Legislature(2007 - 2008)Anch LIO Conf Rm
06/07/2007 09:00 AM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation - Taps Tariff Proceeding Before the Ferc; Oil Pipeline Integrity and Corrosion. | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
June 7, 2007
9:08 a.m.
MEMBERS PRESENT
Representative Carl Gatto, Co-Chair
Representative Craig Johnson, Co-Chair
Representative Vic Kohring
Representative Bob Roses
Representative Paul Seaton
Representative Peggy Wilson (via teleconference)
Representative David Guttenberg (via teleconference)
Representative Scott Kawasaki (via teleconference)
MEMBERS ABSENT
Representative Bryce Edgmon
OTHER LEGISLATORS PRESENT
Representative Nancy Dahlstrom
Representative Anna Fairclough
Representative Berta Gardner
Representative Max Gruenberg
Representative Kurt Olson
COMMITTEE CALENDAR
PRESENTATION - TAPS TARIFF PROCEEDING BEFORE THE FERC; OIL
PIPELINE INTEGRITY AND CORROSION
-HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
ROBIN BRENA, Attorney at Law
Brena, Bell & Clarkson P.C.
Anchorage, Alaska
PHILIP REEVES, Senior Assistant Attorney General
Oil, Gas & Mining Section
Civil Division (Juneau)
Department of Law
Juneau, Alaska
RICHARD FINEBERG, Investigator
Research Associates of Ester
Fairbanks, Alaska
JONATHAN IVERSEN, Director
Tax Division
Department of Revenue
Anchorage, Alaska
TONY BROCK, Technical Director
BP Alaska
Anchorage, Alaska
JONNE SLEMONS, Coordinator
Pipeline Systems Integrity Office (PSIO)
Division of Oil & Gas
Department of Natural Resources
Anchorage, Alaska
ACTION NARRATIVE
CO-CHAIR CARL GATTO called the House Resources Standing
Committee meeting to order at 9:08:15 AM. Present at the call
to order were Representatives Gatto, Kohring, Roses, Guttenberg
(via teleconference), Kawasaki (via teleconference), and
Johnson. Representatives Wilson (via teleconference) and Seaton
arrived as the meeting was in progress. Representatives
Gruenberg, Dahlstrom, Fairclough, Olson and Gardner were also in
attendance.
^Presentation - TAPS tariff proceeding before the FERC; Oil
Pipeline Integrity and Corrosion.
9:08:15 AM
CO-CHAIR GATTO announced that the only order of business would
be a presentation on the TAPS tariff proceeding before the
Federal Energy Regulatory Commission (FERC) on oil pipeline
integrity and corrosion.
9:09:11 AM
CO-CHAIR GATTO explained to members the committee would review
the first red binder this morning and then break for lunch and
review the second red binder with the numbered tabs this
afternoon. He asked Mr. Brena to testify.
9:11:47 AM
ROBIN BRENA, Attorney at Law, Brena, Bell & Clarkson P.C., first
talked about his background. He grew up in Skagway, Alaska. He
is an attorney with the Anchorage firm of Brena, Bell and
Clarkson. He has an MBA in accounting and finance and a Masters
in Law degree in real estate development and finance law. He
has been involved in pipeline rate litigation for 20 years and
has been involved in 15 to 20 Trans-Alaska Pipeline System
(TAPS) cases. Relative to this particular case, he was the lead
counsel for Tesoro. He filed a complaint in 1976 to lower the
TAPS rates to reasonable levels, resulting in the Regulatory
Commission of Alaska (RCA) lowering rates from $4 to $2. He has
been the lead counsel for Anadarko-Tesoro's effort to lower the
federal rates, which has occurred.
MR. BRENA, in response to Co-Chair Gatto, clarified that he
represents Anadarko-Tesoro, with regard to the Cook Inlet gas
pipeline; Agrium, with regard to Alpine Pipeline Company; and
Murphy Oil. In general, he represents independents and value-
added manufacturers in Alaska.
9:14:12 AM
MR. BRENA began his overview, which consisted of 17 slides. He
told members:
... I wanted to start with just a broad overview and
perhaps just stating the obvious, and that is that our
oil and gas resources in Alaska have to move through
pipelines that don't have competition. They are
monopoly-controlled lines. Normal economic forces do
not operate with regard to these lines and so
regulation is necessary of them.
In looking at what kind of regulation is helpful for
these lines, there are just two things that I want to
focus your attention on: access and rates. If you
come away from this presentation with nothing else,
you come away with - get access right, get rates
right. If you accomplish those two things in the
future, it will maximize the development of the oil
and gas resources in Alaska. It will maximize the
state's revenues and it will encourage the development
of jobs and value added manufacturing in Alaska.
Those are important bi-products of just getting those
two issues right.
