.

19                MR. WIESE:   Great.

20                MR. KUPREWICZ:    Okay.

21                MR. WIESE:     Thanks.

22                MR. BARRETT:    Appreciate that.

23                MR. WIESE:   I might -- Zach, any other

24   comments you wanted to add there?       I might just add --

25   yes, you can just flip the switch.       Anyone else have a
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1    question?    We'll reserve the general comments or

2    statement for the record, again, until the other panel

3    is completed.    Remember to state your name and

4    affiliation.    Oh, you're just taking that.     Okay.

5    Thanks.

6                 All right.   Just if I can, just to close out

7    this panel, speaking for PHMSA, I will tell you that we

8    would clearly prefer to have an option to prescribe a

9    risk-based approach to regulation.     We don't have that

10   option right now for the reasons that we tried to lay

11   out to you.    Our only alternative to deal with the risk

12   that we think is relatively minor, and it's something

13   that I hope we've tried to make a case to you, that we

14   and the industry have exercised a lot of controls on --

15   you'll hear more about what the industry has done -- as

16   adequate, is to use this special permit/waiver process

17   that's established within the code to do that.
18                I'd like to make the case that -- and thank

19   you, Rick.    There ought to be a certain amount of

20   transparency to this.     I mean, that really is an

21   additional control, really, in some ways.      So I guess

22   I'd like to make the case for you that what we're

23   positing for your consideration and comment is, are

24   these criteria adequate to deal with that risk.       That

25   is really what we're looking for your comment and
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1    conclusion on.

2                So, at any rate, with that said, again, what

3    we'll do is we'll take a break, if we can, now.          It's

4    exactly 10.   Can we take 15 minutes?       We'll come back

5    at 10:15.   We've got one more panel.       We'll take

6    questions for them.      And then anybody is welcome to put

7    a comment on the record.      Thank you very much.

8                (Brief recess.)

9                            Findings to Date

10                              Terry Boss

11               (PowerPoint presentation.)

12               MR. BOSS:    Okay.   I'll get started here so we

13   can stay on schedule.      My name is Terry Boss.    I'm

14   senior vice president with the Interstate Natural Gas

15   Association of America.      We represent the interstate

16   pipelines that go through here.         There are segments out

17   there that are also represented in this room.
18               I wanted to give kind of a background of what

19   we have learned.   I know Jeff asked the question who is

20   in the audience, and some of the things that I'm going

21   to be talking about are going to be repetitive perhaps

22   for some folks, but I did want to give some background

23   in case we have some folks in here that have not been

24   through this journey that we have been through multiple

25   years on these sort of things.
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1                 As far as background, I've had about 20 years

2    experience working for a gas transmission company.

3    Spent about a year on integrity management in the Gas

4    Research Institute and been at INGAA probably about 13

5    years, involved in a lot of these different efforts

6    that we've had here.    So it's been a history for me and

7    a history for a lot of folks in the room.

8                 One thing I did want to make some mention,

9    again to get people situated out here, this is a

10   diagram of basically the natural gas infrastructure out

11   there.   Primarily what we're talking about is that

12   segment in the middle, which is primarily transmission

13   pipelines.    There is a little bit of overage on

14   transmission pipelines on the upstream side and on the

15   downstream side in the local distribution companies

16   that AGA represents, and APGA represents on those sort

17   of things.
18                One thing about our industry.   In general,

19   we've got a fairly homogeneous product out there,

20   natural gas.    That's helped us significantly in doing a

21   lot of the risk assessments and moving through this

22   process.   It eliminates a lot of the variables as you

23   go through this kind of analysis.

24                This is a picture, a very gross picture, of

25   some of the interstate pipelines out there and the
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1    companies that are involved.   Put that on the website.

2               Of course, our goals.    This is some repeating

3    of slides that we had at the PIPA thing.    Basically,

4    we're in the business to reliably transport energy

5    safely.   If we have concern by the public or their

6    representatives on that, that's not good for our

7    business and it is going to hurt us very bad.    So we're

8    very concerned about that and our goals are not to have

9    any kind of events that are causing concern.

10              This is an overall slide to give you some

11   perspective of the segments of the industry we're

12   talking about.   We're in with this group right now as

13   far as serious incidents.   The definition of incidents,

14   serious incidents, is up on the PHMSA website.

15   Basically, that's injury or fatality or a very

16   catastrophic type of incident on that sort of thing.

17   So that's what we're working from originally throughout
18   the years as we've moved here.

19              An important thing that we're looking at here

20   is the slide to talk about the infrastructure that

21   we've got to have quality control on the type of

22   operations out there.   There's programs that we've got

23   out there, practices, standards, codes, and

24   regulations, that are adopted.     Originally, as I said,

25   the natural gas industry has been around for a while,
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1    primarily the transmission industry in the '30s.     There

2    was an extensive effort in the '50s to standardize a

3    lot of this stuff under ASME, and granted, as I

4    mentioned before, we've got a very homogeneous product.

5     So you might say our Risk Management 1.0 plan was

6    developed in 1950 under ASME B31.8.

7              A lot of that information that those

8    gentlemen put together at that time was then adopted

9    into regulations.   A lot of times then you get these

10   prescriptive regulations that are put together and some

11   folks don't understand, okay, why did we come up with

12   this information.

13             The first effort we went into risk management

14   demonstration was to relook at the reasons for coming

15   up with the standards and regulations that we had from

16   a risk perspective, and that was the Emeritus Report,

17   as we've been through.
18             As we've developed through the '90s, we

19   relooked at some of the things that were going on.      The

20   OSHA process on safety management had come out.    We

21   also had the EPA R & P program out.   And we did a

22   relook at our regulations that we had out there, and

23   our practices and so on like that, to do a comparison

24   point with those.   Again, from a product standpoint,

25   because we were so homogeneous, in a lot of those cases
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1    we did satisfy a lot of those criteria that we had

2    there.   And if there were some gaps that were involved

3    in those things, that's where we tried to do some

4    improvements.

5               So you can see at the time when those

6    relationships were developed on those things, the

7    regulatory process relooked at process safety

8    management and so on like that, and did a comparison

9    and a determination that essentially the regulatory

10   activity within PHMSA was essentially satisfying the

11   goals that were moving forward on that process.

