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]{.underline}:

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

A G E N D A

[AGENDA ITEM]{.underline}: [PAGE]{.underline}:

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

P R O C E E D I N G S

8:40 a.m.

Welcome and Opening Remarks

Jeffrey D. Wiese

(PowerPoint presentation.)

MR. WIESE: Again, good morning, everyone. My name is Jeff Wiese. I\'m
the associate administrator for pipeline safety at DOT. I\'d like to
welcome you on behalf of DOT to our meeting this morning. I\'m not going
to run through the administrative moment that we covered just a second
ago. To be honest with you, I think we have plenty of time to cover our
agenda today, so I want to relieve any anxieties you might have at that.
But we won\'t go over the administrative moment again.

If I can, just as a prelude to begin talking about this, as I of course
had a moment to talk to a few people out here having coffee, and knowing
that I\'ll speak a lot faster now for all the coffee that I\'ve had, I
did notice that a lot of people we have done business for quite a while
from all sides of the spectrum. My esteemed colleague here from INGAA
asked me for something, and I\'d like to honor that. He said, how many
people in the room have been involved from the days of risk management
forward.

Take a look around. I mean, there\'s a lot of people in this room who
have been involved in the enterprise since the days of risk management.
I would say that the enterprise \-- what I\'d like to start out with,
just my introductory comments to you, is that I think we\'ve worked very
well together. We\'ve done a lot of work together. We\'ve made a lot of
progress working together, all sides pitching in.

The state people are here. They were part of that. The industry was
here. The advocacy groups were here. So I think we\'ve done good work
together and we\'ve come a long way. Not to say things are perfect. We
have a lot of work to do. But I think things are perfect \-- or, not
perfect. Sorry. That\'s the coffee. So we can thank Starbucks. Let me
back up and start over. You can strike those last two sentences.

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

So with that said, I was also commenting to\
Terry as we chatted over this issue that remember it wasn\'t too long
ago that there was a fairly significant loss of confidence in the work
of the enterprise getting together. We had several very high-consequence
accidents. There was clearly room for improvement after we saw those
things.

We set about, what\'s the process that we need to use in order to make
that kind of improvement. The simple solution at that time would have
been, and trust me, after what we\'ve gone through and looking
backwards, it would have been far simpler to have instituted a
pig-and-dig rule, as we say sort of derogatorily. Pig and dig. It\'s a
lot easier to write a rule like that.

But it\'s not about just testing. I think that\'s the case I\'d like to
make for you at the outset. I\'ll run through some slides and make it
for you again. But in the time-honored tradition of telling you, I think
it takes equal contributions from the pipeline and the technology side.
So as I acknowledge my friend from Texas, points about science, it\'s
crucial knowing that and having an understanding of the science and the
technology involved in this.

But it also involves contributions from the process side, which is where
I think we\'ve made a heck of a lot of gain. And the people side, where
I\'d also make the case where we\'ve made a big gain.

So with that sort of prelude to telling you that I think integrity
management has made a significant contribution in our ability to safely
manage the natural gas transmission pipeline system, I just thought I
would run through for you really quickly the goals we set out at the
very beginning of integrity management, even before gas integrity
management. Mind you, we had a number of years of experience working in
the hazardous liquid field before we got to gas.

The goals were pretty much the same. We wanted to start out for sure to
accelerate integrity assessments of gas pipelines in high-consequence
areas. That was more of the pig-and-dig side of this. But as importantly
I guess I should say, we wanted to improve integrity management systems
within companies. The point of that exercise is pig-and-dig will provide
you a certain amount of protection for a certain amount of time, but we
want to make sure that all companies, not just the leading companies but
all companies, know how to do this on a continuous basis. They have the
processes set up in place to give you that return on value constantly.

I think it was crucial for us to improve the government\'s role in this,
both at a state level and a federal level. I see a lot of our state
partners in the room here, and I know that they would agree we would
have worked pretty hard on that. We\'ve done a lot of training of
people. We\'ve had a very rigorous oversight program. Some might say \--
what\'s your favorite word in the state government now? Protocols?
Anyone here? Do I see a show of hands?

I walked into a state meeting at one point, and I\'ll play with my
friends from the states, and they said as I walked in \-- they had me
stand outside, and when they finally let me in, the slide on the wall,
what did it say, Don? Do you remember? \"No more protocols.\" Yeah,
okay, remember that meeting?

So that was a \-- what? Yeah, yeah, they love them. We know you love
them. But they were constantly saying \"No more protocols.\"

At any rate, that\'s a point of saying we\'ve worked pretty hard
together to make sure that we had a rigorous approach to oversight.
It\'s my hope and my belief that we\'ve worked together in order to
shore up public confidence.

Again, not knowing who I\'m speaking to here. I know a lot of you, but
there are some I don\'t know, and I don\'t know where you\'re from.

I will say that there\'s a lot of information on this program available
on our website. That was another thing we did to try to push the
transparency of what we were doing, was to publish even our inspection
protocols on the website. So if you want to know more about how we\'re
approaching it, what gas integrity is about, how we\'ve proceeded and
what we\'re accomplishing, even at a performance metrics level, please
use this website. It will be a matter of the record. The presentation
will be there if you need it.

I think, if you go to our new website, the PHMSA.DOT.gov, you would be
able to find your way there. I\'m still learning that one because I knew
the old website so well.

Okay. I\'m not going to spend time and read all these bullets to you,
but I really wanted to give you a sense of this beyond the pig-and-dig
concept. A lot of what we\'re doing depends on process, establishing
processes to manage for safety. So all I\'m going to do really for this
slide and the next slide is just show you the elements of the integrity
management program the companies have to work on.

This has been a pretty heavy lift for companies. In a lot of cases, I
think many companies, and the leading companies for sure, had many of
these elements in place. There\'s another page to this, and I think
it\'s switched. Yeah, that\'s the continued page.

All of these have to be in place, and PHMSA and our state partners audit
against all of these program elements. So I\'m just pointing them out.
I\'m not going to spend much time on them.

It\'s a fairly extensive effort. This is not an easy job either for the
companies or for ourselves, but I think we\'ve made good progress.

Just quickly, some stats. The overall system \-- I\'m rounding, so
forgive me for rounding. Roughly 290,000 miles of transmission pipeline,
19,000 of which is located in a high-consequence area.

If I can, I\'d like to put something on the record to say that I\'ve had
dialogue with a lot of people, including the U.S. General Accountability
Office \-- I think that\'s their new title \-- about this, the notion of
only 19,000 miles being in high-consequence areas. I\'d just like to say
the integrity management program was always intended to be a supplement.
It is not a replacement for, it is a supplement to all of the other
protections that have been in place for years.

Interestingly enough, and this was validated by the General
Accountability Office, which we\'ll go into that report a little bit
more later, we used our GIS \-- because I was a little concerned about
that being such a low number. Was this an adequate supplement.

We used data from the Census Bureau and went through and used our GAS to
look on a 1,000-foot buffer nationwide around all the gas transmission
pipeline. What does that mean to people. Roughly two-thirds of the
people in this country who could have been affected by a pipeline
failure on a transmission pipeline lived in those high-consequence
areas.

So the point of that is to say people are disproportionately located in
these high-consequence areas. So while 19,000 in a relative sense may be
small, for the job that it was designed to do, to provide added
protection for people, I think it\'s producing a lot of value.

Progress being made so far to date. Over 12,000 of those miles have been
assessed to date by the companies, and over 70 \-- in the non-HCA, the
point I should make is the supplemental benefits again to the integrity
management assessments is they\'re far wider than just the HCAs. The
companies can\'t just assess, generally speaking, within an HCA. So
it\'s really having a multiplier effect.

Another thing I\'d like to point out is I\'d like to say that a lot of
significant pipe anomalies that were there have been identified by the
companies and they have been repaired. Roughly 2,000 conditions so far.

I guess I didn\'t put it on this slide. One of my slides points out the
effective date of this rule was, what, four years ago. I think we\'re at
four. So really, with only four years into this program, there\'s been
substantial work done already, and a lot of the anomalies in the non-HCA
pipe have also been removed. No company that I\'ve met worth their salt
is going to want to identify an anomaly, HCA or not, that\'s significant
and not repair it. It\'s not in a company\'s interest to have a failure
on a pipeline system.

Okay. So at any rate, I\'ve just got a couple more slides. I mostly
wanted to say and sum up on some of these things that I think the
baseline assessments have served their purpose in integrity management.
They will continue to serve their purpose. Major problems are being
found and fixed. I do believe the pipe is in better condition as a
direct result of this.

I think the companies probably, importantly, have a lot more data on
their pipeline system. As we spoke yesterday with some folks, we are
pushing a data-driven, risk-focused agenda. The companies need to be
able to document and defend their decisions. Our oversight is really
going to be pushing on that. Why are you making that decision. What\'s
your basis. So I think the companies are in a better position to do that
now, having acquired a lot of data, and I think that they understand the
risks that they\'re facing.

We talked a little bit about the process side of this, and so I\'d like
to say a lot of progress has been made on that. A lot of the enforcement
actions \-- I think I referenced enforcement a bit \-- that we\'ve taken
really were focused more on the process side, making sure that companies
had adequate processes in place. I think they\'ve worked hard on
procedures and processes. I think we\'ve added a lot of benefit to the
quality end and, clearly, documentation and records are in better shape.
That\'s one of the great sources we and others have, proving that I can
follow direction occasionally.

The other part of this I would say, as I referenced earlier, we\'ve
spent a lot of time with state and federal inspectors, a lot of
training. Most of our inspectors have nine intensive courses just to be
basically qualified. We added five more, as I recall, for all of our gas
inspectors and spend a lot of time in a team environment trying to make
sure we\'re making the best possible decisions we can make.

So our senior inspectors I think are much better prepared to do
oversight than they were prior to this, and having a team approach
really allows us to bring people with different skill sets together to
make a better holistic argument.

Our progress to date, at least at the federal end, which I have good
statistical data for, is we\'re virtually done with the oversight for
companies that have HCA mileage. So that process has been done. There
have been 39 enforcement actions taken to date, but as I said to you,
the bulk of those have to do with process and procedure, pushing the
company to have the processes and procedures in place that will continue
to add value, continue to help shore up our confidence that the
companies know how to manage their assets.

Also, clearly, we have a few people in the room, although I can\'t spot
them when I\'m standing up in front of an audience, from standards
organizations and industry who work on the standards groups, as well as
state regulators and federal who are in there. We\'ve done a lot of work
to advance new technologies and tools that are available to companies,
but I would also say to shore up standards. The standards are growing.
We continue working with the standards organizations. As I made a case
to some of you yesterday, we\'ve brought them closer in.

We have formed a memorandum of agreement with the standards groups to
bring them into the research program. So they\'re learning about
developments at the earliest possible time that can influence and shore
up the quality of the standards that we have.

These are just some of the technologies that we\'ve been working on
collaboratively.

I think I made this case earlier. Really, just to shore it up, some of
the standards developed as we approached Gas IMP dealt with the
qualifications of people and their ability to deploy the tools. Again, I
made the case earlier about all three: having the tools available for
the pipeline, having a process to deploy those tools, and people who are
qualified to do it.

I\'d like to say I think that the Gas Integrity Management Program is
really positively impacting the operators and the reliability of what
they\'re doing. It\'s helping them allocate capital to highest risks,
which I think at the end of the day is what we\'re trying to do, reduce
threats to the public and to the environment and to make sure that the
highest risks are dealt with first.

Overall I\'d like to say that I think you\'re reducing corporate risk.
Again, no company wants a failure, and it\'s fairly significant
consequences above and beyond what happens with us when any company has
a failure.