With regard to oil pipelines, they are common
carriers, so access is not a major issue. That's
quite different from gas lines in which they are
contract carriage lines and access is a major issue.
So the rest of my presentation goes to the second
element with regard to TAPS, which is rates and
explains how the initial decision fits into this. I'm
looking at the screen that the people in Juneau must
be looking at and I realize it's kind of hard to read
that. Let me start out by just saying that much of
the history of TAPS is determined off of a settlement
that was entered into by the state and the TAPS'
carriers in 1985.
9:16:15 AM
The TAPS settlement - there's four aspects of it that
I want to be sure that the committee is aware of.
First, I want to be sure that you understand what the
deal was. You're going to hear a lot of rhetoric from
a lot of people that I don't think accurately
represents what the deal was. So the deal was, in
'85, that they settle all prior rate issues, first of
all. All prior rate issues were final. With regard
to future rate issues from '85 forward, the deal was
that the state would not protest those rates so long
as they were at or below a ceiling rate that was
established under a methodology set forth in the
settlement, which I'll refer to as the [TAPS
settlement methodology] TSM method.
Importantly, they asked for the commissioners at FERC
and the [Alaska Public Utilities Commission] APUC
then, now the RCA, to approve that settlement under a
public interest standard and not under the just and
reasonable standard. Now that is perhaps the
distinction only a lawyer could love but it is an
important one for you to understand. When you have a
settlement and you ask for it to be approved under the
public interest standard, you don't look at whether
the rate needs to [indisc.] these criteria under the
just and reasonable standard. They specifically asked
both commissions not to take a look at their rates and
determine whether or not they were just and
reasonable. What they said is, if a financially
interested party in the future had a problem with the
rates, they could protest them, and if they protested
them, then the regulator would set just and reasonable
rates. That was the deal.
Now that's important because that's exactly what
Tesoro has done to the state rates and that's exactly
what Anadarko and Tesoro have done with the federal
rates. We have protested those rates as unjust and
unreasonable and asked that just and reasonable rates
be set.
Please understand that there's nothing in what Tesoro
has done at the state level. There's nothing that
Anadarko and Tesoro have done at the federal level
that resulted in any violation of the state's
agreement with the TAPS carriers. They are both
continuing to get the benefit of the deal that they
struck at the time in '85. From the state's
perspective, they are continuing to get rates at or
below the levels set forth in their settlement. From
the carriers' perspective, the state still isn't
protesting those rates as unjust and unreasonable so
you'll oftentimes hear that somehow the state is
reneging on this deal. It's not reneging on this
deal. The deal was the third party shippers in the
future could do exactly what we're doing and nothing
about it is - it's all consistent with what the terms
of the settlement were at the time.
But, that aside, when you try to understand TAPS, the
beginning point has to be the TAPS settlement because
that's the deal that's determined rates from 1977 to
date on the federal side and that's the rate that
determines the state's royalty and severance take.
9:19:38 AM
MR. BRENA continued with his presentation, as follows:
Now, I was asked to go into some detail and I can't do
it without talking about it, and just right up front,
some of these different terms that I'm going to be
using.
9:19:48 AM
CO-CHAIR GATTO asked about the standards used to distinguish the
terms "public interest" and "just and reasonable."
MR. BRENA replied the difference between the two standards is
the difference in the level of review undertaken by regulators
during the approval process. When determining a settlement,
regulators look at what is in the public interest. If a
financially interested party protests a rate, that party has a
right to have a just and reasonable rate set. No settlement is
involved so the regulators look at what constitutes just and
reasonable and, in general, that means a cost-based rate. A
cost-based rate was never set in TAPS history until the RCA
established one in the state rate at $1.96 a few years ago. A
cost-based rate has never been established at the federal level;
this initial decision establishes that cost-based rate. He
clarified:
So what we want ... by we I mean anybody that does
business in the state or the state - what they have a
financial interest in - is rates that are actually
based on the cost of providing service and no more.
I'll get into more detail in every word I just used in
just a minute.
CO-CHAIR GATTO asked if [rates] could change with changes of
volume shipped through the pipe.
MR. BRENA said if 2 million barrels are shipped per day and the
rate is $1 and everything else is constant, but then the volume
decreases to 1 million barrels per day, the rate doubles to $2,
everything else being equal. Throughput levels have not been
disputed in any of these cases. He stated:
We have stipulated to the throughput levels that the
carriers used so the throughput is constant. When we
talk about the difference between $2 and $4 between a
just and reasonable rate and the settlement rate, that
difference is attributable to excessive returns and
not to throughput or operating costs. We'll go
through that in great detail in a minute.
9:22:14 AM
MR. BRENA continued his presentation:
Okay, I've already started using some of the terms and
so on page 4 I define them. I'll stay with TSM,
because [that's] the method for establishing rates set
forth in the TAPS settlement. It's important to
understand that that's a settlement method in that
everyone that's taken a look at whether that method
results in a just and reasonable rate has rejected it.