12              The pipeline integrity management process has

13   got principles out there:   the threat identification,

14   characterization of the risk, the integrity assessment,

15   and preventative and mitigative measures out there.

16   Some of this is a repeat of what Jeff has said already

17   today, and I just wanted to essentially work on that.
18              The definition of risk that we've got out

19   there is probability times consequence.   Again, because

20   it's got a homogeneous product, we've got a fairly good

21   idea of the consequence on this, where we don't have

22   some of the issues that you did have in the OSHA

23   process safety management of trying to understand that.

24              Our main concentration from the original

25   regulations and as we've moved through this thing is to
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1    reduce the probability of some of the events that are

2    moving through here.

3              One of the key concerns with natural gas

4    being a flammable product is the public safety that's

5    involved in that.    It's rather benign as far as

6    environment is concerned because it is a methane

7    product out there.    You do have some CO2 concerns with

8    all energy products that are coming up in global

9    climate change.   But in general, the risk to what's

10   going on in the world is essentially a concern about

11   human safety on that.

12             One of the difficulties we have these days is

13   we do have a population distribution out in the U.S.

14   that is expanding and that is affecting a lot of how we

15   do look at these sort of things.    A good example of

16   this is the pipeline that's going through here.      You

17   can see the population encroachment going on there.
18             The original designers of that Risk

19   Management 1.0 understood that sort of thing and built

20   into it a rather, at that time, sophisticated criteria

21   called class location.    So as you had increasing

22   population density coming around the pipeline, you made

23   changes to design, construction, and operation

24   practices as you moved forward on this sort of thing.

25   Quite a bit more sophisticated than the traditional
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1    census-based type look at the thing because we were

2    looking at the area right around the pipeline.

3              As we moved forward in the risk management

4    demonstration processes, later on we determined with

5    the new technology that we had out there we could take

6    a more sophisticated look on that thing.

7              Like I said, I'll rush through this quickly.

8     A lot of folks have seen this before, but we may have

9    some folks in here that have not.

10             What I'm depicting here is a pipeline out

11   here that's going through there.    We may have some

12   houses in there or some additional houses being built.

13    Right now the class location process that we had out

14   there is a dynamic process.   As population changes, we

15   make adjustments to the system.

16             The original criteria that was out there that

17   was set up on there to simplify things was to
18   essentially look at a corridor type base arrangement

19   around the pipeline to understand what population is

20   around there.   As you move through that process, you

21   could identify when you had heavier population, like in

22   density areas, and we moved to additional criteria as

23   we move through those processes.

24             So in this particular case, it might have

25   jumped from a class one location to a class three
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1    location and made different requirements on that.

2               As we started on the risk management

3    demonstration integrity work in the latter '90s and

4    early 2000s, we came up with this more defined criteria

5    out there to come up with a high consequence area.    We

6    went through a lot of data and analysis and research

7    that was done to look at the accident data and the

8    homogeneous characteristics of natural gas and the

9    behavior on the worst case conditions on these

10   pipelines, and we came up with what we call a CFER

11   circle.   That's essentially an engineering-type

12   terminology to essentially address some levels of risk.

13              The idea of the high consequence area is

14   essentially you look at this criteria and you

15   essentially walk down the pipeline and look at the

16   density of population on that.   And when you have an

17   area that fits into a certain density of population, we
18   overlay additional criteria on top of the already risk

19   management practices that were built into the O & M

20   procedures.   This is the integrity management plan that

21   we're talking about here now that we're working on.     So

22   it's essentially -- the yellow section out there is

23   what we're talking about on these type of criteria.

24              In threat identification, and these are some

25   generic slides, there is a different criteria for the
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1    hazardous liquid pipelines because the consequences to

2    those folks of those type of events are slightly

3    different.    But this is generic criteria.   Like I said,

4    ours is concentrated primarily on the public safety, I

5    think, but to identify the threats that are put

6    together on this.

7                 There's a probability that those threats may

8    cause some kind of accident on those sort of things,

9    and we have to identify the probability that's going on

10   there.

11                This is an example of a sheet that we pulled

12   out of one of the reports on there.    Essentially, we

13   went through during the risk management demonstration

14   gathering all the data for the data collections from

15   '70 through '84, where we had a lot of information

16   about not only the failures we had on the system during

17   operation but any kind of maintenance failures on
18   hydrostatic testing.    Through the '80s and '90s and so

19   on like that, improvements in the form to get a better

20   idea and clarification of the threats that are out

21   there.   You can see we're roughly up to about 23

22   distinct causes out there that we can break down.

23                In a lot of cases, what you want to

24   understand is you want to understand what is causing

25   the event.    There may be different activities to help
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1    mitigate or prevent that effect, and they may be

2    different.    That's why we've broken them down into all

3    these different classifications.

4                 Consequence assessment is essentially looking

5    at the situation.    A lot of work went into these -- I

6    think Daron is right over here -- in defining that.        A

7    lot of dialogue with PHMSA and so on.     We built off of

8    the original criteria class location, but we were

9    trying to identify those special locations, the nursing

10   homes, et cetera, that are out there that we wanted to

11   have a little bit more care in those things to be more

12   assured that those efforts are being through, and on

13   the consequence assessment.

14                Again, a lot of work was done on the

15   consequence because of the homogeneous product, which

16   made it a little bit easier for natural gas to do this

17   rather than some of the other products to see what was
18   going on.

19                Consequences.   This is, again, a chart out

20   there.   This gives you some idea of, when we have had

21   incidents, both an idea of the injuries and fatalities

22   out there and property damage that are involved in the

23   thing.

24                Additional analysis is going on right now,

25   and some of this is going on in the PIPA.     What we're
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1    looking at is categories of people that are affected.

2    In some cases the employees, in some cases emergency

3    providers.    Other cases, it may be excavators, and then

4    there's the general public.    So it's a good idea to

5    understand who is the affected population and how do

6    these different threats and probabilities affect those

7    things.

8                 The final thing is to go into the risk

9    determination process of what's out there.       We've

10   broken the causes out there into static defects.         These

11   are defects that may be present in some of the

12   locations during construction, and as technology

13   improves we may identify some of these static defects

14   that are out there.    Essentially, it's a defect.       Once

15   you find it and you eliminate it and you mitigate it,

16   that defect does not come back.