We will continue to foster this continuous learning environment where
companies can hopefully, and regulators, can continue to make better
decisions about what we\'re doing and how we manage and achieve our
safety and environmental goals. I would say that integrity management
really has fostered a much deeper dialogue, perhaps deeper than some
might wish, but a much deeper dialogue with the industry than we had
prior to it.

So just in summary for my part of this, I appreciate your coming today
and giving us an opportunity to talk with you. I appreciate those of you
who are taking your time to come and share your point of view with the
crowd.

I mostly wanted to say to you what I\'ve tried to say repeatedly around
integrity management. It\'s not about just the science. That\'s crucial
and we have to continue to make progress on that, not just about the
pipeline and what you know about it. It clearly involves equal
contributions from the processes that you put in place to manage and to
deploy your people and having people who are qualified to do it.

In closing, I\'d like to say I actually believe that the enterprise, not
just the regulator, not just the industry, but the enterprise is in a
much better position to judge the merits of a science-based rationale
than we were five years ago. This has been validated independently.
We\'ll hear more about it.

The General Accountability Office has validated this themselves. They
did a pretty exhaustive year-long audit of us, spoke with a lot of
people in industry, a lot of vendors, and some time ago said that they
preferred the science risk-based approach to setting assessment
intervals.

The administration had made that proposal, as some of you know, in the
reauthorization of the Pipeline Safety Program that happened in 2006.
Congress wasn\'t ready to take it on at that time. They came back and
asked GAO to do that audit and asked us to comment on it. I think we\'ve
both commented favorably and said we\'re in a much better position to do
this now, trying to give the confidence to the Congress to give DOT the
authority to prescribe risk-based regulations.

Until the day that that happens, really we don\'t have that option, so
we\'re gathered together today to talk about the notion of special
permits. How can we use authority that we have to deal with this
challenge of the seven-year reassessment interval on a more
science-driven basis.

So again, I think that really concludes my remarks, and I appreciate
your listening and your patience for our late start. So, thank you very
much.

Background

Mike Israni

(PowerPoint presentation.)

MR. ISRANI: Good morning.

PARTICIPANTS: Good morning.

MR. ISRANI: I\'m Mike Israni. I\'m senior technical advisor at PHMSA
Pipeline Safety. This workshop is about special permits, consideration
for seven-year reassessment intervals. So the best way to begin would be
for us to tell you how we arrived at these reassessment intervals.

So what I will cover in my presentation would be what assessment
intervals Congress mandated in the Pipeline Safety Act of 2002, how
PHMSA determines the reassessment intervals and the deviation from those
reassessment intervals that we allow, what the General Accounting Office
audit report says about these reassessment intervals, what PHMSA\'s
position is on those seven-year reassessment intervals, and finally,
I\'ll also show you a flow chart that we use for the maximum allowable
operating pressure about the procedure to go about special permits.

Special permits are the same thing as the waivers currently defined in
our regulations. It\'s no different, it\'s just a different term we use.
The key difference being here that, normally in the waivers, we have
individual waivers that come to us and we put those in the Federal
Register and ask for comments. And based on the comments and on our own
evaluation we respond, and then we again have to go to the Federal
Register for those waivers.

In the special permits, we follow the same procedure, except we can
bundle a number of these waivers together since this particular issue
would raise a similar situation with lots of companies. So we would
bundle up, like on a monthly basis, whatever requests we get from the
industry. We can bundle up those and put the waiver in the Federal
Register.

So let\'s look at first what assessment intervals Congress mandated in
the Pipeline Safety Act of 2002. Congress required PHMSA to ask the
operators to complete the baseline assessments by the year 2012, and
that was a 10-year baseline assessment \-- was it 10 years or seven
years? Ten years, 10 years. Fifty percent of the high-risk assessments
to be completed by the year 2007.

The Congress also put reassessment for each and every pipeline to be
completed at seven years, and this was the issue that is bringing us to
this workshop: reassessment for all the pipelines every seven years.
Congress, in their mandate, told us about these assessment intervals
regardless of the stress level, meaning there were no different maximum
limits on these intervals for low-stress pipeline or the ones which are
greater than 30 percent SMYS and 50 percent SMYS. They were all required
to go to seven-year reassessment intervals.

When we prepared the Integrity Management\
Rule, we took the approach which determines assessment intervals based
on the risk. We had evaluation involved in this. Our approach involved
continual identification of the risks to determine assessment intervals,
and we wanted these evaluations to be done as often as needed.

Under the periodic evaluation, we also wanted operators to consider the
previous completed integrity assessment results, their recommendation,
results of all the data that they collect normally from their own
inspections or from the history, to integrate all that information and
do the risk assessment. They also had to remediate \-- all the decisions
they make about remediation. Also, they would consider additional
prevention and mitigating measures.

Our assessment intervals also were based on stress levels in the
pipeline. For the pipelines with lower stress levels, we had longer
intervals for them, and for the higher stress levels, we had shorter
intervals for them. But our intervals were in coordination with the
maximum intervals established by the ASME B31.8 Supplement. We followed
the ASME B31 Supplement guidance on establishing these intervals, which
were done with \-- based on the corrosion growth of the defects \-- the
length of the pipeline.

But there was a constraint on the seven-year statutory requirement that
all operators had to comply with. This table shows you the reassessment
intervals we currently have in our regulations. It shows you the
assessment method and different stress levels, what assessment intervals
they have. For example, the pipeline which is at or above 50 percent
SMYS, currently they have 10 years maximum reassessment intervals. For
pipelines between 30 percent up to 50 percent, they have 15 years
maximum reassessment intervals, and below 30 percent SMYS they have
20-year reassessment intervals.

But the seven-year reassessment interval mandated by the statute was
required for all of these at all stress levels. So all of them had to
comply with those requirements, and we established something called the
\-- direct assessment method which was focusing on the corrosion
component of it, meaning internal and external corrosion at seven-year
intervals all the operators at all stress levels had to carry out.

There were some concessions given to the pipelines below 30 percent SMYS
as they had certain different electrical inspections in their chart, and
we have the tables in the Integrity Management Rule which show how they
go about doing those intervals in lieu of seven-year reassessment
intervals.

Now, I want to emphasize that these are the maximum assessment
intervals, and throughout the regulation we made it very clear that a
pipeline, when they do their risk analysis and they find a pipeline
needs to be reassessed at a shorter interval than the seven years, then
they have to do that. That\'s what the whole risk-based program was
based on. These are the maximum intervals. Not every single operator
reaches the maximum limit to do these. Some have to do \-- a certain
segment needs to be done earlier than this.

There were certain deviations allowed in our reassessment intervals. For
example, if there was a lack of inspection tools available because of
all these operators using them at the same time, we were allowing that
flexibility of our reassessment intervals. We also allowed the
flexibility to maintain the product supply. If there was a shortage of
supply and if the operator could demonstrate that the local product
supply \-- we had to maintain that, there was some flexibility given on
that. We wanted these waivers for the flexibility to arrive at PHMSA 180
days before so we can analyze those.

Deviation was also allowed for certain pipeline operators who had an
exceptional performance-based program. Operators with a mature program
could qualify to fall in that category would be the ones who meet all
the requirements that we had in the regulation and above and beyond what
currently was in the regulation. Those operators are given certain
flexibility on the maximum reassessment intervals, except for the
seven-year intervals. Because of our statutory requirement, we could not
budge on that. So operators still had to do for corrosion the
confirmatory assessment every seven years.

The General Accounting Office, as Jeff mentioned, took a good two years
interviewing all of us at PHMSA, in industry, and vendors, the smart pig
vendors, and a number of other people, state folks.

From their study and survey, these are the conclusions they put in their
September 2006 report. They concluded that the mandatory seven-year
reassessment interval is preserved. They agree. They said that most
operators have found few major problems during the baseline assessment.
It wasn\'t very severe \-- that problems would be in the pipeline.

And they also found they were \-- their concern was about the
availability of these resources. So far they haven\'t found such a case.
This was from the survey of the operators. They also found that serious
accidents caused by corrosion are very rare.

In other words, they were trying to find out was the seven-year
mandatory intervals that was focusing on the corrosion, wasn\'t as big
an issue as we had this. So their overall conclusion was that they were
not really in favor of having this mandatory fixed seven-year interval.
They thought it was too restrictive, too conservative.

Now, what is PHMSA\'s position on the seven-year interval. Based on the
GAO report as well as what we had originally when we were developing the
integrity rule based on the risk, we feel that the seven-year
reassessment interval was overly conservative. So we agree with the GAO
report recommendations.

However, we \-- the stature requires, and we feel confident, that
seven-year intervals would give us some interim report on what\'s
happening in the pipeline. Because this program is just beginning, that
will help to have that. But it was going against the risk management
principles for why we did this program. We had originally delivered the
rule without consideration of the seven-year reassessment interval. So
we believe that this \-- we agree with all the recommendations and the
conclusions that the General Accounting Office provided to us. If we
established that risk-based criteria to qualify for not complying with
seven-year interval assessments, we want to emphasize again that the
operators would, from the risk analysis, find certain testing or
inspections to be done earlier than seven years.

They would still be required to do that, meaning we would have the
proposed rule as \-- our new proposed rule, if you go with it, would
have the same requirement as what we had minus the seven-year intervals
but certain criteria that we still have established to ensure that we
are not making a wrong judgment here.

Some of those factors and the criteria \-- jointly agree, and we have to
form some kind of committee or group that would work together to create
that criteria \-- might be prepared for the maximum allowable operating
pressure.

I would now like to go into details of this ILI or pressure test
assessments only and \-- corrosion and make \-- deal with factors that
we have to reconsider during the criteria establishment.

Finally, I\'ve shown you here an example of the special permits flow
chart that we are currently using for the maximum allowable operating
pressure. We\'re going to follow the same procedures, the same process,
of going with the special permits in the case of the reassessment
intervals. Because it\'s a mandatory requirement, we still have \--
special permit or waivers from the operators.

So when we receive the application for a special permit, we\'ll need a
hard copy to the associate administrator of pipeline safety. Copies need
to be also included for the regional director, the director of
engineering, and an additional copy for the staff. A docket number will
be established for each and every request that we receive. There will be
a separate docket number for each and every request that we receive.

So even though we put that special permit notice in the Federal
Register, we\'ll have a separate docket number for each and every
waiver. The reason for that is if someone objects to this and has a
comment on the individual docket number, they can go and comment on that
individual docket, or they can see the detailed information about the
individual request, what the individual company requested in there, what
justifications they give. So commenters will look at the individual
docket number and comment on that.

That procedure so far works fine. We are likely to follow the same
procedure.

We will notify the operator when we receive these copies, and as we go
through all the information the operator provides, we\'re going to
ensure that all the information that we need, the criteria that they are
providing, it meets the baseline for what we need, if there are any
missing items.

Then we prepare the draft and we post this draft on our internal website
first, meaning our PHMSA website. That\'s the bottom box on the
left-hand side. After that, it goes through our own office for clearance
through our office staff and legal people, regional director. Everybody
weighs in. Is this criteria justified.

We put it in the Federal Register. We wait for the comment. As I
mentioned earlier, in fact what we have done on a monthly basis, we
issue this Federal Register notice notifying the following companies
have given these special permit requests. Each and every company\'s
individual docket, people can comment on that.

So pretty much we\'re going to follow this procedure. When we receive
comments and we don\'t have negative comments, we notify the operator
and notice also goes to the Federal Register stating that these have
been all approved.

So the process will be the same \-- on the time span. So this concludes
my talk on how we\'re going to go about on the special permits. We\'ll
take questions at this stage.

MR. WIESE: I think we\'ll \-- maybe in Andrew\'s time we\'ll take
questions en bloc.

MR. ISRANI: Okay. We\'ll take questions later, after the next
presentation. Thank you.

Proposal: How Will We Accomplish and Implement Change?