It's been rejected by the RCA. It's been rejected by
the Superior Court. It's been rejected in the initial
decision by Judge Cintron. The TSM just doesn't
result in just and reasonable rates and I'll explain
in some detail why. It's fine for a settlement as far
as - I mean it met the public policy goals of the
state at the time, apparently, but it is not an
appropriate methodology to use for actually setting
cost based rates. So that's the TSM and that is the
method that's been used to establish rates for 30
years on TAPS.
The stand-alone cost method, or the SAC method - I'll
talk a little bit about that. The carriers, in
defending their TSM rates, have come up with different
theories. One theory is the SAC method and basically
what that method is it ignores the actual cost of
operating TAPS and just builds a hypothetical new line
and figures out what the costs would be and then
charges that cost. It's a complete exercise in make
believe. It's never been used to establish a just and
reasonable rate. It's never been used to establish a
revenue requirement. It is one of the theories they
advanced at the federal site to justify their rates.
It does result in rates beginning at $6.10 and going
up to $28 over the next 15 years. It is one of the
active theories of the case that they advanced to
justify their rates.
CO-CHAIR GATTO asked Mr. Brena, "Are you saying then that what
they would say is hey, if today we had to build the same
pipeline, we would have to charge this rate?"
MR. BRENA said that is correct. The rate would be based on the
cost of building a hypothetical new line today. It is
essentially a replacement cost approach to value without
depreciation. He noted as he continues his presentation, the
committee will see that some of the rate theories that have been
advanced are so extreme they beg the question of whether they
are good faith positions.
MR. BRENA returned to his presentation:
Now where the action is "Original Cost-Based Methods"
on the bottom of [page] 4. And there are two and it
doesn't really matter what the differences are because
they aren't that different but I'll describe them.
A depreciable original cost (DOC) method - and what
you do is you just take the amount of investment. It
cost us $1 million to build a pipeline and the
pipeline is going to operate for 10 years and we're
going to use straight line depreciation. We just get
that $1 million and then we depreciate it over 10
years. Whatever it cost us to build the line we get
back in our depreciation allowance. Whatever it cost
us to operate the line, we get back in our operating
expenses. And then whatever our remaining investment
is at the time, we get a reasonable return on it. So
in year 5, we have a half million dollars left and
let's say we get a 10 percent return so we'll get
$500,000 of return. That is basically how original
cost rate making works. It has three basic elements:
return of investment, which is [indisc.] allowance,
the operating costs and a return on unrecovered
investment. Those are the three elements that make up
a cost-based rate. It's kind of simple really.
There are two different ways of applying original cost
methods. The FERC has adopted one and the RCA has
adopted the other. The one the RCA adopted in its
Order 151 was the DOC - the depreciable original cost.
The difference between the two has to do with the rate
profile you're trying to create. If what you're
trying to do is flatten out the rates over the life of
the facility, then one way you can do that is take a
portion of return and push it into the future.
And so what the TOC does, the trended original cost
method, is it takes the inflation component of return
and just turns it into a deferred return element and
recovers it later. And the effect of that is just to
flatten out the rate profile a little bit. That's all
it is so it just takes - if you have a 12 percent
return and 8 percent of it is real and 4 percent of it
is due to inflation, all the TOC will do is take the 4
percent attributable to inflation and recover it in
the future.
CO-CHAIR GATTO noted Mr. Brena referred to Order 151 but it has
also been referred to as P-97-4-151. He asked if the "P"
represents pipeline and "97" represents the year.
9:27:48 AM
MR. BRENA said that is the RCA docketing convention. "P" stands
for pipeline; the docket was opened in 1997 and it was the
fourth docket opened that year. That is a seminal order with
regard to Alaska's pipelines, particularly TAPS. It establishes
the $1.96 rate. He continued:
And then with regard to the TOC ... I'll refer to the
FERC's TOC as the 154 B because that is the order in
which FERC adopted the TOC to be applied to oil
pipelines. So, I might go back and forth a little bit
when I'm talking about FERC between the B and 154 B
and the TOC. And I might go back and forth a little
bit between Order 151 and the DOC but they're
basically, all of them, are more similar than
different and how they're the same is that they base
the rate on the cost of providing service under an
original cost method. I didn't want the differences
to be confusing.
9:29:01 AM
My next two slides kind of summarize the RCA
proceedings and where they're at and the FERC
proceedings and where they're at. On Slide 5, in the
RCA we filed a protest of the 1997 rates. We filed in
1996 saying that the TSM rates, the method and the
settlement, wasn't resulting in just and reasonable
rates and since we had the right to protest those
rates, and that was the deal in the settlement, we
did. The TAPS carriers and the State of Alaska
defended the TSM rates and asked the RCA to continue
to charge them to us. The RCA decision in Order 151
rejected the use of the TSM for setting just and
reasonable rates. It said the method set forth in the
settlement is not appropriate to use in establishing
cost-based rates. And then they set the rate under
traditional cost-based principles and lowered the rate
to $1.96.