17                There is time-independent defects out there.
18    Those are very similar to defects that occur when you

19   have an excavation damage or some event that does not

20   have predictability out there on when it does happen.

21                And then time-dependent defects:    something

22   that you can forecast over a period of time where there

23   may be some technology or process that you can go in

24   and examine the pipeline every once in a while and then

25   get some kind of predictability that you will be able
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1    to manage the situation.    A very good example of that

2    is corrosion, where there is a time-based thing.

3                 A lot of the things that we're talking about

4    on the IMP program are based on the time-dependent

5    thing, and that's the focus of the seven-year thing.

6    But the key criteria that you need to know is the IMP

7    program does address the static and time-independent

8    events here and the extra efforts that we're trying to

9    control those things.

10                Again, the methodologies that are out there

11   right now are in-line inspection, pressure test, direct

12   assessment, and new technology that may be out there.

13   We're working on a lot of new technologies to try to

14   improve this process.    And you've got to pig and

15   background to do that sort of thing.

16                After we have determined what is out there on

17   the assessment, there is protective and mitigative
18   actions.   It's one thing to repair something, but it's

19   an additional step to find out, well, why was that

20   happening.    If you have a general process in there and

21   something isn't working quite right in this place, that

22   additional step of mitigating that so you don't think

23   that -- or, you try to prevent that issue from

24   happening in the future.

25                Some important documents on there on what
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1    we've learned on the integrity management program on

2    there.   The GAO report that was mentioned before is up

3    on their website.   That has been submitted to Congress

4    and put through there.   We just finished a report on

5    comparison of assessment techniques.    The INGAA

6    Foundation put together a report on that.       I'm going to

7    pull a few excerpts out of that.

8                The INGAA Foundation report.   Essentially,

9    there is a diagram in there that talks about this

10   process, and I won't delve on that.    Essentially what

11   is out there.

12               The approximate statistics that Jeff went

13   over.    These are about the same things that he has out

14   there, to give you some idea of the coverage on that

15   sort of thing.

16               An important note to make out here is, as the

17   industry moves forward on these sort of things, there's
18   practices out there that individual companies are

19   putting together.   And then eventually these practices

20   start moving around and they become best practices.

21   When these best practices gel together, then you may

22   end up having standards like B31.8S.    Those practices

23   are so good, and there may be some recalcitrant players

24   out there, then you get a regulatory process.      That's

25   when we get the IMP process in there.
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1                So essentially what we're doing is we're

2    taking a lot of the technology and practices and

3    putting those together in a standardized process to

4    help that, and eventually you do get the regulation.

5                The assessment technology split that's out

6    there.   Primarily, the total number of miles that are

7    being inspected are overwhelmingly done by in-line

8    inspection.   Once you do modify your facilities, that

9    is probably the easiest method to do that.      One of the

10   difficulties that we had with the Gas Integrity

11   Management Program rather than the Liquid Program, is

12   gas is a compressible fluid and we didn't have the

13   facilities installed to run these in-line inspection

14   devices because of the different sizes of pipe and

15   different equipment that was in there.

16               So the original baseline period of 10 years

17   was really established to permit the gas pipeline
18   industry essentially to modify a lot of their

19   facilities to put this equipment in and make that big

20   expenditure moving forward on that.

21               A little bit of hydrostatic pressure testing

22   done.    The key factor is that ILI doesn't necessarily

23   cut off the flow all that much except when you're

24   installing a lot of those facilities.    So it's

25   primarily ILI that's being done on this.
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1               Again, I'll refer you, because you probably

2    can't read these things, that these will be up on the

3    docket, but the reports are on the websites and are

4    available for downloading on these things.     This gives

5    you some kind of idea of the period of years that we've

6    been in the standardized program.

7               Let me emphasize this.   One of the values of

8    the Integrity Management Program is not only

9    standardized processes but the standardized collection

10   of data.   There was a lot of sharing of information

11   within the companies.    Their methodologies may have

12   been a little bit different.    But what this does give

13   us is a very good database of information out there

14   across the whole United States.

15              I'm going to be speaking in Europe here in

16   about two weeks or so.    We've got a great advantage

17   over those folks because they don't have a lot of
18   information that's available transparently to share on

19   those sort of things.    So that's one of the advantages

20   of the IMP program, is a lot of the sharing of the data

21   and being able to understand better and more quickly

22   improve our processes as we're moving through here.

23              I put these up on the slide so you can see

24   them more directly.   This gives you some idea of the

25   results that are coming through under the establishment
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1    of the program and some idea of these out there and the

2    repairs that we're going through here.   Essentially

3    what we're addressing on these immediates and schedules

4    are essentially precursors to events.    So not only are

5    we trying to control the incidents on that but control

6    the precursors which are established out there.   It

7    gives you some idea of the things that we have

8    experienced here.

9              One of the other things that has gone on --

10   and Jeff alluded to it and we put it in our report --

11   even though there is a very systematic and structured

12   process that is being reported to the federal

13   government under the HCA areas, there is a lot of fine

14   work that's going on outside these HCA areas on that.

15   The HCA really is taking credit for a lot of these

16   integrity inspections out there.

17             What we have done is we have published a lot
18   of that information in the areas outside of the HCA

19   areas, and we are looking at the rates that are

20   occurring in those areas to see that we are getting

21   comparable type of results both in the HCA areas and

22   outside the HCA areas as we move through that on those.

23    That's depicted here.

24             As far as the GAO report that is out there,

25   this was published in September 2006.    This is a rather
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1    extensive effort of the Government Accountability

2    Office.

3               One of the main concerns, and a lot of folks

4    are probably, if you're not familiar with this, are

5    asking the question, okay, what's going on with the

6    seven years.    Why are we discussing that.   The

7    particular layout -- we've done an extensive effort

8    where we've got to modify our system to do those sort

9    of things, and then we will have to start and do a

10   reassessment period on that.    There is an overlap of a

11   lot of work on that, and there is disruption on a lot

12   of the things.    We are out to reliably provide energy.

13              One of the concerns is not only a resource

14   issue but also a deliverability issue of natural gas on

15   these things.    We want to be sure we can minimize the

16   effect of this without affecting the safety of the

17   process as we move through here.
18              So the timeline of the process is essentially

19   we've got a lot of overlap occurring on the thing and

20   the question about just the efficacy of the seven-year

21   requirement, which is essentially a political

22   compromise that happened in Congress on those sort of

23   things.