Zach Barrett

(PowerPoint presentation.)

MR. BARRETT: I\'m Zach Barrett. I\'m currently the director of state
programs, but probably more importantly for this, I was lead for the Gas
Integrity Management Oversight Program. I wanted to speak to you this
morning a little bit about a proposed special permit process for us for
reviewing special permits and kind of some of the expectations and
things that we would expect from operators, and some of the review
criteria that we would have around that.

One of the important things I\'d like to emphasize before I get into
this is that we\'re trying to \-- the process that we\'re trying to put
in place kind of follows the pipe-people-process structure that you\'ve
heard Jeff talk about in the past. In this presentation it\'s kind of
the process-the people-the pipe structure the way it\'s laid out.

But we feel that those three elements are important to have a good
review and to assure safety and to assure improvements. So what you\'re
going to see is going to follow that structure.

Initially, for permit criteria, what we\'re expecting to see is that,
for process criteria, we expect that you would have a good gas integrity
management program or plan. Just in general, in reviewing, kind of
building on what Jeff has said about the acceptable IMP programs, we
have reviewed most of our major operators\' integrity management
programs to date in area that are fairly germane to this: identifying
HCAs, identifying your threats to an HCA, looking at the assessment
methods that were chosen to assess the HCAs, looking at the repair
criteria.

Usually in those areas we didn\'t find a lot of problems with operators.
Most operators are identifying HCAs well, they\'re identifying their
threats well, and they\'re identifying their tools to assess their
threats well. They\'re doing well in making repairs and having repair
processes.

For personnel, having qualified personnel is obviously very important,
too. If people are not qualified to do the work that you\'re doing or
are not tested well or are not there, we feel that that\'s an important
piece. So we\'d be expecting, in our review of some of our OQ
requirements, some of our review of our O & M procedures, review of our
other pipe inspections that we do, to kind of get an indication that we
feel that your personnel are qualified and doing well in implementing
the process and plans and procedures that you have in place.

And then lastly, the technical criteria for the pipe itself. What type
of pipe would be in consideration for these special permits at this
stage of the game. We\'re certainly open to reconsidering as time goes
on, but this is where we\'d like to start.

Again, for information necessary to review special permits, we certainly
have on file, for the process and procedures look, your amp audits.

Also, some of my slides will have PHMSA audits. I tried to go through
\-- I missed this one \-- to say \"PHMSA state audits\" involved here
because certainly the states and tri-states would have an opportunity to
also review a special permit. As Mike says, there\'s not much difference
in the waiver process that they have in place. If they were choosing to
accept our criteria and guidelines, they could also choose to supplement
that with their own procedures and processes.

Again, personnel qualification. We look at the OQ proposed plans. We\'re
looking for the operators, obviously, to bring us their proposed
segments for the special permits and the plans and justifications, that
we\'ll get to later in this presentation, for review.

Then there\'s a reporting proposal. It\'s part of the ticket to the gate
to get into a special permit program. We expect that you will provide us
information for reporting on those segments that are in the special
permit so that we might keep up with that. As part of our transparency
efforts, we\'ll probably work to probably post those on our websites and
that sort of thing.

As far as the time period and the timeline, we\'re expecting in the
month of February for a given year that operators will bring us a letter
of intent. A letter of intent for this project is, look, we believe that
we have been a cooperative company. We have a good safety history with
PHMSA. Our safety culture is in place, and we believe that we would like
to apply for a special permit. It\'s like kind of a top-screen type
thing.

During March and within the next 30 days of the submission of the letter
of intent, we\'ll review that and give an operator an indication whether
or not we will be accepting of a special permit proposal or not. So that
might save a few folks a little time. Obviously, if you\'ve just had
some accidents or some problems on your line, we\'re probably not going
to be too welcoming to a special permit proposal coming in, so that\'s
what that\'s about.

During the period of March 11th through March 31st, that\'s when we\'re
expecting you to submit more detailed information on the segments that
you\'re proposing to put in for a special permit. We would expect to see
an individual segment be presented as opposed to \"We would like a
special permit for Line what have you.\" We would expect this to be on
an individual basis and have detailed information on an individual basis
for each segment, each HCA that you\'re presenting for a special permit.

And then within the March to the June 30th period, within that 90 days,
you would get indication or not whether you were approved for the
special permit or not.

The reasons for these timelines is we realize, or we\'re sensitive to
the fact, that you have a budgeting process for getting your projects in
for the coming year, and this should meet that budget process. So
that\'s why the dates have been chosen.

For some of the information \-- this is probably not all the
information. We\'ll certainly develop on this criteria. But, some of the
information that we\'ll be looking for for the more detailed
application, if you\'ve made the screening through the letter of intent
and we\'ve approved your letter of intent, obviously your name, your
PHMSA operator ID, contact information. Who is the point of contact that
we can discuss our issues that we might have with the special permit.

And a description of the segment: what threats exist in the segment,
milepost to milepost what\'s in the segment. Date of last integrity
assessment. What type of integrity assessments have been on the
pipeline. This could also include a history of assessment of the
pipeline. Some of our operators have been running in-line inspection
tools through a segment for some time and it\'s not something new to
them, so they may want to also list that they have also been running
in-line inspection tools on this segment in previous years, not just the
last integrity assessment.

We\'re also interested in the results that we would get, the detailed
results. Did you have any immediates that showed you, did you have any
other concerns that we should be aware of.

We\'re also interested in the justification for extending by the
seven-year interval. That would include \-- the seven-year interval, as
Mike has pointed out, is only applicable to corrosion, the corrosion
threats. So we would be looking at your justification why, based upon
your latest integrity assessments and what you\'re finding there, as to
what your repairs are, and the mechanisms of corrosion that you have
identified on that line that you would have a good justification for why
it would not be a problem to extend past the seven-year interval.

We\'d also like a statement from an executive company officer that all
the details and all the data that\'s being provided to us and that he is
also on board with extending the interval.

So some of the application for the process pieces began \--
process-people-pipe. We feel those three elements are needed. We\'d be
looking, again, that you have an integrity management program in place
and that you\'ve implemented that integrity management program.
Certainly we will look at the results of your integrity management
program audits to determine if there were any issues that we have there
that\'s germane to going past the seven-year assessment.

We\'ll also look to see that you\'ve implemented operations and
maintenance plans. We would also look at our reviews, our 1M reviews and
also our standard inspections to see that we feel like you\'re
implementing well against your plans. That goes to kind of the total
safety culture that you\'re a company that we have confidence in, that
you have good process and procedure, you have good people in place, and
you\'re operating well across the board, maybe not just in the HCAs,
just in these segments, but across the board. We\'d be looking that
you\'re doing well.

Also as you may have heard earlier in some of our presentations, the
drug and alcohol program is certainly becoming more and more dear to our
heart again. We\'d also be looking that you have implemented a drug and
alcohol program.

For the criteria piece, we\'re also looking for a public awareness
program that has been implemented, that you are actually making your
mailings, you\'re making your contacts with the public, and we\'re also
looking for your records to demonstrate your overall, broad range of
records that we\'ll be looking at from our inspections and from your
justifications that you bring to us to demonstrate that you have a good,
appropriate handle on the management of your pipeline system and the
management of the threats, and are taking appropriate actions to manage
safety.

So for acceptability, that\'s kind of what we think the criteria is. For
acceptability, and I think I\'ve kind of mentioned it as we went
through, is that you have at least one PHMSA or state audit in place of
your IMP program. If there are any outstanding issues from that \-- if
you\'ve had the audit, we have got to have had time to have communicated
those outstanding issues to you as the company, and any unresolved \--
if we have communicated those issues to you in a formal enforcement type
action, we will consider the level of NOPVs that we have, as was
mentioned before by Jeff.

There was a lot of \-- some process pieces that might not be as germane
to looking at the identification of threats, the identification of the
HCAs, your selection of tools, your application of the tools, and your
repair process. We would take a look at those, if there were some of
those, to decide whether they were germane or not to this special permit
or not.

So again, it would have at least one successful state or
PHMSA-coordinated IMP audit. If you have a third party that came in to
audit your program, we would not accept your third party\'s audit. But
if you wanted to include that as part of your package as justification,
we would also take a look at that, also.

So then, of course, we\'d accept or deny based upon the performance of
those materials that we look through. So that\'s what we\'re thinking of
as kind of a general process piece of acceptance.

Moving to the people piece, the people piece criteria, obviously we
expect you to have qualified people and have an operator and
qualification plan in place and a drug and alcohol plan and program in
place, including testing in both. We\'ll look at your training records
and those sort of things to see if they\'re there.

We\'re looking toward that management structure supporting operations
and maintenance and integrity management, and to demonstrate a
commitment to safety. That goes to kind of the safety culture issue
we\'ve been talking about, that you buy into the process and procedures
issues, implementing those process and procedures, that you\'re having
good success across the board as we look at your indicators from the
records and information we have, that you\'re performing well. So
that\'s one of the things that we would be looking at for the criteria
for personnel.

We also think it\'s important that you have technical staff on board
that\'s able to identify or evaluate the conditions that you might have
with a specific segment you\'ve put in to play, or HCA that you\'ve put
into play. Obviously, it\'s important that you have the technical
ability to be able to determine the threats that are in that HCA or be
able to pull out the threats that are applicable to the seven-year or
the corrosion threats.

But if you thought you were just having external corrosion issues and
you really hadn\'t looked at the internal corrosion issues, hopefully we
would have identified that during the IMP audit. That would be a piece
of that and we would chain that up. But also, there are other threats
that could have \-- the interaction of threats that could also move an
assessment forward. We would expect you to have some discussion in your
plans and procedures about the interaction of threats and which threats
could accelerate your assessment, there is some thought given to that.

Obviously, you can outsource your expertise. That\'s something that\'s
commonly done in practice. But we\'d just like to know that those
abilities and those contractual agreements are in place, that you\'ve
been operating in this manner.

For the personnel acceptance of this criteria, obviously we\'re looking
to see that we\'ve conducted an operation and maintenance plan or a
standard inspection of you, or a drug and alcohol inspection, or that
you have certified to us that you have an active drug and alcohol
program in place.

The reason we\'re not stating that you have at least had one drug and
alcohol inspection is because our inspection program has been lacking
for a few years in the drug and alcohol arena. We\'re beginning to tool
up for that again. Our indicators that we\'re getting back from folks
that have been certifying to us is that the testing levels have been
appropriate and we don\'t believe that we\'re seeing any indications of
a concern or increase there. So until we can motivate our folks and get
around to start doing inspections again, we\'re looking at having just
you certify to us that you\'re following our Part 40 and Part 199 drug
and alcohol programs.

Again, any unresolved NOPVs in any of these areas we would be open for
discussion to look at to see if anything is germane to the seven-year
waiver or any unresolved notice of amendments. We would be looking for
the same thing.

Based upon our review of your personnel criteria, your OQ plans, and the
process and procedures that we\'re looking at, what you\'re filing to
us, we would give you an indication of whether we believe or not you\'re
doing well there.

Okay. This is more the pipe piece of this, and this is probably more
some of what you\'re interested in. One of the first criteria that we
believe is important is that you\'ve done an in-line inspection and your
assessment method is either by in-line inspection or pressure test.

At this time we\'re not looking at the direct assessment criteria as
being a criteria for a special permit, and that\'s somewhat due to the
newness of using direct assessment. Again, we know that people have been
using the tools for some time as individuals, but it\'s the process
itself and integrating the tools together. During our initial
inspections of operators, we found quite a few issues with their direct
assessment process.

We\'re certainly open to bringing the direct assessment criteria into
this procedure probably at a future date, but for our initial attempt at
getting this together and getting this together, I guess, right, where
we can manage it and deal with it, we were trying to limit it to
something we had some familiarity with and we thought we could make some
quick decisions.