To put this into perspective generally, the difference
between TSM rates and cost-based rates is the difference of
$2 or $3 a barrel, depending on the year and the
circumstances.
CO-CHAIR GATTO announced a short at-ease to address a technical
difficulty.
9:30:45 AM
MR. BRENA continued:
So, in Order 151, the RCA essentially applied cost-
based principles for the first time in the history of
TAPS and set an actual cost-based rate. The cost-
based rate that they set was about half of what they'd
been charging. And to put this in a broader
perspective as we go along, when I talk about $1 a
barrel decrease, the state's interest is essentially
25 cents a barrel. So if you talk about $1 a barrel
and you've got 1 million barrels going through the
line a day, then you're talking about $250,000 a day
the state has an interest in that outcome.
MR. BRENA continued:
The procedural status of Order 151 is that it was
appealed to the Superior Court as an intermediate
appellate court and Judge Sedwick affirmed the
decision of the RCA in all respects. His decision has
been appealed to the Alaska Supreme Court. We've
argued that and we're waiting for the Alaska Supreme
Court to rule.
With regard to the FERC rate proceedings ...
9:32:02 AM
CO-CHAIR JOHNSON interrupted to ask if the $1.96 rate is now a
fixed rate where the previous rate was variable.
9:32:19 AM
MR. BRENA explained that under the tax settlement method that
was in effect prior to setting the cost-based rate at $1.96, the
rate varied greatly, from year to year and from carrier to
carrier. Their rates were $3.96 on average but they ranged from
$3.50 to over $4.00. The TSM resulted in highly variable rates
that were about double the rate set by the RCA. He continued
with his presentation, as follows:
The FERC rate proceeding - one thing that the RCA's
order did is it caused people to take another look at
the rate structure on TAPS to figure out what was
fair. We had done calculations in the rate proceeding
and they suggested that the carriers were earning 100
percent a year on their investment each year for the
five years before Tesoro filed its protest - over 100
percent a year return for the remaining investment and
so that's one reason we wandered into that.
You might ask what is Tesoro, a relatively small
player, doing taking on the combined resources of
Exxon and BP and ConocoPhillips when it has a
relatively small amount of throughput. But there's a
difference. You know, pigs get fat and then hogs get
slaughtered and the difference between $2 and $4 makes
a lot of difference to our clients. If you take $1 a
barrel difference and we ship 25 or 30,000 barrels a
day, and you add $1 a barrel a day, that equals the
average of the profitability of the Tesoro refinery
during this period when we protested the rates. It
has a huge impact on local business so you've got a
relatively small player with hardly any throughput,
26, 28,000 barrels a day of the million barrels a day
at the time it was going through it and saying this is
just way out of line and it making sense financially
for that small player to do that even for those small
barrels. The state has a huge financial interest in
this in relative terms. Its financial interest is 25
percent. It is the big winner or loser in these
cases.
On the FERC side, the independents whose - on the
North Slope, Anadarko in particular, took a look at
the RCA ruling and said it doesn't make a whole lot of
sense for the federal rate to be over $4 and the state
rate to be under $2 so maybe it is time for the
federal rate to go down too. And so Anadarko and
Tesoro filed in 2005 to lower the federal rate to a
just and reasonable level as well. The rates at the
time, and this is putting it in 2006, ranged from
$3.78 to $4.41 and we stepped forward and asked FERC
to lower those rates to $2.04. The State of Alaska,
because it's a signatory to the settlement and I'll
discuss the implications of that more later, can't
argue that the federal rate or any rate under the TSM
is unjust and unreasonable. But they did argue that
those rates were discriminatory. And even though they
spent the last five or eight years opposing the
establishment of a just and reasonable state rate,
they said that because the federal rate was higher
than the state rate, that it was discriminatory and so
the federal rate needed to come down. And so they
filed a discrimination action with FERC, asking FERC
to lower the federal rate to the state rate level of
$1.96.
The carriers in turn said the state rate was too low
and asked the federal government to raise it to the
federal rate level. And so those were the three
classes of claims that were there: us, the smallest
fish in the entire ocean saying let's set just and
reasonable rates; the state who can't say that it's an
unjust and unreasonable rate - saying it's a
discriminatory rate, let's lower it to the state rate;
and the carriers who just lost the state case saying
that the state rate is wrong and so we're having FERC
raise it to the federal level. Those are the three
different classes.
CO-CHAIR GATTO asked whether the market value of a barrel of oil
affects the rates.