24              This gives you some kind of idea of the

25   overlap.   The darker gray type indications are the
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1    original baseline tests that we're moving through here.

2     And then as you move into the reassessment process,

3    you layer on those inspections on the same time.       What

4    we're trying to do is trying to manage that situation

5    so we effectively are improving the safety as we're

6    moving forward here but we're not affecting our

7    reliability or resource problems on that.

8                 One thing that we want to be very, very

9    cautious about as we move forward, we want to do these

10   extensive efforts in the high consequence areas on

11   there, but the high consequence areas are not

12   necessarily the whole pipeline.    We'd like to be able

13   to allocate our resources to a lot of those areas as we

14   move forward on the process.    So, doing a lot of

15   overwork in one area doesn't necessarily help as we

16   move through this process.    We want to effectively

17   allocate our resources on these efforts.
18                As far as the results that are out there, and

19   this is a natural response to it, the public had a

20   concern about the conditions of the pipelines out there

21   because they had a lack of knowledge about the

22   pipelines.    What's happened with this consistent

23   program and consistent reporting of this information is

24   more information is available out on the stated

25   conditions on that.    As GAO went through that, what
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1    they were determining was that anxiety that was out

2    there about the conditions of the line isn't

3    necessarily needed.   The condition was a lot better

4    than people had feared was out there on the gas

5    transmission lines.

6              The conclusion was that GAO thought the

7    seven-year prescriptive requirement was conservative

8    and that it should be more of a risk-based type thing.

9     Again, these reports are available for looking at.

10             Conclusion.    The IMP has been very effective

11   in improving and standardizing the risk management

12   protection out there.    That goes all the way to the

13   reporting, which then gives confidence to the public

14   and the regulators of the processes now out there.

15             The natural gas transmission system is in

16   better condition than the public had perceived.    The

17   congressionally mandated reassessment interval in
18   general is too conservative.    It should be more of a

19   risk-based type thing.    And the technical tools and

20   techniques that we have out there are available to do

21   more sophisticated analysis on this sort of thing to

22   manage the risks out there.

23                    Operator Utilization

24                 Bob Travers, Spectra Energy

25             MR. TRAVERS:    Good morning.   I'm Bob Travers.
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1     I currently head up the integrity program over at

2    Spectra Energy, the operator formerly known as Duke.

3                First of all, the reason I'm up here, and

4    Daron on my right, we participated in the development

5    of the framework that you've seen presented to you this

6    morning.    Helped out in getting that up and running.

7    And we're here to offer an operator's perspective on a

8    few issues.   I'll speak to a few technical elements and

9    Daron will talk a little bit about a few process

10   elements.

11               But first and foremost, we want to offer our

12   support of this risk-based approach.    We think it makes

13   sense over the prescriptive seven-year time frame.       In

14   some cases, the right answer may be eight years, nine

15   years.   In some cases it might be shorter than seven.

16   This provides a vehicle to do the right thing and get

17   our lines inspected at the right frequencies.
18               I'll address just a few of the technical

19   elements, as I said.    Some of this may be a little bit

20   redundant with what was said this morning, but just to

21   reemphasize a few of those things.

22               As you saw this morning, some criteria has

23   been established to identify which lines are valid to

24   participate in this program.   Quite simply, there are a

25   number of things that would disqualify you from this,
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1    one being possibly if you've had a corrosion-related

2    leak, a corrosion-related incident over the last few

3    years.   Quite simply, it's just not eligible for the

4    program.

5               As Zach mentioned earlier, there are a number

6    of other things that will just require some extra

7    justification.   If you've had some MIC or SSC or SCC,

8    clearly it's something we're going to have to make a

9    very strong justification to PHMSA as to why we feel

10   that this segment could still participate in this

11   program and why going to eight or nine or 10 years on

12   the ILI frequency doesn't cause a problem given the

13   history that the line has.

14              Speaking for myself and for Spectra, this for

15   us will apply to a small handful of our lines,

16   somewhere, maybe, between 10 to 15 percent of the ILIs

17   that we would do on a given year.   I don't anticipate
18   going for much more than that, so we would probably be

19   looking at somewhere between five, seven ILIs per year

20   that maybe we would submit and request to participate

21   in this program.   But I don't think it would be too,

22   too much more than that.

23              It goes without saying this is going to be

24   limited to lines that performed very well on their last

25   in-line inspection.   Quite simply, it wouldn't take
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1    more than a small handful of anomalies scheduled out to

2    years eight or nine where it's just going to be more

3    cost effective to run at the normal frequency than to

4    dig those additional anomalies.    So I think that all

5    factors into what I said earlier.

6                We don't anticipate this being a big part of

7    our program.    Probably more the exception than the

8    rule.    I think some operators would probably have a

9    higher percentage of their lines participating in this

10   program, but speaking for myself, we're probably in

11   that 10, 15 percent range.

12               That was really all I wanted to say.

13   Everything else had been addressed earlier.       So I'm

14   also up here to answer the questions that come after

15   Daron is done.     But at this point I'll throw it over to

16   Daron.   Thanks.

17      Presentation by Daron Moore, El Paso Natural Gas
18               MR. MOORE:   I'm going to stay seated if we

19   can get the microphone to work properly for the court

20   reporter.   Is this adequate?   Thank you.

21               My name is Daron Moore with El Paso

22   Corporation out of Houston, Texas.    I've been working

23   on pipeline safety for about 12 years now.       As Jeff

24   started off the discussion this morning, I was the one

25   that raised my hand who had worked on risk management.
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1     That's about when I started.     I remember the public

2    meeting down the street at the Crystal City Marriott.

3    Some of you in the room might remember that meeting.

4    That's kind of when I got started in all this.

5                 My time in pipeline safety has extended

6    through integrity management today, with stops along

7    the way in specifically operator qualification and a

8    few other technical issues that I've worked with PHMSA

9    on.   So I've been heavily involved in PHMSA's

10   regulatory agenda over the last 12 years.

11                My comments are primarily as an INGAA

12   representative from the El Paso perspective.       We agree

13   with Zach's presentation and the technical criteria.

14   We think it's technically founded.    We think it's data-

15   driven.   We see opportunities for it to be transparent.