Predict your pipeline corrosion rates. Obviously, your corrosion rates
are going to be a strong factor in what your reassessment interval could
be, and so we\'ll be looking for justification of your corrosion rates,
whether you\'re using \-- why default corrosion rates, corrosion rates
that might be issued or NACE or in a standard are applicable to your
pipeline sections, or why that you would have \-- what information that
you have available that you could predict your corrosion rates based
upon what your internal company data is.

Your post-IMP repairs. After you\'ve done your assessments and you\'ve
done your thing, we\'re looking for analysis of what repairs have you
made, at what levels of corrosion indications or anomalies did you feel
that you needed to make repairs, and what\'s remaining to be repaired
out there. So we\'re curious to see how you\'re performing with your
repairs and what your criteria is for repair.

Obviously, we don\'t want to take any segments that have had a ground
assessment and that you\'ve had any incident or leak that\'s been caused
by corrosion subsequent to IMP. Certainly you might have a segment that
had a third party damage hit or something like that that it wouldn\'t be
tied to the seven-year corrosion reassessment period, but any leak or
incident caused by corrosion would throw you out of the seven-year
reassessment.

Pipeline segments with special conditions, MIC, SSC, SCC, non-tariff gas
\-- and there we\'re thinking gas that would have some constituents that
would be aggressive with an aggressive corrosion mechanism \-- those
would require additional \-- I guess I\'m saying this now, is that if
you have segments that have these mechanisms in there that could be
interacting that we also would expect you to, in your justification,
address these issues and address why they\'re not a concern in moving up
the interval.

The seam-selective corrosion \-- SSC is seam-selective corrosion. SCC is
stress corrosion cracking. Macrobiological-induced corrosion is MIC.
Non-tariff gas; again, we\'re looking for wet gas or gas with some
corrosive components in it that could be concerning for internal
corrosion.

In looking at the document that you\'re providing for us and the
technical acceptance, we\'re also not looking for any bare steel pipe to
be accepted into the waiver process or the special permit process, or
any pipe that you have ineffective coating systems on where you\'re
seeing that you\'re having disbonded coating in the areas of the
specific HCA or that your cathodic protection requirements are the same
as what it would be for bare pipe in those areas.

No pipe with ineffective cathodic protection. If your cathodic
protection readings are below criteria, we\'re not looking to accept
those into the special permit.

Again, no pipe that\'s assessed other than by ILI or hydrostatic
testing. We\'ve kind of gone through that a bit. No pipe with known
history of MIC, SCC, SSC. Certainly, again, the caveat that you would
have to have additional justification for a pipe with those issues.

If you have a pipeline that\'s never been hydrostatically tested \--
this kind of goes to some of the pipe that\'s operating higher than the
72 percent SMYS lines \-- you would have to justify why the lack of the
pressure test does not contribute to the corrosion threat.

Of course, we would accept or deny your technical justification on those
parameters, around those parameters.

Again, as a ticket to admission into a special permit, we expect that
you will provide us voluntarily with some reports about how we\'re doing
with these segments. That would include things like when the assessments
were \-- did you have any leaks or problems in that segment. That\'s
probably going to throw you out of being able to go ahead and extend the
maximum interval. We\'re keeping the maximum intervals in this. We\'re
not extending behind the maximum intervals. But if you had a leak or
something in year six, obviously you\'re probably back in for year seven
to do the reassessment issue. So we want to make you aware of that.

We would also be looking at reporting of any repairs after you have ran
your assessment for the segment, whatever interval that you\'re doing
that. We\'d like to know what was found in those areas, what the repair
history was, and were there any concerns that would cause us to
reinstitute the seven-year period in years to come.

We will develop a matrix of fields and issues that we feel that you need
to do and communicate that with you guys. But I just want to communicate
at this point and probably have some open discussion with industry and
others what they feel would be appropriate to bring in for this
reporting period.

Again, if you\'re adding any segments to your special permit, we would
like to know that in the reporting thing. Taking any segments out, why
the segments are being removed. And again, status on completion of the
scheduled runs and scheduled repairs that may be going on.

With that, that\'s a general kind of high-level overview of what we\'re
looking for and how the process would work and the key elements of the
process that we\'re looking for for that.

Question-and-Answer Session

MR. WIESE: I wonder if \-- just for a process check, we guaranteed to
get you out at noon. I\'d like to do two things. One is I\'d like to
give you an opportunity now to ask this panel any questions you have. I
recognize it\'s a public workshop and we want to put things on the
record for this. But if you have a position you want to put on the
record, could I ask that you would hold that \'til the end when you\'ve
heard both panels.

But clearly, if there\'s a point of clarification that you want to work
out while we have this panel here now, I would invite questions but
promise you we will provide time at the end for anyone who wants to put
a statement on the record.

So I would just ask now if there\'s any questions for this panel. We
will take a break when we\'re done, and then we will bring our next
panel up. We\'ll finish that. We\'ll have questions for them, and then
we\'ll have kind of an open comment period.

So, any questions for this panel? Lois.

Please use the mic. Daron? You guys can queue up there. Is that working?
There should be a switch somewhere there. There you go.

MR. MOORE: My name is Daron Moore from El Paso Corporation.

MR. WIESE: No, not picking up that mic. The mic is working, it\'s just
not jacked in.

It\'s a new hotel. They\'re debugging as we go. So bear with us.

MR. MOORE: My name is Daron Moore with El Paso Corporation. Looking at
Mike\'s slides and Zach\'s slides, it looks like there may be a conflict
on SSC and perhaps MIC. Mike said they would not be allowed and Zach \--
I seem to recall it may be allowed with certain prescriptions. Can you
describe that perhaps kind of conflict?

MR. BARRETT: Right. Initially when we started looking at criteria for
the special permits, in some of the past things that we communicated we
were looking at eliminating those threats. Then, having further
discussion and thinking about that for a while, there may be some
companies that have those threats that are managing those threats well.
That\'s why we have decided to go with additional justification.

Certainly it will be a very high-level, stringent review. If you have
those activities, you\'re going to have to knock it over the fence, so
to say, to convince us that you should get in. But we thought that we
should allow the opportunity for a company to make their case that they
are managing those threats and that they would not affect the
seven-year.

MS. EPSTEIN: Hi. Lois Epstein. I\'m an engineer with LNE Engineering and
Policy. I\'m here representing the Pipeline Safety Trust. I have several
questions.

I am wondering whether PHMSA has estimated the number of operators or
the percentage of operators that might be going through this process?

MR. BARRETT: We don\'t have any formal numbers how many will be coming
forward with the process. I think that they will come in because of the
interval probably the year before \-- the way the process is set up, the
year before the seven-year would be in effect. So it\'s not going to be
like there will be everybody that might want to be in the seven-year
process can come in in any given year. It would spread out over several
years. Does that make sense to you?

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

MR. BARRETT: Sure.

MS. EPSTEIN: Maybe it\'s unjustified. To some extent there will be the
tail wagging the dog at PHMSA, that this might actually be an enormous
resource blow because it\'s a fairly well-defined process that\'s going
to require a lot of attention by the technical staff. A related question
is whether PHMSA has considered instituting a fee. And I recognize that
that won\'t help you directly, but it will at least help the federal
government deal with that.

I know that it\'s controversial in some sense, but this is also to some
extent a privilege that certain operators would be granted.

MR. WIESE: I\'ll try, and then maybe Zach can pitch in on that.

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

(Laughter.)

MR. WIESE: Being a student of body language and watching the audience
from this perspective, as you introduced the concept of the fee, it was
interesting.

MS. EPSTEIN: It\'s my job.

MR. WIESE: I know it is, and you do it well. But I will say on the fee,
it\'s certainly an interesting concept, Lois, and we\'re always
struggling to figure out how to cover these bases. If I could start from
the premise that we\'re not particularly fond of special permits because
they do impose a significant work load on the agency.

So I will tell you that in this particular case \-- and I think I\'m
speaking for all of us when I say we don\'t see the seven-year interval
as being a significant risk, generally speaking. There are clearly cases
where operators ought to be assessing more frequently than that, so
let\'s start with that, too.

Our purpose in the special permit is to prescribe criteria clearly
enough that companies will know whether they\'re going to make it
through or not. I know that\'s kind of an indirect answer to your
question. Alan Mayberry is sitting right here, and Alan gets a lot of
the special permits that come in. They are pretty intensive.

But we are making this step to prescribe the criteria as clearly as
possible and to say to the companies you need to know you can pass that
before you apply. And, we\'re applying some executive certification
requirements to ensure that the management of that company is going to
stand up to what they\'re submitting to us.

MR. BARRETT: And I would say, as you pointed out, this would be somewhat
of a privilege to get. So we would probably, if we got inundated with
requests \-- being in the house, the way that typically works is you
typically would thumb through the requests and pick the ones out that
you thought had really done a good job of providing the detail and the
justification and the issues that we felt were appropriate and you would
look at those first because you would hope that you could make a fairly
quick judgment on those. Those that were more lacking would get kind of
pushed towards the end of the pile.

We\'re not saying that we will process everything that comes in the
door. We\'ll put a good faith effort in doing that, and operators can
help us by doing a good faith effort, just not kind of \"Hey, we\'d like
to try this\" and throw something out towards us. We would probably move
those toward the end of the pile.

MS. EPSTEIN: Well, I\'d encourage PHMSA to at least have that discussion
about resources.

MR. WIESE: Appreciate that.

MS. EPSTEIN: And then, I haven\'t participated in the discussions that
have changed the terminology from \"waiver\" to \"special permit.\" I
don\'t think you need to spend a lot of time on that, but I\'d like to
know the justification and whether it\'s an issue of how that fits with
the NEPA, National Environmental Policy Act, requirements and EIS\'s,
Environmental Impact Statements and Environmental Assessments. My
understanding is that the permits in general have to do something like
that. I was wondering whether the legal folks had looked at that.

MR. WIESE: Well, I have several in the room. Let me, being not an
attorney nor practicing law in any way, tell you that the honest answer
to that question is that PHMSA \-- remember we were the Office of
Pipeline Safety for many years and ran kind of fairly independently.
We\'ve now sort of merged into one agency. The sister part of our agency
has issued special permits forever on the hazardous materials side.

This is more of a rhetorical thing than a change. They\'re fundamentally
still waivers. There\'s a lot of internal resistance about waivers
because, I hope you can see, it\'s not a waiver. It\'s fundamentally an
alternative. So the term \"waiver\" was pretty loaded. Just for the
sense of one PHMSA they decided to settle on \"special permit.\"

So I understand and I won\'t comment on the NEPA part of that, but I
don\'t know if either of the attorneys who are here care to comment on
it or not. Larry, do you want to? I got a nod from my attorneys, so.

MS. EPSTEIN: And maybe someone can follow up in a separate conversation
with me or be able to have those materials \-- have some sort of
categorical exclusion. Maybe that\'s something you guys need to get,
too.

MR. WIESE: I\'ll commit to respond to you as a matter of the record and
put something on the record about the NEPA implications of special
permits.

MS. EPSTEIN: Okay.

MR. WIESE: Great. Thanks, Lois.

MR. KUPREWICZ: Just a quick question. I\'m a representative of \--

MR. BARRETT: Rick, they need your name.

MR. KUPREWICZ: Oh. Rick Kuprewicz. I\'m sorry. Three cups of coffee this
morning.

MR. WIESE: We know we can hear you.

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

MR. WIESE: Oh, okay.

MR. KUPREWICZ: A real important question for me because I have to
explain this to the Citizen\'s Committee on Pipeline Safety, which is
meeting next week here in Washington State. I want to be sure I
understand this and get it right.