9:37:26 AM
MR. BRENA said the market value of a barrel of Alaska North
Slope (ANS_ crude oil is determined in the LA Basin, based on
competitive market forces - international and alternative crude
oils. He did not believe the transportation rate directly
impacts the price of ANS but it impacts the profitability of
using ANS for a particular refinery.
CO-CHAIR GATTO commented that shipping a $65 barrel of oil has
added expenses, such as running diesels and compressors, paying
higher salaries and paying for travel. He said $1.96 could
start to look a little thin and questioned whether a company
might be entitled to an adjustment, depending on the market
price of oil.
MR. BRENA said if transportation rates are reduced by $1, the
value of all North Slope oil and gas resources increases by $1
per barrel in the ground. So the economics of a 100 million
barrel field would increase by $100 million. He said although
$1 per barrel might not make that much of a difference with $60
per barrel oil, it directly and substantially impacts the
likelihood of marginal field development on the North Slope. He
explained:
Whenever you can take a buck out of the middle, then
you add it somewhere else. It's either upstream or
downstream and so that's a buck to somebody's bottom
line that's adding value. So that midstream, if it's
based on the cost of providing service, is very, very
important. It's very, very important to the state
because to the degree that as a producer that I can
transfer my return from upstream to mid-stream, I get
to subtract mid-stream from my royalty and severance
taxes. So for every buck I transfer from production
to transportation is a quarter I save in taxes. Now
that works as long as I'm paying myself the rate and
we'll get into the risks of affiliated lines ... but
the whole game works as a tax saving mechanism to
transfer profitability from upstream to mid-stream and
reducing the State of Alaska royalty and severance
taxes as long as you're paying the rate to yourself.
It doesn't work when you're not paying the rate to
yourself.
9:40:52 AM
MR. BRENA returned to his presentation:
... Okay, so those are the three classes of claims.
Tesoro saying the rates are just too darn high. The
State can't say that - saying it's discriminatory and
so lower the federal rate to the state rate. And the
carriers saying the state rate is wrong, let's raise
it to the federal rate level.
And let me just comment here. You know, Tesoro is
just a small refiner, really. It's grown since this
case started so it's a pretty big independent. In
relative terms to the people that we're talking to,
it's relatively small. Let me just have you
appreciate for a moment what a tremendous effort it
takes for a small minnow in the ocean to do something
like lower the rates on TAPS. First you have to go
litigate between the RCA. Then you've got to litigate
before the Superior Court. Then you've got to
litigate before the Supreme Court and then you've got
to beat off whether or not there's an appeal to the
U.S. Supreme Court. Then you've got to go down to
Juneau and you've got to defend what you did in
Juneau. And then you've got to go back to the RCA
because they'll open three or four R dockets and
you've got to go through your R dockets. And then, in
this case, we had to go back to FERC and defend the
rate at FERC because the carriers asked FERC to raise
the rate. That's what someone doing business in
Alaska has to go through just to get a fair rate off
the North Slope.
Please appreciate that and I'll get into the state's
legitimate role in being sure that these things are
done right in the first place so you don't force your
businesses trying to add jobs and value in Alaska ...
to do that kind of thing. I can't tell you how much
the TAPS carriers - they had to track their expenses
in opposing - just trying to set a fair rate on the
state side they spent over $20 million opposed to
setting a rate on TAPS. That's how much they spent
against our position. And, of course, there's an
argument over how much of that we have to pay through
our future rates.
Okay, well, I'm back to the FERC rate proceeding -
three classes, Judge Cintron agreed with Anadarko-
Tesoro's position to the penny, to the penny. It's
not very often in complex rate litigation that you get
any regulator to agree with any party to the penny.
In fact, it's never happened in my career before.
That's what just happened at FERC, part of it is
because these claims had already been embedded before
the RCA and so we were pretty familiar with each
other's arguments at this point. But part of it goes
to that we put on a fair case in the first place.
The State of Alaska's discrimination claim for
dismissed is moot and the reason for that is as soon
as they lowered the federal rate down to a cost-based
rate and the federal and state rates were about the
same, then there's no reason to worry about
discrimination anymore. And similarly, the carriers'
efforts at trying to raise the state rate to the
federal rate under Section 13-4 of the Interstate
Commerce Act, they were rendered moot too because
there's no reason to talk about raising the state rate
to the federal rate when they're both about the same
too.
So, of the three classes of claims, Anadarko-Tesoro's
position was adopted to the penny. The state's case
was dismissed as moot and the carriers' counterclaims
were - under the Interstate Commerce Act - were
dismissed as moot.
This is an initial decision by Judge Cintron
procedurally where it is. It is a 116 page decision.