16    We think all those things are key to the success of

17   this program both internally to El Paso as well as
18   publicly for PHMSA and, perhaps most importantly, to

19   the public, being able to see what we're trying to

20   accomplish.

21                I have a few INGAA comments now that I'd like

22   to make on process that the pipeline operators see in

23   this.   I'll go into those now.

24                We think that we can build on prior

25   successes.    There have been a number of prior successes
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1    that INGAA operators have had with PHMSA over the last

2    decade or so.   Primarily, and number one, is the

3    Integrity Management Rule itself.   INGAA stepped up and

4    built, along with help from some of the other trade

5    associations, a national consensus standard called

6    B31.8(s) which formed the framework for this rule.     It

7    was a resounding success, and we want to continue to

8    build on those themes.

9               The class location special permit criteria.

10   There are some issues around the special permits

11   themselves.   The criteria that we jointly developed

12   with DOT was successful.   We want to build on that,

13   also.

14              Finally, in OQ, we had a gun pointed to our

15   head back in 2002 and we developed frequently asked

16   questions on inspection protocols, which led to further

17   inspections of the operator qualification programs.
18   That I thought was a big success as we stabilized the

19   operator qualification environment that we did not have

20   the stability on in the early 2000s.

21              We want to build on those successes as we go

22   forward.   We think this program has the opportunity to

23   do that.

24              Specific concerns.   I have six, and they're

25   more cautions or comments, not necessarily just
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1    concerns.   I want to be very clear that these are not

2    negative comments.

3                Number one, success in this program we

4    believe is due largely to timing and consistency.     We

5    didn't talk too much about the timetable that Zach laid

6    out which started in, I believe, February of each year

7    and concluded in June or July of each year, why that

8    was so important to operators.

9                Number one, February is important because

10   we're only looking one year out.   It's a rolling year.

11    We can't predict as operators what our threats are

12   going to be on our pipeline more than about a year or

13   two in advance.   So it doesn't make sense to ask for an

14   extension from seven to eight, nine, or 10 years if we

15   can't predict what the threats are going to be.

16               But on the other end, on the July-June end,

17   we're limited by our budgetary constraints.     We need to
18   know as operators what we're going to be doing in the

19   following year.    Those decisions are made typically,

20   with most operators, in the summer period the year

21   prior.   So we have some constraints there that we need

22   to work within and try to make it happen.

23               We also think that there may be some need for

24   consistency in our application process.     I'm thinking

25   in terms of a form that has the relevant data that DOT
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1    needs to have to make their decision.      In the past, for

2    special permits, 80 percent, and class location in

3    particular, the applications have been company-specific

4    with data scattered, I'm guessing, all through the

5    applications and different between El Paso compared to

6    Spectra, compared to Panhandle, compared to other

7    operators.    Perhaps having a common form would

8    facilitate, one, INGAA companies supplying the data;

9    and two, DOT being able to evaluate that data again in

10   a timely fashion, as I mentioned earlier.

11                The programmatic information is at the

12   headquarters of DOT, programmatic being the performance

13   of operators in their integrity management program, O &

14   M plans, drug and alcohol plans, operator qualification

15   plans, and ongoing.    With that programmatic info being

16   housed at the headquarters location primarily, we think

17   there's a lot of room for this program here to be
18   headed up and started and finished at the headquarters

19   location.    I'll talk some more about that in a few

20   minutes.

21                Dedicated resources at DOT.   We talked about

22   that.   There was a question about that this morning.

23   We also think that there will be more and more easily

24   dedicated resources at the headquarters facility than

25   there may be at various regions out in the field for
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1    DOT.

2                 Item Number 2, the integrity management plan

3    inspection issues may still be outstanding for

4    operators.    There have been a number of inspections of

5    operators over the last two years.     I don't know what

6    the percentage is of which ones have received some form

7    of enforcement letter, but the percentage is relatively

8    high and it's much higher than what we saw in the first

9    round of inspections for the hazardous liquid

10   pipelines.

11                I believe Zach addressed this as well, and we

12   agree that even if you have some level of enforcement

13   action, as long as that's not systemic, as long as it's

14   not programmatic for the operator and the operator is

15   diligently working to resolve those issues with DOT, we

16   think that that should not stand in the way of an

17   operator submitting a special permit and ultimately
18   being granted a special permit for this discussion

19   we're having today.

20                There are honest disagreements in those

21   inspections where operators disagree with some of the

22   assertions and interpretations of DOT.    Sometimes the

23   operator agrees with DOT, and there have been occasions

24   where DOT has agreed with the operator.    So obviously,

25   there's some give and take there, and we need to take
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1    that into account in this program and not have

2    operators be tossed out just because there may be an

3    NOPV or an NOA on the operator outstanding.

4                Finally on this topic, there have been some

5    relatively long time intervals between the time the

6    inspection took place and the time the enforcement

7    letters may or may not have gone out.      The longest I've

8    heard of is in the neighborhood of 66 weeks, but there

9    are some that are approaching that and are still

10   outstanding.    That would not be fair to a given

11   operator to be held out because of something beyond his

12   control.    I want to make that comment.

13               Item Number 3, we believe strongly that the

14   process needs to be defined.    Zach has defined that

15   well this morning.    Concurrent with that, it needs to

16   be repeatable year over year over year.      We think

17   that's key.    One, that's for timing and budgetary
18   reasons.

19               I'm concerned, and I think that all the

20   operators [were] when they saw the slide earlier this

21   morning that had the roughly 12 points.     But it was

22   three columns, multi colors, with multiple time frames

23   in there.    I got very concerned that that could be

24   accomplished in the review process from a February to a

25   July time frame.    If we need to sharpen that pencil and
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1    get it right, then industry, and specifically the INGAA

2    operators, are more than willing to work diligently

3    with DOT to make that happen.      I'm just not certain

4    right now how that's going to play, so I wanted to toss

5    that out as a concern.