I\'m only one voting member of that committee. That could be good or
bad. But I want to understand in terms of the special permit process. I
think I understand that the application process is a matter of public
record, right, because it enters a docket. What I\'m not clear about; as
it gets through the final steps and the final approval and granting of a
special permit, is that going to be posted in a public website or
whatever? And the conditions granting for that specific special permit.
It wasn\'t clear to me from the presentation.

MR. WIESE: I think the short answer \-- and I was looking for my
non-attorney, the reviewer in this case. No, Alan. And he was nodding
yes. It is public \-- you\'re right. It\'s a matter of public record.
There is a docket out there. Anyone is able to comment. But the
conclusion and our assessment is posted publicly.

MR. KUPREWICZ: Okay. So let\'s say a particular pipeline company is
granted a special permit on a specific pipeline.

MR. WIESE: Right.

MR. KUPREWICZ: That will be something that the public should be able to
access. The most ideal way is a website, understanding that isn\'t
necessarily a legal document.

MR. WIESE: Yeah.

MR. KUPREWICZ: Okay. If I can pass that on to the people who may raise
those questions.

MR. WIESE: Yes.

MR. BARRETT: That\'s what we\'re doing now, right, Alan?

MR. MAYBERRY: Yeah. (Off mic.)

MR. KUPREWICZ: Yeah, I understand that. Okay. But what was confusing me
was, I could see it in the initial phase but what happens? From my
perspective, I could just be missing it. By the time it gets to \-- as
you\'re evolving and evaluating the process and you may change some
conditions as you gather condition information or communicating amongst
the parties. You may have told an additional condition \-- again, we\'re
talking about a specific pipeline or pipeline segment.

I think the public, from the public perspective, what I hear constantly
on committees are, as a public person living by a pipeline, what can I
get to feel confident that people have everything under control. And
what I try to explain to people who don\'t get buried in details, don\'t
understand that the process makes sense, and usually you can get \--
Washington State has a very liberal public record process.

If I say we \-- that, but what I wanted to be sure of is if you have a
document that says you\'ve imposed an additional condition on you \--
let\'s say SSC. \"We\'re going to grant it to you. You have it under
control.\" But if the public perceives that as a real risk on this
segment and you haven\'t touched that part of it \-- then that final
condition, the public is going to come at you, probably. If you\'ve got
a letter saying here\'s all the conditions granted in your special
permit, it\'s on the website or wherever it is, it\'s a public document,
they can evaluate their own conditions.

MR. WIESE: Yeah, understood. Alan will certainly correct me if I\'m
wrong here, and I\'ll step out on a limb large enough to say that
generally speaking, though, Rick, what would happen is we would reject
it. So by the time we accept it, the conditions have been worked within
the special permit and that application is deemed satisfactory.

So we will reject it if they\'re not meeting the terms that we\'ve been
trying to lay out here. It\'s that simple. It ought to speak for itself
at the end of the day.

MR. KUPREWICZ: Yeah, but \-- I don\'t disagree with that. I\'m just
saying that a lot of effort is going to be involved here.

MR. WIESE: Sure.

MR. KUPREWICZ: You might go 90 percent into the process and then find a
new piece of data. We\'re not looking for everybody to just run the
bills up here. We\'re just looking \-- there may be a minor condition
here that a minor modification doesn\'t take you to the \-- option.

MR. WIESE: Right.

MR. KUPREWICZ: This is a safety factor, and it\'s just real important
that that final series of conditions be available to the public to make
sure everybody is under control. That\'s all we\'re asking.

MR. WIESE: Great.

MR. KUPREWICZ: Okay.

MR. WIESE: Thanks.

MR. BARRETT: Appreciate that.

MR. WIESE: I might \-- Zach, any other comments you wanted to add there?
I might just add \-- yes, you can just flip the switch. Anyone else have
a question? We\'ll reserve the general comments or statement for the
record, again, until the other panel is completed. Remember to state
your name and affiliation. Oh, you\'re just taking that. Okay. Thanks.

All right. Just if I can, just to close out this panel, speaking for
PHMSA, I will tell you that we would clearly prefer to have an option to
prescribe a risk-based approach to regulation. We don\'t have that
option right now for the reasons that we tried to lay out to you. Our
only alternative to deal with the risk that we think is relatively
minor, and it\'s something that I hope we\'ve tried to make a case to
you, that we and the industry have exercised a lot of controls on \--
you\'ll hear more about what the industry has done \-- as adequate, is
to use this special permit/waiver process that\'s established within the
code to do that.

I\'d like to make the case that \-- and thank you, Rick. There ought to
be a certain amount of transparency to this. I mean, that really is an
additional control, really, in some ways. So I guess I\'d like to make
the case for you that what we\'re positing for your consideration and
comment is, are these criteria adequate to deal with that risk. That is
really what we\'re looking for your comment and conclusion on.

So, at any rate, with that said, again, what we\'ll do is we\'ll take a
break, if we can, now. It\'s exactly 10. Can we take 15 minutes? We\'ll
come back at 10:15. We\'ve got one more panel. We\'ll take questions for
them. And then anybody is welcome to put a comment on the record. Thank
you very much.

(Brief recess.)

Findings to Date

Terry Boss

(PowerPoint presentation.)

MR. BOSS: Okay. I\'ll get started here so we can stay on schedule. My
name is Terry Boss. I\'m senior vice president with the Interstate
Natural Gas Association of America. We represent the interstate
pipelines that go through here. There are segments out there that are
also represented in this room.

I wanted to give kind of a background of what we have learned. I know
Jeff asked the question who is in the audience, and some of the things
that I\'m going to be talking about are going to be repetitive perhaps
for some folks, but I did want to give some background in case we have
some folks in here that have not been through this journey that we have
been through multiple years on these sort of things.

As far as background, I\'ve had about 20 years experience working for a
gas transmission company. Spent about a year on integrity management in
the Gas Research Institute and been at INGAA probably about 13 years,
involved in a lot of these different efforts that we\'ve had here. So
it\'s been a history for me and a history for a lot of folks in the
room.

One thing I did want to make some mention, again to get people situated
out here, this is a diagram of basically the natural gas infrastructure
out there. Primarily what we\'re talking about is that segment in the
middle, which is primarily transmission pipelines. There is a little bit
of overage on transmission pipelines on the upstream side and on the
downstream side in the local distribution companies that AGA represents,
and APGA represents on those sort of things.

One thing about our industry. In general, we\'ve got a fairly
homogeneous product out there, natural gas. That\'s helped us
significantly in doing a lot of the risk assessments and moving through
this process. It eliminates a lot of the variables as you go through
this kind of analysis.

This is a picture, a very gross picture, of some of the interstate
pipelines out there and the companies that are involved. Put that on the
website.

Of course, our goals. This is some repeating of slides that we had at
the PIPA thing. Basically, we\'re in the business to reliably transport
energy safely. If we have concern by the public or their representatives
on that, that\'s not good for our business and it is going to hurt us
very bad. So we\'re very concerned about that and our goals are not to
have any kind of events that are causing concern.

This is an overall slide to give you some perspective of the segments of
the industry we\'re talking about. We\'re in with this group right now
as far as serious incidents. The definition of incidents, serious
incidents, is up on the PHMSA website. Basically, that\'s injury or
fatality or a very catastrophic type of incident on that sort of thing.
So that\'s what we\'re working from originally throughout the years as
we\'ve moved here.

An important thing that we\'re looking at here is the slide to talk
about the infrastructure that we\'ve got to have quality control on the
type of operations out there. There\'s programs that we\'ve got out
there, practices, standards, codes, and regulations, that are adopted.
Originally, as I said, the natural gas industry has been around for a
while, primarily the transmission industry in the \'30s. There was an
extensive effort in the \'50s to standardize a lot of this stuff under
ASME, and granted, as I mentioned before, we\'ve got a very homogeneous
product. So you might say our Risk Management 1.0 plan was developed in
1950 under ASME B31.8.

A lot of that information that those gentlemen put together at that time
was then adopted into regulations. A lot of times then you get these
prescriptive regulations that are put together and some folks don\'t
understand, okay, why did we come up with this information.

The first effort we went into risk management demonstration was to
relook at the reasons for coming up with the standards and regulations
that we had from a risk perspective, and that was the Emeritus Report,
as we\'ve been through.

As we\'ve developed through the \'90s, we relooked at some of the things
that were going on. The OSHA process on safety management had come out.
We also had the EPA R & P program out. And we did a relook at our
regulations that we had out there, and our practices and so on like
that, to do a comparison point with those. Again, from a product
standpoint, because we were so homogeneous, in a lot of those cases we
did satisfy a lot of those criteria that we had there. And if there were
some gaps that were involved in those things, that\'s where we tried to
do some improvements.

So you can see at the time when those relationships were developed on
those things, the regulatory process relooked at process safety
management and so on like that, and did a comparison and a determination
that essentially the regulatory activity within PHMSA was essentially
satisfying the goals that were moving forward on that process.

The pipeline integrity management process has got principles out there:
the threat identification, characterization of the risk, the integrity
assessment, and preventative and mitigative measures out there. Some of
this is a repeat of what Jeff has said already today, and I just wanted
to essentially work on that.

The definition of risk that we\'ve got out there is probability times
consequence. Again, because it\'s got a homogeneous product, we\'ve got
a fairly good idea of the consequence on this, where we don\'t have some
of the issues that you did have in the OSHA process safety management of
trying to understand that.

Our main concentration from the original regulations and as we\'ve moved
through this thing is to reduce the probability of some of the events
that are moving through here.

One of the key concerns with natural gas being a flammable product is
the public safety that\'s involved in that. It\'s rather benign as far
as environment is concerned because it is a methane product out there.
You do have some CO2 concerns with all energy products that are coming
up in global climate change. But in general, the risk to what\'s going
on in the world is essentially a concern about human safety on that.

One of the difficulties we have these days is we do have a population
distribution out in the U.S. that is expanding and that is affecting a
lot of how we do look at these sort of things. A good example of this is
the pipeline that\'s going through here. You can see the population
encroachment going on there.

The original designers of that Risk Management 1.0 understood that sort
of thing and built into it a rather, at that time, sophisticated
criteria called class location. So as you had increasing population
density coming around the pipeline, you made changes to design,
construction, and operation practices as you moved forward on this sort
of thing. Quite a bit more sophisticated than the traditional
census-based type look at the thing because we were looking at the area
right around the pipeline.

As we moved forward in the risk management demonstration processes,
later on we determined with the new technology that we had out there we
could take a more sophisticated look on that thing.

Like I said, I\'ll rush through this quickly. A lot of folks have seen
this before, but we may have some folks in here that have not.

What I\'m depicting here is a pipeline out here that\'s going through
there. We may have some houses in there or some additional houses being
built. Right now the class location process that we had out there is a
dynamic process. As population changes, we make adjustments to the
system.

The original criteria that was out there that was set up on there to
simplify things was to essentially look at a corridor type base
arrangement around the pipeline to understand what population is around
there. As you move through that process, you could identify when you had
heavier population, like in density areas, and we moved to additional
criteria as we move through those processes.

So in this particular case, it might have jumped from a class one
location to a class three location and made different requirements on
that.

As we started on the risk management demonstration integrity work in the
latter \'90s and early 2000s, we came up with this more defined criteria
out there to come up with a high consequence area. We went through a lot
of data and analysis and research that was done to look at the accident
data and the homogeneous characteristics of natural gas and the behavior
on the worst case conditions on these pipelines, and we came up with
what we call a CFER circle. That\'s essentially an engineering-type
terminology to essentially address some levels of risk.