It's in your binder. It's very well supported as an
order, as was the Commission's Order 151. These are
massive rate cases that give you some idea of the
state rate case is a 65,000 page record. The federal
rate case is another 30 or 40,000 plus to 65,000 in
the state proceedings so the federal case is an 80 to
100,000 page record. These are massive records and
massive cases. ... The judge did a good job and the
judge got it right. There's one exception to that we
may complain about but, with regard to establishing
the transportation rate, the judge got it right.
So, of course it's going to be appealed to the FERC.
It's called briefs on exceptions and it's going to go
before the FERC. And then, of course, from there it's
going to go to the D.C. Circuit and then, of course,
from there it will probably go to the [U.S.] Supreme
Court, which I don't expect them to hear.
9:45:38 AM
CO-CHAIR GATTO asked if the [D.C.] Circuit Court will definitely
hear the case.
MR. BRENA affirmed it would. He told members the D.C. Circuit
Court does a great job in rate cases. That court forced the
FERC to do it right in the first place in Farmers Union 2.
CO-CHAIR GATTO asked if the D.C. Circuit is the Ninth Circuit.
MR. BRENA said it is not, and added that FERC sits in the D.C.
Circuit's jurisdiction. The pipeline is in the Ninth Circuit
so, arguably the case could be heard there, but the D.C. Circuit
has a lot of experience reviewing agency decisions and
particularly FERC decisions.
CO-CHAIR GATTO asked Mr. Brena if, in his opinion, the D.C.
Circuit Court will hear the case.
MR. BRENA said it must because an appeal is a matter of right.
The effective life of these cases is about 10 years. He said as
soon as the FERC rules, the rates are likely to go down and the
money will go where it should be going.
CO-CHAIR GATTO asked if there will be a retroactive payment.
MR. BRENA said yes, to January 1, 2005. He said he will discuss
the state's interest and refunds.
9:47:06 AM
MR. BRENA returned to his presentation:
I thought I'd just summarize the judge's decision on
page 7. First, with regard to the TSM, the carriers
have never even tried to support the rate elements
that are comprised in the TSM and that's what the
judge held. She held that they didn't support the TSM
so they couldn't very well approve an unsupported
method.
One of the major problems with the TSM, and I don't
mean for this to be too esoteric, but you remember I
said that the three elements of a just and reasonable
- one was return on unrecovered investment. The idea
is that your return is based on how much money you've
got out there. And one of the things the TSM did that
was very, very wrong was it divorced the return
element from the remaining investment and it permitted
an allowance per barrel to be collected. That
allowance per barrel last year, taking into
consideration the tax impacts as well, is $1.19 per
barrel of additional returns and it has nothing to do
with how much investment they still have in the line.
Whenever you take return and you link it to throughput
instead of to investment, you're going to get taken to
the cleaners and that's what happened.
CO-CHAIR GATTO questioned the origin of the allowance per
barrel.
MR. BRENA said it came from fundamentally flawed economic
thinking. When the carriers settled in 1985, they did not want
to pay retroactive refunds so they tried hard to get to keep the
revenues they collected and were successful, for the most part.
However, they collected very high rates and lots of revenue, so
determining how to back fill that with a cost-based method was
problematic. Essentially, they filled the pot by retroactively
accelerating their recovery of investment and [dismantlement,
removal, and restoration] DR&R to the extent possible. By back-
end loading all of this investment, they did not have to pay
much in refunds but they did not have much investment left over.
In cost-based rate making, your return is based on your
remaining investment. He further related:
And I cross-examined the state's economist at the time
on this point for a very long time, the better part of
half a day, I think. Why did you do that? Then, the
allowance per barrel was the crossover point when
their remaining investment went down below a certain
level that was below what would be an acceptable
return. So then they created this allowance per
barrel to take the place of return based on
investment. And the justification that the economist
for the state gave me from the stand when I explored
this with him was - is they forewent future profits
because they recovered their investment upfront. What
I explored with him for a very long time was
generally, in business, you want your investment
sooner back. The sooner you get it the better it is
for you. Why do you give a return because they don't
have investment? When they take all their money back
don't you think they're earning a return on it
somewhere else?
So, if you have this allowance per barrel to give them
a return because they got the front end loaded, then
the first step is that's economically flawed because
it's a benefit to the owner to get his investment back
quickly. But if you're saying well what about these
profits here? If you give them those profits there,
then in effect you've allowed them to double recovered
profit on that same investment. He took it out of the
pipeline and invested in over in Turkistan and made a
20 percent return on it over there and now you're
giving him 20 percent return here because it's not
here. So what sense does that make?
That's the history of it. That's the justification
that the state economist gave me on the stand for it.
It doesn't make a darn bit of sense to me. It never
has. It never will. It's basically flawed economic
theory and it goes to - well, that's the history of
it.
CO-CHAIR GATTO asked if they have recovered 100 percent of their
investment.