6                 We want to make sure the technical benchmarks

7    are clear.    I think they are from what Zach presented

8    earlier today.    That was good.    And, transparent to the

9    public in both data and programs.      We think that's

10   important.    We want them to be able to see what's going

11   on.   Having multiple dockets, one for each operator or

12   one for each piggable segment or one for each year may

13   not be the best way for the public to see this.      I

14   would encourage perhaps a webpage dedicated that DOT

15   has in the PRIMA system or somewhere else to make it a

16   little bit easier for both operators, the public, and

17   perhaps even DOT personnel to access.
18                Item Number 4, active program administration

19   with robust controls.    This is inside the operating

20   companies.    It's cautioning ourselves.    PHMSA has

21   learned a lot about our operations during their long

22   inspections.    For the public, the inspections have

23   lasted usually two weeks with a team of five to eight

24   inspectors coming in.    El Paso's lasted three weeks.

25   So they're long, detailed inspections with long
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1    discussions.

2               PHMSA has learned a lot from that, and so

3    have the operators.    PHMSA has an idea of who has

4    management commitment, not just to sign the data form

5    we have to send in once or twice a year, but true

6    commitment to pipeline safety.    Only those operators

7    that PHMSA is comfortable with should be allowed into

8    the program.

9               Item 5, desire for a defined dispute

10   resolution process.    If there is a disagreement,

11   particularly in the special permit application, and I

12   can think of issues perhaps being the SSC issues and a

13   couple of the others that Zach mentioned, we'd like to

14   see some sort of defined dispute resolution process.

15   We don't think that's too difficult, but one that drags

16   on for a number of months and results in hearings or

17   whatever else may come up probably is unacceptable
18   given the time constraints.

19              Finally, Item 6.   I mentioned this a moment

20   ago.   Must have senior management support, but not only

21   support, also involvement, and their commitment.      If

22   that doesn't exist, this won't work.    The internal

23   processes must be robust and sound inside the company,

24   and the company safety culture must be firmly

25   established.    In our discussions with Zach and his team
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1    over the last number of months, we've talked about

2    safety culture.    He's made it very clear that they will

3    make that part of their evaluation process, and that's

4    appropriate.

5               A couple final comments.    Operator

6    submissions should be data-driven with all the risk

7    factors accounted for.    We're required to do this by

8    rule as far as the risk factors are concerned, and I

9    think most companies are doing that based on the

10   readings I've had of the various enforcement letters.

11              Only appropriate segments should be applied

12   for.   That's what Bob said just a moment ago.    If we're

13   applying for extensions in time on segments that don't

14   meet the technical criteria or are borderline, we're

15   only setting ourselves up for failure and DOT up for

16   failure and second-guessing by the public and loss of

17   confidence, and that's not positive.
18              The programs must be consistent and

19   repeatable in approach and execution, and finally, with

20   safe operation being the paramount goal in all of this.

21    That's clearly what operators are about and that's

22   clearly what DOT is about, and it's clearly what the

23   public is demanding.    My final comment is we think this

24   is what Zach said this morning and what he said prior

25   to today, and it's what we think gives this program the
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1    best chance for success.

2               That concludes my INGAA comments.    Thank you.

3                   Question-and-Answer Session

4               MR. BARRETT:    Since you were having some

5    difficulty with questions and comments earlier, we'd

6    ask, if you have any of those, please step forward to

7    this mic, Station A.    We open it up to any questions or

8    comments that you have for this panel.

9               MS. EPSTEIN:    Lois Epstein with LNE

10   Engineering and Policy.    I had a question for Daron.   I

11   just wanted to get your reaction to the discussion

12   earlier that some of the applications that would come

13   in would look good and would be high priority and

14   others may fall down.     It's getting at the question of

15   does DOT-PHMSA have the resources to oversee this

16   program right now.

17              MR. MOORE:   Lois, I think it ties in with the
18   forms discussion I had a while ago.    It's clear to me,

19   both today and prior to today, that if you don't have a

20   strong application -- and I don't mean strong

21   technically in this sense, I mean strong in the sense

22   of organization and its clarity and timeliness.    If you

23   don't have those things in place, DOT is not going to

24   have as good an opportunity to evaluate it in a timely

25   fashion.   Clearly, if you're making the effort to put
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1    all this data together behind the scenes, and this is

2    not going to be easy for operators to do, we want to

3    have the best chance of getting these special permits

4    accepted and granted.

5               That's the onus I think Zach was trying to

6    say, and it plays directly in line with what we're

7    concerned about.   Did I answer your question, all of

8    it?

9               MR. BOSS:    The thing that we want to

10   emphasize is the upfront work both from the companies

11   and PHMSA to get a Web portal established on this and

12   to achieve the goals of getting the data out there both

13   from an administrative process and clarity on fields

14   that are out there and then also from a transparency

15   thing.   So it's kind of a front end-loaded process

16   which we're promoting that will ease the administrative

17   process later on as we move forward.
18              MS. EPSTEIN:    So in some sense the best case

19   scenario is all the applications are in really good

20   shape, and that's almost the worst case scenario for

21   PHMSA because they may not be able to handle it.    That

22   was just a comment.

23              MR. BOSS:    Well, the key is if an

24   administrative process is set up and we are building

25   off an integrity management process that's already out
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1    there, we've already been audited, a lot of these

2    "questions" have already been put together, it's a

3    matter of structuring it such that all the decisions

4    that have been made in the past on there are put in the

5    same place so you can very quickly say, okay, we've

6    done this audit, we've seen this, here's the technical

7    criteria.   X marks the spot on that.   Then it's a

8    fairly quick decision.

9                That's probably the biggest thing on the

10   earlier question you had versus waivers versus special

11   permits.    Special permits are designed to be very

12   structured such that everybody knows what the game is,

13   rather than a wide-open waiver, so that they can go

14   ahead and apply it on those things.

15               MS. EPSTEIN:   And maybe this is a question

16   for Zach.   Is there a guidance you're writing?   Daron's

17   point about an application process, how is that going
18   to work?

19               MR. BARRETT:   We will have to develop some

20   standard formats, not only for our website, so we can

21   be transparent with what we're sending out to people

22   and what's there, but for internal reviews and that

23   sort of thing.    But they'll contain the elements that

24   you saw in my presentation.

25               Our reviews would be a review of whether or
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1    not you have an integrity management plan.      We will go

2    to our websites and have our people check to see, yes,

3    they have a plan; yes, they've been audited' what were

4    the results of that audit; is there anything that

5    concerns us in the area of threat identification or

6    those issues; are there outstanding violations or

7    notice of amendments.    We'll look at those areas, also.