The idea of the high consequence area is essentially you look at this
criteria and you essentially walk down the pipeline and look at the
density of population on that. And when you have an area that fits into
a certain density of population, we overlay additional criteria on top
of the already risk management practices that were built into the O & M
procedures. This is the integrity management plan that we\'re talking
about here now that we\'re working on. So it\'s essentially \-- the
yellow section out there is what we\'re talking about on these type of
criteria.

In threat identification, and these are some generic slides, there is a
different criteria for the hazardous liquid pipelines because the
consequences to those folks of those type of events are slightly
different. But this is generic criteria. Like I said, ours is
concentrated primarily on the public safety, I think, but to identify
the threats that are put together on this.

There\'s a probability that those threats may cause some kind of
accident on those sort of things, and we have to identify the
probability that\'s going on there.

This is an example of a sheet that we pulled out of one of the reports
on there. Essentially, we went through during the risk management
demonstration gathering all the data for the data collections from \'70
through \'84, where we had a lot of information about not only the
failures we had on the system during operation but any kind of
maintenance failures on hydrostatic testing. Through the \'80s and \'90s
and so on like that, improvements in the form to get a better idea and
clarification of the threats that are out there. You can see we\'re
roughly up to about 23 distinct causes out there that we can break down.

In a lot of cases, what you want to understand is you want to understand
what is causing the event. There may be different activities to help
mitigate or prevent that effect, and they may be different. That\'s why
we\'ve broken them down into all these different classifications.

Consequence assessment is essentially looking at the situation. A lot of
work went into these \-- I think Daron is right over here \-- in
defining that. A lot of dialogue with PHMSA and so on. We built off of
the original criteria class location, but we were trying to identify
those special locations, the nursing homes, et cetera, that are out
there that we wanted to have a little bit more care in those things to
be more assured that those efforts are being through, and on the
consequence assessment.

Again, a lot of work was done on the consequence because of the
homogeneous product, which made it a little bit easier for natural gas
to do this rather than some of the other products to see what was going
on.

Consequences. This is, again, a chart out there. This gives you some
idea of, when we have had incidents, both an idea of the injuries and
fatalities out there and property damage that are involved in the thing.

Additional analysis is going on right now, and some of this is going on
in the PIPA. What we\'re looking at is categories of people that are
affected. In some cases the employees, in some cases emergency
providers. Other cases, it may be excavators, and then there\'s the
general public. So it\'s a good idea to understand who is the affected
population and how do these different threats and probabilities affect
those things.

The final thing is to go into the risk determination process of what\'s
out there. We\'ve broken the causes out there into static defects. These
are defects that may be present in some of the locations during
construction, and as technology improves we may identify some of these
static defects that are out there. Essentially, it\'s a defect. Once you
find it and you eliminate it and you mitigate it, that defect does not
come back.

There is time-independent defects out there. Those are very similar to
defects that occur when you have an excavation damage or some event that
does not have predictability out there on when it does happen.

And then time-dependent defects: something that you can forecast over a
period of time where there may be some technology or process that you
can go in and examine the pipeline every once in a while and then get
some kind of predictability that you will be able to manage the
situation. A very good example of that is corrosion, where there is a
time-based thing.

A lot of the things that we\'re talking about on the IMP program are
based on the time-dependent thing, and that\'s the focus of the
seven-year thing. But the key criteria that you need to know is the IMP
program does address the static and time-independent events here and the
extra efforts that we\'re trying to control those things.

Again, the methodologies that are out there right now are in-line
inspection, pressure test, direct assessment, and new technology that
may be out there. We\'re working on a lot of new technologies to try to
improve this process. And you\'ve got to pig and background to do that
sort of thing.

After we have determined what is out there on the assessment, there is
protective and mitigative actions. It\'s one thing to repair something,
but it\'s an additional step to find out, well, why was that happening.
If you have a general process in there and something isn\'t working
quite right in this place, that additional step of mitigating that so
you don\'t think that \-- or, you try to prevent that issue from
happening in the future.

Some important documents on there on what we\'ve learned on the
integrity management program on there. The GAO report that was mentioned
before is up on their website. That has been submitted to Congress and
put through there. We just finished a report on comparison of assessment
techniques. The INGAA Foundation put together a report on that. I\'m
going to pull a few excerpts out of that.

The INGAA Foundation report. Essentially, there is a diagram in there
that talks about this process, and I won\'t delve on that. Essentially
what is out there.

The approximate statistics that Jeff went over. These are about the same
things that he has out there, to give you some idea of the coverage on
that sort of thing.

An important note to make out here is, as the industry moves forward on
these sort of things, there\'s practices out there that individual
companies are putting together. And then eventually these practices
start moving around and they become best practices. When these best
practices gel together, then you may end up having standards like
B31.8S. Those practices are so good, and there may be some recalcitrant
players out there, then you get a regulatory process. That\'s when we
get the IMP process in there.

So essentially what we\'re doing is we\'re taking a lot of the
technology and practices and putting those together in a standardized
process to help that, and eventually you do get the regulation.

The assessment technology split that\'s out there. Primarily, the total
number of miles that are being inspected are overwhelmingly done by
in-line inspection. Once you do modify your facilities, that is probably
the easiest method to do that. One of the difficulties that we had with
the Gas Integrity Management Program rather than the Liquid Program, is
gas is a compressible fluid and we didn\'t have the facilities installed
to run these in-line inspection devices because of the different sizes
of pipe and different equipment that was in there.

So the original baseline period of 10 years was really established to
permit the gas pipeline industry essentially to modify a lot of their
facilities to put this equipment in and make that big expenditure moving
forward on that.

A little bit of hydrostatic pressure testing done. The key factor is
that ILI doesn\'t necessarily cut off the flow all that much except when
you\'re installing a lot of those facilities. So it\'s primarily ILI
that\'s being done on this.

Again, I\'ll refer you, because you probably can\'t read these things,
that these will be up on the docket, but the reports are on the websites
and are available for downloading on these things. This gives you some
kind of idea of the period of years that we\'ve been in the standardized
program.

Let me emphasize this. One of the values of the Integrity Management
Program is not only standardized processes but the standardized
collection of data. There was a lot of sharing of information within the
companies. Their methodologies may have been a little bit different. But
what this does give us is a very good database of information out there
across the whole United States.

I\'m going to be speaking in Europe here in about two weeks or so.
We\'ve got a great advantage over those folks because they don\'t have a
lot of information that\'s available transparently to share on those
sort of things. So that\'s one of the advantages of the IMP program, is
a lot of the sharing of the data and being able to understand better and
more quickly improve our processes as we\'re moving through here.

I put these up on the slide so you can see them more directly. This
gives you some idea of the results that are coming through under the
establishment of the program and some idea of these out there and the
repairs that we\'re going through here. Essentially what we\'re
addressing on these immediates and schedules are essentially precursors
to events. So not only are we trying to control the incidents on that
but control the precursors which are established out there. It gives you
some idea of the things that we have experienced here.

One of the other things that has gone on \-- and Jeff alluded to it and
we put it in our report \-- even though there is a very systematic and
structured process that is being reported to the federal government
under the HCA areas, there is a lot of fine work that\'s going on
outside these HCA areas on that. The HCA really is taking credit for a
lot of these integrity inspections out there.

What we have done is we have published a lot of that information in the
areas outside of the HCA areas, and we are looking at the rates that are
occurring in those areas to see that we are getting comparable type of
results both in the HCA areas and outside the HCA areas as we move
through that on those. That\'s depicted here.

As far as the GAO report that is out there, this was published in
September 2006. This is a rather extensive effort of the Government
Accountability Office.\
One of the main concerns, and a lot of folks are probably, if you\'re
not familiar with this, are asking the question, okay, what\'s going on
with the seven years. Why are we discussing that. The particular layout
\-- we\'ve done an extensive effort where we\'ve got to modify our
system to do those sort of things, and then we will have to start and do
a reassessment period on that. There is an overlap of a lot of work on
that, and there is disruption on a lot of the things. We are out to
reliably provide energy.

One of the concerns is not only a resource issue but also a
deliverability issue of natural gas on these things. We want to be sure
we can minimize the effect of this without affecting the safety of the
process as we move through here.

So the timeline of the process is essentially we\'ve got a lot of
overlap occurring on the thing and the question about just the efficacy
of the seven-year requirement, which is essentially a political
compromise that happened in Congress on those sort of things.

This gives you some kind of idea of the overlap. The darker gray type
indications are the original baseline tests that we\'re moving through
here. And then as you move into the reassessment process, you layer on
those inspections on the same time. What we\'re trying to do is trying
to manage that situation so we effectively are improving the safety as
we\'re moving forward here but we\'re not affecting our reliability or
resource problems on that.

One thing that we want to be very, very cautious about as we move
forward, we want to do these extensive efforts in the high consequence
areas on there, but the high consequence areas are not necessarily the
whole pipeline. We\'d like to be able to allocate our resources to a lot
of those areas as we move forward on the process. So, doing a lot of
overwork in one area doesn\'t necessarily help as we move through this
process. We want to effectively allocate our resources on these efforts.

As far as the results that are out there, and this is a natural response
to it, the public had a concern about the conditions of the pipelines
out there because they had a lack of knowledge about the pipelines.
What\'s happened with this consistent program and consistent reporting
of this information is more information is available out on the stated
conditions on that. As GAO went through that, what they were determining
was that anxiety that was out there about the conditions of the line
isn\'t necessarily needed. The condition was a lot better than people
had feared was out there on the gas transmission lines.

The conclusion was that GAO thought the seven-year prescriptive
requirement was conservative and that it should be more of a risk-based
type thing. Again, these reports are available for looking at.

Conclusion. The IMP has been very effective in improving and
standardizing the risk management protection out there. That goes all
the way to the reporting, which then gives confidence to the public and
the regulators of the processes now out there.

The natural gas transmission system is in better condition than the
public had perceived. The congressionally mandated reassessment interval
in general is too conservative. It should be more of a risk-based type
thing. And the technical tools and techniques that we have out there are
available to do more sophisticated analysis on this sort of thing to
manage the risks out there.

Operator Utilization

Bob Travers, Spectra Energy

MR. TRAVERS: Good morning. I\'m Bob Travers. I currently head up the
integrity program over at Spectra Energy, the operator formerly known as
Duke.

First of all, the reason I\'m up here, and Daron on my right, we
participated in the development of the framework that you\'ve seen
presented to you this morning. Helped out in getting that up and
running. And we\'re here to offer an operator\'s perspective on a few
issues. I\'ll speak to a few technical elements and Daron will talk a
little bit about a few process elements.

But first and foremost, we want to offer our support of this risk-based
approach. We think it makes sense over the prescriptive seven-year time
frame. In some cases, the right answer may be eight years, nine years.
In some cases it might be shorter than seven. This provides a vehicle to
do the right thing and get our lines inspected at the right frequencies.

I\'ll address just a few of the technical elements, as I said. Some of
this may be a little bit redundant with what was said this morning, but
just to reemphasize a few of those things.

As you saw this morning, some criteria has been established to identify
which lines are valid to participate in this program. Quite simply,
there are a number of things that would disqualify you from this, one
being possibly if you\'ve had a corrosion-related leak, a
corrosion-related incident over the last few years. Quite simply, it\'s
just not eligible for the program.

As Zach mentioned earlier, there are a number of other things that will
just require some extra justification. If you\'ve had some MIC or SSC or
SCC, clearly it\'s something we\'re going to have to make a very strong
justification to PHMSA as to why we feel that this segment could still
participate in this program and why going to eight or nine or 10 years
on the ILI frequency doesn\'t cause a problem given the history that the
line has.

Speaking for myself and for Spectra, this for us will apply to a small
handful of our lines, somewhere, maybe, between 10 to 15 percent of the
ILIs that we would do on a given year. I don\'t anticipate going for
much more than that, so we would probably be looking at somewhere
between five, seven ILIs per year that maybe we would submit and request
to participate in this program. But I don\'t think it would be too, too
much more than that.