MR. BRENA replied, "I have a slide just on the recovery but the
scheduled depreciation cost them $9 billion to build this line,
there's about $600 million of investment remaining based on the
method that's been in place for the last three decades."
9:52:58 AM
MR. BRENA continued his presentation:
I'm back to the summary of initial decision. TSM
Opinion 154 B - again that's the federal cost-based
approach. She said if we're going to use it, we're
going to set cost-based rates and Anadarko-Tesoro got
it right.
DR&R - DR&R is a separate entire conversation but let
me just say, and I have a slide on it, but she said
that it's time to account for the collections of DR&R
and your earnings on them and that if you over
collected, they should be refunded. There's a lot
more to it but that's essentially what she said.
With regard to rates, I mentioned earlier that all the
carriers had different rates and they varied year by
year and they varied carrier by carrier in any given
year. She said we're going to set one rate on the
federal side. There's no justification that's been
advanced for having these rates bouncing all over the
place.
The State of Alaska's discrimination claim for
dismissed is moot. The TAPS carrier Section 13-4
claims were dismissed as moot. The remedies for the
refunds - she held that it's the increases in rates
that are refundable in '05 and '06 with the cost-based
rates going forward. So, in effect they raised their
rates from $3 to $4 in '05 and '06, that's what's
subject to refund. It's not subject to refund all the
way down to the cost-based rate but going forward
we're going to set cost-based rates.
CO-CHAIR GATTO asked if the refund for '05 and '06 has been
calculated.
MR. BRENA said the amount depends on how it is calculated.
CO-CHAIR GATTO questioned if it is between $1.96 or $2.04 and
the charge.
MR. BRENA said the difference is a couple of dollars between the
filed and collected rate and the J&R rate. He further said,
"But FERC has a policy of only allowing refunds of increases so
only allowing refunds down to the last clean rate - that's the
way they referred to it. So there's a question about whether
those refunds should go all the way down to the $2.04 level or
down to the prior rate filing level for those two years only and
I'm sure that's an issue that the state has quite an interest
in."
CO-CHAIR GATTO inquired as to the amount in the most recent
filing.
MR. BRENA said the rates have increased from $3.00 to $5.00 over
the last three years. Five years ago the RCA said the rates
should be $2.00.
CO-CHAIR GATTO asked if, "... we can't get below the $3.00?"
MR. BRENA answered that remains to be seen but the judge's
initial decision only went to the last filed rate for those two
years. The principle benefit to the state under her ruling is
2007 forward and the potential for DR&R refunds.
9:56:14 AM
MR. BRENA continued with his presentation:
Slide 8 - I've said this because this is where it
actually fits into my presentation. "Just and
Reasonable Rates," - what that means is cost of
providing service and what that means is if you built
the pipeline, you get your operating costs, you get
your investment back and you get a reasonable return
on your remaining unrecovered investment. That's what
just and reasonable rates are usually intended to be.
And this is decades and decades of litigation. This
has been the result.
9:56:57 AM
I've talked about the next slide, Slide 9. I've
talked about the TSM rates are not just and
reasonable. They've never been supported. They've
never asked for a review. There's never been a review
of the rates prior to these cases as to whether or not
the TSM produces just and reasonable rates. The
owners have never supported their rates, not in a
single case. They've never come in and said these
rate elements are supported by these costs.
The RCA did a calculation of over collection. If you
apply the RCA's approach, if you apply the FERC's
approach and you take a look backward to take a look
at what the collection should have been, then this is
what you end up with. The TSM has resulted in over
$18 billion of over collections. ... The state's
interest is 25 percent of that and that would have
been from '77 to date and you probably would have
earned some money on that difference in the meanwhile.
So - and just to put this in some kind of perspective,
it cost them roughly $10 billion to build the line,
$15 billion to operate it. So all in, they have $25
billion in this line. They've collected through 2004
$60 billion ... and all in operating cost investment
they got $25 billion in. I mentioned that the TSM is
fatally flawed as a method to set just and reasonable
rates. I mentioned the allowance per barrel.
There [are] a few other elements of it that you should
be aware of. One is each carrier can make up whatever
rate he wants each year. He can project any
throughput he wants. He can project any level of cost
that he wants and he can get any rate that he wants in
any one year. That's a characteristic of the TSM.
Now theoretically, it's supposed to balance out
because there's a lagging true-up, where if he's off
when the actual costs flow through it kind of balances
up. But, in fact, that's just a challenge to change
your projections more and more into the future and
there is absolutely nothing that says what happens at
the end of the life of the settlement when your
projections are all out of whack with reality. It's a
mess.