8     But we haven't put those in a structured format yet.

9    We will have to do that.

10             Any other questions?

11             MR. MOHN:     Jeryl Mohn from Panhandle Energy.

12    A clarification, I guess, for our industry panel.

13   What is the first year under the seven-year criteria

14   where operators would be doing reinspection where the

15   special permit process might apply?

16             MR. BARRETT:     Do you have any coming up in

17   the coming year?
18             MR. MOORE:    We envision being able to make

19   application this year, in the next couple months, with

20   approval coming sometime later this year, obviously.

21             I wasn't sure they could hear me.      I heard

22   some mumbling out there.    I guess they can.

23             With next year's being -- the seven years

24   expiring next year being moved back one, two, or three

25   years from there.   So that would be the 2009 scheduled
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1    inspections being moved back possibly as late as 2012.

2     Consistent with you, Zach?

3              MR. BARRETT:    Obviously we've got some work

4    that we have to get done to allow that, but they

5    actually would have to come in for this year for next

6    year's evaluations.    2009 would be the first year the

7    seven-year reassessments would come into play under the

8    rule.

9              MR. BOSS:    I think as far as the number of

10   events going on there's a few inspections that have the

11   probability of being in this program this next year,

12   but the bulk as you move forward year by year is

13   actually going to be in the following year.    So you

14   might say this is almost like a pilot stage as we move

15   through this process to get it established.

16             MR. BARRETT:    Other questions from the floor?

17             MR. ADLER:    Thank you.   Dave Adler, NiSource.
18    Zach, you just mentioned that guidance will be -- is

19   being developed.   I think that's a great idea.    I hope

20   there will be some opportunity for input from the

21   public and industry.

22             For example, and there will be a number of

23   such issues, but I'm thinking of a line -- several

24   lines we have that may be 1,500 miles long, all with

25   the same name.   Parts of this line -- let's take near
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1    Nashville, Tennessee, for example -- contain much newer

2    pipe.   Other parts contain the original pipe from the

3    original construction.    In some of the original areas

4    we might feel it's important to inspect more frequently

5    than every seven years, and we might like to get a

6    special permit for areas where we can inspect the newer

7    pipe and we find it to be in better condition.

8               Yet, what I've heard a couple times this

9    morning is if we've ever had any pinhole leak in our

10   line, and I assume that means a line that shares a

11   common name, then it may kick it out as a candidate.      I

12   think that would be a situation where it maybe should

13   not be kicked out as a candidate.

14              MR. BARRETT:   I can clarify that.   What we're

15   looking for when you send your applications in is for

16   individual HCA segments, is what you'll be sending in.

17    We're talking about the shape of the line, the
18   criteria, the details.    It will be looked at as an

19   individual HCA segment.    So it's not Line 100 by Line

20   100, it's HCA -- you've designated those HCAs from

21   milepost to milepost or from station to station.

22              So if you've had an assessment on that HCA,

23   what date was that.   If you've had any subsequent leaks

24   or corrosion issues from the time of that assessment,

25   that's what would limit that HCA from the reassessment
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1    period from the special permit.

2                So what we're asking for is specific

3    information to a high consequence area, a covered

4    segment.    Does that help?

5                MR. BARRETT:   Any other questions from the

6    floor?

7                MR. KUPREWICZ:    Just a quick observation

8    because I get this feedback from the public all the

9    time.    I guess I'm going to address it to everybody

10   here.    I often have to advise highly energized public

11   persons who are legitimately energized for various

12   reasons on their own perspective.     But I think I would

13   advise the process players here, we're not here to run

14   up your bill on inspections.     I think it's important

15   that everybody stay focused, including the process.

16               I don't have a problem with the special

17   permit process from a technical perspective.     I think
18   you want to -- and it sounds like you've been doing

19   your homework on all parties.     That's a good thing.    I

20   think what we have a hard time communicating to the

21   public is the frequency of inspections are a rather

22   irrelevant issue if the quality of the inspections are

23   not well done.    That's a hard thing to get to the

24   persons who are really energized who don't understand

25   the technical aspects.
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1              It does not surprise me to see or hear some

2    of the information today because, like in all good

3    operations, there are many good operators and then

4    there are a few goofs.    The goofs can create a lot of

5    problems for everybody for various reasons.    And I'm

6    being polite calling them "goofs."

7              So from our perspective, my feedback from a

8    public perspective is to keep the process focused on

9    the quality and is it addressed to the specifics of the

10   pipeline and the frequency itself.    Let's not lose

11   another perspective.   It hasn't been too many years ago

12   that you really never had to do inspections on your

13   pipelines at all, technically, in regulation.    So we've

14   come a long ways here, and that's a good thing.     So I

15   just want to watch that the amount of volume coming at

16   you causes you to lose the quality.

17             MR. BARRETT:    Appreciate those comments.       Any
18   other questions from the floor?   Yes, sir.

19             MR. BRESLAND:    I'm John Bresland with

20   currently EPA, formerly Chemical Safety Board.      I think

21   it was Daron who brought the issue of safety culture.

22   I think you said that the companies without a strong

23   safety culture would fall out of this program.      Does

24   PHMSA or the industry have any measurements or

25   assessment tools for safety culture that are currently
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1    being used?

2              MR. BARRETT:   We haven't done a criteria or

3    inspections for safety culture.    However, we do have

4    data that we gather from our inspections that bring

5    indicators to us of concerns that we may have in

6    certain areas where we may ask some of the higher-level

7    management to come in and visit with our higher-level

8    management to discuss issues about how they're managing

9    their systems, their pipeline systems and that.

10             So it hasn't been formalized yet, but we do

11   have kind of indicators or triggers that cause us

12   concern from time to time to ask an operator to come in

13   to do that.

14             I think really overall what we're getting at

15   here is that we're looking for operators who are open

16   and transparent with us and are also willing to play

17   well, willing to exchange ideas, willing to open their
18   books to us, willing to allow us access into areas that

19   we feel that we need access into without a lot of

20   barriers and difficult and fights to be able to get the

21   confidence that we feel like we need to do something

22   additional and special in this.   So that's the best I

23   can characterize it for you at this level.