It goes without saying this is going to be limited to lines that
performed very well on their last in-line inspection. Quite simply, it
wouldn\'t take more than a small handful of anomalies scheduled out to
years eight or nine where it\'s just going to be more cost effective to
run at the normal frequency than to dig those additional anomalies. So I
think that all factors into what I said earlier.

We don\'t anticipate this being a big part of our program. Probably more
the exception than the rule. I think some operators would probably have
a higher percentage of their lines participating in this program, but
speaking for myself, we\'re probably in that 10, 15 percent range.

That was really all I wanted to say. Everything else had been addressed
earlier. So I\'m also up here to answer the questions that come after
Daron is done. But at this point I\'ll throw it over to Daron. Thanks.

Presentation by Daron Moore, El Paso Natural Gas

MR. MOORE: I\'m going to stay seated if we can get the microphone to
work properly for the court reporter. Is this adequate? Thank you.

My name is Daron Moore with El Paso Corporation out of Houston, Texas.
I\'ve been working on pipeline safety for about 12 years now. As Jeff
started off the discussion this morning, I was the one that raised my
hand who had worked on risk management. That\'s about when I started. I
remember the public meeting down the street at the Crystal City
Marriott. Some of you in the room might remember that meeting. That\'s
kind of when I got started in all this.

My time in pipeline safety has extended through integrity management
today, with stops along the way in specifically operator qualification
and a few other technical issues that I\'ve worked with PHMSA on. So
I\'ve been heavily involved in PHMSA\'s regulatory agenda over the last
12 years.

My comments are primarily as an INGAA representative from the El Paso
perspective. We agree with Zach\'s presentation and the technical
criteria. We think it\'s technically founded. We think it\'s
data-driven. We see opportunities for it to be transparent. We think all
those things are key to the success of this program both internally to
El Paso as well as publicly for PHMSA and, perhaps most importantly, to
the public, being able to see what we\'re trying to accomplish.

I have a few INGAA comments now that I\'d like to make on process that
the pipeline operators see in this. I\'ll go into those now.

We think that we can build on prior successes. There have been a number
of prior successes that INGAA operators have had with PHMSA over the
last decade or so. Primarily, and number one, is the Integrity
Management Rule itself. INGAA stepped up and built, along with help from
some of the other trade associations, a national consensus standard
called B31.8(s) which formed the framework for this rule. It was a
resounding success, and we want to continue to build on those themes.

The class location special permit criteria. There are some issues around
the special permits themselves. The criteria that we jointly developed
with DOT was successful. We want to build on that, also.

Finally, in OQ, we had a gun pointed to our head back in 2002 and we
developed frequently asked questions on inspection protocols, which led
to further inspections of the operator qualification programs. That I
thought was a big success as we stabilized the operator qualification
environment that we did not have the stability on in the early 2000s.

We want to build on those successes as we go forward. We think this
program has the opportunity to do that.

Specific concerns. I have six, and they\'re more cautions or comments,
not necessarily just concerns. I want to be very clear that these are
not negative comments.

Number one, success in this program we believe is due largely to timing
and consistency. We didn\'t talk too much about the timetable that Zach
laid out which started in, I believe, February of each year and
concluded in June or July of each year, why that was so important to
operators.

Number one, February is important because we\'re only looking one year
out. It\'s a rolling year. We can\'t predict as operators what our
threats are going to be on our pipeline more than about a year or two in
advance. So it doesn\'t make sense to ask for an extension from seven to
eight, nine, or 10 years if we can\'t predict what the threats are going
to be.

But on the other end, on the July-June end, we\'re limited by our
budgetary constraints. We need to know as operators what we\'re going to
be doing in the following year. Those decisions are made typically, with
most operators, in the summer period the year prior. So we have some
constraints there that we need to work within and try to make it happen.

We also think that there may be some need for consistency in our
application process. I\'m thinking in terms of a form that has the
relevant data that DOT needs to have to make their decision. In the
past, for special permits, 80 percent, and class location in particular,
the applications have been company-specific with data scattered, I\'m
guessing, all through the applications and different between El Paso
compared to Spectra, compared to Panhandle, compared to other operators.
Perhaps having a common form would facilitate, one, INGAA companies
supplying the data; and two, DOT being able to evaluate that data again
in a timely fashion, as I mentioned earlier.

The programmatic information is at the headquarters of DOT, programmatic
being the performance of operators in their integrity management
program, O & M plans, drug and alcohol plans, operator qualification
plans, and ongoing. With that programmatic info being housed at the
headquarters location primarily, we think there\'s a lot of room for
this program here to be headed up and started and finished at the
headquarters location. I\'ll talk some more about that in a few minutes.

Dedicated resources at DOT. We talked about that. There was a question
about that this morning. We also think that there will be more and more
easily dedicated resources at the headquarters facility than there may
be at various regions out in the field for DOT.

Item Number 2, the integrity management plan inspection issues may still
be outstanding for operators. There have been a number of inspections of
operators over the last two years. I don\'t know what the percentage is
of which ones have received some form of enforcement letter, but the
percentage is relatively high and it\'s much higher than what we saw in
the first round of inspections for the hazardous liquid pipelines.

I believe Zach addressed this as well, and we agree that even if you
have some level of enforcement action, as long as that\'s not systemic,
as long as it\'s not programmatic for the operator and the operator is
diligently working to resolve those issues with DOT, we think that that
should not stand in the way of an operator submitting a special permit
and ultimately being granted a special permit for this discussion we\'re
having today.

There are honest disagreements in those inspections where operators
disagree with some of the assertions and interpretations of DOT.
Sometimes the operator agrees with DOT, and there have been occasions
where DOT has agreed with the operator. So obviously, there\'s some give
and take there, and we need to take that into account in this program
and not have operators be tossed out just because there may be an NOPV
or an NOA on the operator outstanding.

Finally on this topic, there have been some relatively long time
intervals between the time the inspection took place and the time the
enforcement letters may or may not have gone out. The longest I\'ve
heard of is in the neighborhood of 66 weeks, but there are some that are
approaching that and are still outstanding. That would not be fair to a
given operator to be held out because of something beyond his control. I
want to make that comment.

Item Number 3, we believe strongly that the process needs to be defined.
Zach has defined that well this morning. Concurrent with that, it needs
to be repeatable year over year over year. We think that\'s key. One,
that\'s for timing and budgetary reasons.

I\'m concerned, and I think that all the operators \[were\] when they
saw the slide earlier this morning that had the roughly 12 points. But
it was three columns, multi colors, with multiple time frames in there.
I got very concerned that that could be accomplished in the review
process from a February to a July time frame. If we need to sharpen that
pencil and get it right, then industry, and specifically the INGAA
operators, are more than willing to work diligently with DOT to make
that happen. I\'m just not certain right now how that\'s going to play,
so I wanted to toss that out as a concern.

We want to make sure the technical benchmarks are clear. I think they
are from what Zach presented earlier today. That was good. And,
transparent to the public in both data and programs. We think that\'s
important. We want them to be able to see what\'s going on. Having
multiple dockets, one for each operator or one for each piggable segment
or one for each year may not be the best way for the public to see this.
I would encourage perhaps a webpage dedicated that DOT has in the PRIMA
system or somewhere else to make it a little bit easier for both
operators, the public, and perhaps even DOT personnel to access.

Item Number 4, active program administration with robust controls. This
is inside the operating companies. It\'s cautioning ourselves. PHMSA has
learned a lot about our operations during their long inspections. For
the public, the inspections have lasted usually two weeks with a team of
five to eight inspectors coming in. El Paso\'s lasted three weeks. So
they\'re long, detailed inspections with long discussions.

PHMSA has learned a lot from that, and so have the operators. PHMSA has
an idea of who has management commitment, not just to sign the data form
we have to send in once or twice a year, but true commitment to pipeline
safety. Only those operators that PHMSA is comfortable with should be
allowed into the program.

Item 5, desire for a defined dispute resolution process. If there is a
disagreement, particularly in the special permit application, and I can
think of issues perhaps being the SSC issues and a couple of the others
that Zach mentioned, we\'d like to see some sort of defined dispute
resolution process. We don\'t think that\'s too difficult, but one that
drags on for a number of months and results in hearings or whatever else
may come up probably is unacceptable given the time constraints.

Finally, Item 6. I mentioned this a moment ago. Must have senior
management support, but not only support, also involvement, and their
commitment. If that doesn\'t exist, this won\'t work. The internal
processes must be robust and sound inside the company, and the company
safety culture must be firmly established. In our discussions with Zach
and his team over the last number of months, we\'ve talked about safety
culture. He\'s made it very clear that they will make that part of their
evaluation process, and that\'s appropriate.

A couple final comments. Operator submissions should be data-driven with
all the risk factors accounted for. We\'re required to do this by rule
as far as the risk factors are concerned, and I think most companies are
doing that based on the readings I\'ve had of the various enforcement
letters.

Only appropriate segments should be applied for. That\'s what Bob said
just a moment ago. If we\'re applying for extensions in time on segments
that don\'t meet the technical criteria or are borderline, we\'re only
setting ourselves up for failure and DOT up for failure and
second-guessing by the public and loss of confidence, and that\'s not
positive.

The programs must be consistent and repeatable in approach and
execution, and finally, with safe operation being the paramount goal in
all of this. That\'s clearly what operators are about and that\'s
clearly what DOT is about, and it\'s clearly what the public is
demanding. My final comment is we think this is what Zach said this
morning and what he said prior to today, and it\'s what we think gives
this program the best chance for success.

That concludes my INGAA comments. Thank you.

Question-and-Answer Session

MR. BARRETT: Since you were having some difficulty with questions and
comments earlier, we\'d ask, if you have any of those, please step
forward to this mic, Station A. We open it up to any questions or
comments that you have for this panel.

MS. EPSTEIN: Lois Epstein with LNE Engineering and Policy. I had a
question for Daron. I just wanted to get your reaction to the discussion
earlier that some of the applications that would come in would look good
and would be high priority and others may fall down. It\'s getting at
the question of does DOT-PHMSA have the resources to oversee this
program right now.

MR. MOORE: Lois, I think it ties in with the forms discussion I had a
while ago. It\'s clear to me, both today and prior to today, that if you
don\'t have a strong application \-- and I don\'t mean strong
technically in this sense, I mean strong in the sense of organization
and its clarity and timeliness. If you don\'t have those things in
place, DOT is not going to have as good an opportunity to evaluate it in
a timely fashion. Clearly, if you\'re making the effort to put all this
data together behind the scenes, and this is not going to be easy for
operators to do, we want to have the best chance of getting these
special permits accepted and granted.

That\'s the onus I think Zach was trying to say, and it plays directly
in line with what we\'re concerned about. Did I answer your question,
all of it?

MR. BOSS: The thing that we want to emphasize is the upfront work both
from the companies and PHMSA to get a Web portal established on this and
to achieve the goals of getting the data out there both from an
administrative process and clarity on fields that are out there and then
also from a transparency thing. So it\'s kind of a front end-loaded
process which we\'re promoting that will ease the administrative process
later on as we move forward.

MS. EPSTEIN: So in some sense the best case scenario is all the
applications are in really good shape, and that\'s almost the worst case
scenario for PHMSA because they may not be able to handle it. That was
just a comment.

MR. BOSS: Well, the key is if an administrative process is set up and we
are building off an integrity management process that\'s already out
there, we\'ve already been audited, a lot of these \"questions\" have
already been put together, it\'s a matter of structuring it such that
all the decisions that have been made in the past on there are put in
the same place so you can very quickly say, okay, we\'ve done this
audit, we\'ve seen this, here\'s the technical criteria. X marks the
spot on that. Then it\'s a fairly quick decision.

That\'s probably the biggest thing on the earlier question you had
versus waivers versus special permits. Special permits are designed to
be very structured such that everybody knows what the game is, rather
than a wide-open waiver, so that they can go ahead and apply it on those
things.

MS. EPSTEIN: And maybe this is a question for Zach. Is there a guidance
you\'re writing? Daron\'s point about an application process, how is
that going to work?

MR. BARRETT: We will have to develop some standard formats, not only for
our website, so we can be transparent with what we\'re sending out to
people and what\'s there, but for internal reviews and that sort of
thing. But they\'ll contain the elements that you saw in my
presentation.

Our reviews would be a review of whether or not you have an integrity
management plan. We will go to our websites and have our people check to
see, yes, they have a plan; yes, they\'ve been audited\' what were the
results of that audit; is there anything that concerns us in the area of
threat identification or those issues; are there outstanding violations
or notice of amendments. We\'ll look at those areas, also. But we
haven\'t put those in a structured format yet. We will have to do that.

Any other questions?

MR. MOHN: Jeryl Mohn from Panhandle Energy. A clarification, I guess,
for our industry panel. What is the first year under the seven-year
criteria where operators would be doing reinspection where the special
permit process might apply?

MR. BARRETT: Do you have any coming up in the coming year?

MR. MOORE: We envision being able to make application this year, in the
next couple months, with approval coming sometime later this year,
obviously.

I wasn\'t sure they could hear me. I heard some mumbling out there. I
guess they can.

With next year\'s being \-- the seven years expiring next year being
moved back one, two, or three years from there. So that would be the
2009 scheduled inspections being moved back possibly as late as 2012.
Consistent with you, Zach?

MR. BARRETT: Obviously we\'ve got some work that we have to get done to
allow that, but they actually would have to come in for this year for
next year\'s evaluations. 2009 would be the first year the seven-year
reassessments would come into play under the rule.

MR. BOSS: I think as far as the number of events going on there\'s a few
inspections that have the probability of being in this program this next
year, but the bulk as you move forward year by year is actually going to
be in the following year. So you might say this is almost like a pilot
stage as we move through this process to get it established.

MR. BARRETT: Other questions from the floor?

MR. ADLER: Thank you. Dave Adler, NiSource. Zach, you just mentioned
that guidance will be \-- is being developed. I think that\'s a great
idea. I hope there will be some opportunity for input from the public
and industry.

For example, and there will be a number of such issues, but I\'m
thinking of a line \-- several lines we have that may be 1,500 miles
long, all with the same name. Parts of this line \-- let\'s take near
Nashville, Tennessee, for example \-- contain much newer pipe. Other
parts contain the original pipe from the original construction. In some
of the original areas we might feel it\'s important to inspect more
frequently than every seven years, and we might like to get a special
permit for areas where we can inspect the newer pipe and we find it to
be in better condition.

Yet, what I\'ve heard a couple times this morning is if we\'ve ever had
any pinhole leak in our line, and I assume that means a line that shares
a common name, then it may kick it out as a candidate. I think that
would be a situation where it maybe should not be kicked out as a
candidate.

MR. BARRETT: I can clarify that. What we\'re looking for when you send
your applications in is for individual HCA segments, is what you\'ll be
sending in. We\'re talking about the shape of the line, the criteria,
the details. It will be looked at as an individual HCA segment. So it\'s
not Line 100 by Line 100, it\'s HCA \-- you\'ve designated those HCAs
from milepost to milepost or from station to station.

So if you\'ve had an assessment on that HCA, what date was that. If
you\'ve had any subsequent leaks or corrosion issues from the time of
that assessment, that\'s what would limit that HCA from the reassessment
period from the special permit.

So what we\'re asking for is specific information to a high consequence
area, a covered segment. Does that help?

MR. BARRETT: Any other questions from the floor?

MR. KUPREWICZ: Just a quick observation because I get this feedback from
the public all the time. I guess I\'m going to address it to everybody
here. I often have to advise highly energized public persons who are
legitimately energized for various reasons on their own perspective. But
I think I would advise the process players here, we\'re not here to run
up your bill on inspections. I think it\'s important that everybody stay
focused, including the process.

I don\'t have a problem with the special permit process from a technical
perspective. I think you want to \-- and it sounds like you\'ve been
doing your homework on all parties. That\'s a good thing. I think what
we have a hard time communicating to the public is the frequency of
inspections are a rather irrelevant issue if the quality of the
inspections are not well done. That\'s a hard thing to get to the
persons who are really energized who don\'t understand the technical
aspects.

It does not surprise me to see or hear some of the information today
because, like in all good operations, there are many good operators and
then there are a few goofs. The goofs can create a lot of problems for
everybody for various reasons. And I\'m being polite calling them
\"goofs.\"

So from our perspective, my feedback from a public perspective is to
keep the process focused on the quality and is it addressed to the
specifics of the pipeline and the frequency itself. Let\'s not lose
another perspective. It hasn\'t been too many years ago that you really
never had to do inspections on your pipelines at all, technically, in
regulation. So we\'ve come a long ways here, and that\'s a good thing.
So I just want to watch that the amount of volume coming at you causes
you to lose the quality.

MR. BARRETT: Appreciate those comments. Any other questions from the
floor? Yes, sir.

MR. BRESLAND: I\'m John Bresland with currently EPA, formerly Chemical
Safety Board. I think it was Daron who brought the issue of safety
culture. I think you said that the companies without a strong safety
culture would fall out of this program. Does PHMSA or the industry have
any measurements or assessment tools for safety culture that are
currently being used?

MR. BARRETT: We haven\'t done a criteria or inspections for safety
culture. However, we do have data that we gather from our inspections
that bring indicators to us of concerns that we may have in certain
areas where we may ask some of the higher-level management to come in
and visit with our higher-level management to discuss issues about how
they\'re managing their systems, their pipeline systems and that.

So it hasn\'t been formalized yet, but we do have kind of indicators or
triggers that cause us concern from time to time to ask an operator to
come in to do that.

I think really overall what we\'re getting at here is that we\'re
looking for operators who are open and transparent with us and are also
willing to play well, willing to exchange ideas, willing to open their
books to us, willing to allow us access into areas that we feel that we
need access into without a lot of barriers and difficult and fights to
be able to get the confidence that we feel like we need to do something
additional and special in this. So that\'s the best I can characterize
it for you at this level.

Jeff, do you have any \-- is that a fair characterization?

MR. BOSS: I think from an industry perspective we\'re very cognizant of
that. Like I said, one of the big advantages that we have, you do have a
diverse culture as you move geographically across and so on like that.
But we do have a rather homogeneous industry. One product, a lot of the
technology that everybody is using on there, the management processes,
and so on. So there\'s a lot of sharing that\'s going on, so that does
facilitate that communication and understanding by PHMSA as they move
from company to company on some of the attitudes and the culture
involved in those sort of things. It does help that.

MR. BARRETT: Any other questions from the floor? Hearing none \--

MR. WIESE: Since this is a public meeting, I\'d like to give everybody
one last opportunity just to put a comment \-- it doesn\'t have to be a
question \-- to either panel. But if anyone would like to take a last
opportunity to put a comment on the record in favor or opposed, whatever
you wish. This is really the best opportunity to do that.

We do have a docket. You can submit things to the docket for this. I\'d
welcome any comments anyone has.

MR. BARRETT: To repeat that, any comments that anyone has, this is the
most opportune time to get that into the docket. So I\'d open this up to
comments and not just questions at this time. So, any comments you\'d
like for the docket, please come forth and state them. Anybody that has
comments for the docket, please \--

(Laughter.)

MR. LUU: Thanks. Good morning. Andrew Luu with American Gas Association.
I just want to reflect the position and comments from AGA as well as its
members. AGA would like to commend PHMSA for its efforts in initiating
and developing this proposal for a special permit process which would
provide authorized operators the opportunity to perform integrity
reassessments beyond the seven-year interval for those pipelines that
meet the technical criteria as specified by PHMSA in concert with
national pipeline standards.

The mechanism will allow operators to prioritize their resources so they
can be expended on the pipelines which truly represent the greatest risk
to the public.

In general, AGA is supportive and in agreement with both the proposed
process and criteria associated with the special permits. There\'s two
issues which AGA would like to provide comment on, and they were raised
a little bit earlier but we just wanted to reemphasize it.

We wanted to point out that the slides were mostly geared towards having
a successful PHMSA audit. For operators \-- for the local distribution
companies who are under the enforcement of a state regulatory authority,
an audit conducted by the state we feel should satisfy this particular
requirement the same as a PHMSA audit. In essence, an audit by a state
agency should be as credible and as acceptable in this particular
process as a PHMSA audit, we feel. We don\'t understand why that would
be any different.

Secondly, we feel it\'s critical to revisit this criteria and the
process periodically to consider whether any changes or additions are
warranted based upon industry findings from integrity assessments. The
industry is still largely in a learning mode. We all know that. The rule
has only been in place since December of 2003. In particular, operators
and regulators are still gaining familiarity and confidence in all the
intricacies associated with direct assessment, ECDA, ICDA, and SSCDA.

While AGA can agree at this time that candidate pipeline segments should
have at least one prior inspection with ILI and pressure testing \-- or
pressure testing I should say, as the assessment method, there may be
one day in the future where it\'s appropriate to allow those lines
inspected by only DA as eligible for special permit consideration.

Again, we realize that DA is still evolving and it is not our intent to
initiate a technical discussion at this time on the merits of DA, but we
just wanted to get that on the record. Thank you.

MR. BARRETT: Thank you, Andrew. The point of clarification with the
slides I think, especially some of the previous slides, they didn\'t
have \-- they had a PHMSA audit. I tried to amend those before this
meeting where they had a PHMSA/state audit. We did intend for a state
audit to bear the same weight as a PHMSA audit in the review of the
special permit, something that came from an intrastate line to a state
organization. So, appreciate your comments.

Any other comments for the record?

MR. TRAVERS: I have a question, if it\'s okay to ask a question.

MR. BARRETT: You bet. Sure, sure.

MR. TRAVERS: Bob Travers, Spectra. I was wondering if, Zach, either you
or perhaps Jeff could speak at all to where you see this going in the
future in terms of legislative change. Will this live for a while as a
special permit process? Do we anticipate within a few years that this
perhaps could move to a rulemaking through legislative change on that
seven-year requirement? Just the issues around that. Wondering what your
thoughts were on that.

MR. WIESE: I didn\'t think Zach wanted to take that one, but thanks for
bringing that up, Bob Travers. Okay.

(Laughter.)

MR. WIESE: I think the simplest way for me to answer this without
getting myself in trouble is we don\'t have the statutory authority at
this time to enter into the regulatory side. I guess it would be my hope
that the experience we can gain with the special permit process, in
addition to the GAO report, in addition to the Secretary of
Transportation\'s letter to the Hill, would someday give us the
opportunity to ask the Congress for that authority. But right now we
lack it. We\'re not in a position to lobby Congress, obviously.

But we can consider suggesting to Congress that we be given that
authority. Perhaps the experience with some of these special permits is
really the icing on the cake.

So again, until such time as we\'re given the authority, really this is
the only route we can take.

MR. MOORE: Daron Moore. We would, as industry, certainly appreciate your
support in the next reauthorization to have this considered by Congress.

MR. WIESE: Okay. Any other comments?

(No response.)

Conclusion

Jeff Wiese

MR. WIESE: Okay. Thank you very much. It was a good discussion this
morning. I\'m glad we were able to get a couple of things out. Just keep
it in your forefront of your mind. As we talk about these things it\'s
important to talk about not just the pipelines but also the process
quality and the people quality. So, thank you.

(Whereupon, at 11:15 a.m., the meeting was concluded.)