24             Jeff, do you have any -- is that a fair

25   characterization?
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1                 MR. BOSS:    I think from an industry

2    perspective we're very cognizant of that.      Like I said,

3    one of the big advantages that we have, you do have a

4    diverse culture as you move geographically across and

5    so on like that.    But we do have a rather homogeneous

6    industry.    One product, a lot of the technology that

7    everybody is using on there, the management processes,

8    and so on.    So there's a lot of sharing that's going

9    on, so that does facilitate that communication and

10   understanding by PHMSA as they move from company to

11   company on some of the attitudes and the culture

12   involved in those sort of things.      It does help that.

13                MR. BARRETT:    Any other questions from the

14   floor?   Hearing none --

15                MR. WIESE:    Since this is a public meeting,

16   I'd like to give everybody one last opportunity just to

17   put a comment -- it doesn't have to be a question -- to
18   either panel.    But if anyone would like to take a last

19   opportunity to put a comment on the record in favor or

20   opposed, whatever you wish.      This is really the best

21   opportunity to do that.

22                We do have a docket.    You can submit things

23   to the docket for this.      I'd welcome any comments

24   anyone has.

25                MR. BARRETT:    To repeat that, any comments
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1    that anyone has, this is the most opportune time to get

2    that into the docket.    So I'd open this up to comments

3    and not just questions at this time.    So, any comments

4    you'd like for the docket, please come forth and state

5    them.   Anybody that has comments for the docket, please

6    --

7               (Laughter.)

8               MR. LUU:   Thanks.   Good morning.   Andrew Luu

9    with American Gas Association.    I just want to reflect

10   the position and comments from AGA as well as its

11   members.   AGA would like to commend PHMSA for its

12   efforts in initiating and developing this proposal for

13   a special permit process which would provide authorized

14   operators the opportunity to perform integrity

15   reassessments beyond the seven-year interval for those

16   pipelines that meet the technical criteria as specified

17   by PHMSA in concert with national pipeline standards.
18              The mechanism will allow operators to

19   prioritize their resources so they can be expended on

20   the pipelines which truly represent the greatest risk

21   to the public.

22              In general, AGA is supportive and in

23   agreement with both the proposed process and criteria

24   associated with the special permits.    There's two

25   issues which AGA would like to provide comment on, and
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1    they were raised a little bit earlier but we just

2    wanted to reemphasize it.

3                 We wanted to point out that the slides were

4    mostly geared towards having a successful PHMSA audit.

5     For operators -- for the local distribution companies

6    who are under the enforcement of a state regulatory

7    authority, an audit conducted by the state we feel

8    should satisfy this particular requirement the same as

9    a PHMSA audit.    In essence, an audit by a state agency

10   should be as credible and as acceptable in this

11   particular process as a PHMSA audit, we feel.    We don't

12   understand why that would be any different.

13                Secondly, we feel it's critical to revisit

14   this criteria and the process periodically to consider

15   whether any changes or additions are warranted based

16   upon industry findings from integrity assessments.    The

17   industry is still largely in a learning mode.    We all
18   know that.    The rule has only been in place since

19   December of 2003.    In particular, operators and

20   regulators are still gaining familiarity and confidence

21   in all the intricacies associated with direct

22   assessment, ECDA, ICDA, and SSCDA.

23                While AGA can agree at this time that

24   candidate pipeline segments should have at least one

25   prior inspection with ILI and pressure testing -- or
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1    pressure testing I should say, as the assessment

2    method, there may be one day in the future where it's

3    appropriate to allow those lines inspected by only DA

4    as eligible for special permit consideration.

5              Again, we realize that DA is still evolving

6    and it is not our intent to initiate a technical

7    discussion at this time on the merits of DA, but we

8    just wanted to get that on the record.    Thank you.

9              MR. BARRETT:   Thank you, Andrew.     The point

10   of clarification with the slides I think, especially

11   some of the previous slides, they didn't have -- they

12   had a PHMSA audit.   I tried to amend those before this

13   meeting where they had a PHMSA/state audit.     We did

14   intend for a state audit to bear the same weight as a

15   PHMSA audit in the review of the special permit,

16   something that came from an intrastate line to a state

17   organization.   So, appreciate your comments.
18             Any other comments for the record?

19             MR. TRAVERS:   I have a question, if it's okay

20   to ask a question.

21             MR. BARRETT:   You bet.    Sure, sure.

22             MR. TRAVERS:   Bob Travers, Spectra.     I was

23   wondering if, Zach, either you or perhaps Jeff could

24   speak at all to where you see this going in the future

25   in terms of legislative change.     Will this live for a
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1    while as a special permit process?      Do we anticipate

2    within a few years that this perhaps could move to a

3    rulemaking through legislative change on that seven-

4    year requirement?    Just the issues around that.

5    Wondering what your thoughts were on that.

6                 MR. WIESE:    I didn't think Zach wanted to

7    take that one, but thanks for bringing that up, Bob

8    Travers.   Okay.

9                 (Laughter.)

10                MR. WIESE:    I think the simplest way for me

11   to answer this without getting myself in trouble is we

12   don't have the statutory authority at this time to

13   enter into the regulatory side.      I guess it would be my

14   hope that the experience we can gain with the special

15   permit process, in addition to the GAO report, in

16   addition to the Secretary of Transportation's letter to

17   the Hill, would someday give us the opportunity to ask
18   the Congress for that authority.      But right now we lack

19   it.   We're not in a position to lobby Congress,

20   obviously.

21                But we can consider suggesting to Congress

22   that we be given that authority.      Perhaps the

23   experience with some of these special permits is really

24   the icing on the cake.

25                So again, until such time as we're given the
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1    authority, really this is the only route we can take.

2               MR. MOORE:   Daron Moore.   We would, as

3    industry, certainly appreciate your support in the next

4    reauthorization to have this considered by Congress.

5               MR. WIESE:   Okay.   Any other comments?

6               (No response.)

7                            Conclusion

8                            Jeff Wiese

9               MR. WIESE:   Okay.   Thank you very much.   It

10   was a good discussion this morning.    I'm glad we were

11   able to get a couple of things out.    Just keep it in

12   your forefront of your mind.    As we talk about these

13   things it's important to talk about not just the

14   pipelines but also the process quality and the people

15   quality.   So, thank you.

16              (Whereupon, at 11:15 a.m., the meeting was

17   concluded.)
18




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