The line was depreciated over 2011. This line isn't
going to go out of service in 2011. When the TAPS
owner put in the right-of-way renewal application,
which by law they could only extend for 30 years, they
extended it to 2034 and in their application they said
the economic life of this line is well beyond 2034. I
just got out of an ad valorem hearing before the state
assessment review board. I represented the City of
Valdez in that case and we were arguing over what the
assessed value of TAPS ought to be and the life of the
line was a major issue. We put on a case that, based
on proven producing reserves alone, in 2050 there will
be 136 barrels of oil flowing through TAPS. This line
is going to be around a long, long time and all the
rate making prior to these cases was based on 2011 -
way off. And now the new rates that have been set
have been based on the federal rates based on 2034 and
in the next rate case, I predict that the rates will
be based on 2050, 2060. That will be conservative.
CO-CHAIR GATTO asked if the pipes can survive that long without
requiring replacement.
MR. BRENA said reserves must be properly reported to investors,
based on SEC definitions. People usually report what they
believe is pretty close to the truth to the SEC and the tax
authorities. When it comes to calculating rates, people take a
more relaxed approach. As an example, BP has told its investors
in its fourth quarter 10K report for the BP royalty trust that
it intends to continue producing [in] Prudhoe Bay through 2062.
He returned to his presentation:
So, anyway, going back to the point - the TSM basis
rates on the recovery of investment through 2011, the
federal rate is through 2034. Everyone acknowledges
that the life of this line is at least 2034.
Realistically, I think it is 2050, 2060, 2070.
One of the things that the TSM does is it says that
the way that the mechanism works it establishes a
total revenue requirement. We'll say it's $1,000 and
then it uses the plug figure, whatever they collect
from the state shippers, let's say it's $100 is
subtracted.
10:02:45 AM
That means they're entitled to collect $900 from the
federal shippers. That's the way the mechanism works.
Well, when the state took the $100 they were
collecting from the state shipper and shrunk it down
to $50, then the effect of that was to take the amount
that they collected from the federal shippers from
$900 and $950. So, it doesn't make jurisdictional
separations and, in fact, the costs that were
specifically disallowed by the RCA as unjust and
unreasonable costs then automatically flowed over and
reflected from the federal shippers and went to reduce
the state's royalty and severance taxes.
In terms of the over-collections to date, not looking
forward, just looking back, the TSM has cost the state
about $4.5 billion in royalty and severance taxes plus
earnings on that amount from '77 to 2004.
10:03:54 AM
On page 10 is a copy of the rates. This just
illustrates the different carrier's rates by the
different years - year to year and among the carrier
groups. I've already kind of discussed this. ... Page
11 is kind of the heart of the argument over the
theory. I want to draw your particular attention to
lines 1, 2, 3, 7, 9, 10, 12, 13, 14, and 15.
I want to first point out, on line 1, operating costs.
What this is - this is the carriers' theory of how
cost-based rates should be established on the federal
side based on Opinion 154 B compared with Anadarko-
Tesoro's theory. Here they are just lined up side-by-
side. Now you can see that the carriers' net result
on line 15 is the carriers said that their rate under
cost-based rates should be $5.53. Anadarko-Tesoro and
the judge said it ought to be $2.04. So the carriers
put on a case that said that the TAPS rates, the TSM
rates, were too low. Their filed rates were too low
by a buck and a half and that's the way that they
interpreted Opinion 154 B.
So, if you take a look at operating expenses, you'll
see that both of them have identical operating
expenses. Everybody agrees to give them every penny
that went into operating. If you take a look at
throughput on line 13, you'll see that they use the
identical level of throughput. So the operating costs
and the throughput levels in both of these models
[are] identical but the rates are $3.50 difference.
Okay, well that's a lot of gamesmanship to get there
when your costs and your throughput are the same.
You see the depreciation expense item? They said that
each year they should be entitled to $335 million and
we said $13 million. They put on a case that said
that they want to double recover their investment.
That front end loading depreciation that they got paid
once, they said that it should have been straight
lined and they should be paid that investment back a
second time. That was the essence of their federal
case. They said we should get our investment back
twice. We disagreed and the judge disagreed.
Deferred earnings: $224 million versus $7 million.
They actually got deferred earnings in the TSM all the
way back to '77. They said they should be able to go
calculate it and get a second helping of deferred
earnings and so they tried to double recover the
inflation component.
If you take a look at the return allowance, the return
on equity, their return on equity was almost $300
million. Ours was 30. It's because of the difference
in the calculation of investment. If your investment
is a lot higher, you get a lot more return. Also
their return calculation was high. The total return
allowance, you can see - well the total revenue
requirement - line 12, they said $1,750,000,000 a
year. We said $647,000,000.
Take a look at the tax allowance on line 9 - $300
million versus $40 million. When you get a tax
allowance equal - you know, you get to gross up for
taxes and so if your return is higher, this is a
matter of calculation, your tax allowance is a lot
higher. So when you pump up your investment, you pump
up your return and you pump up your tax allowance.
That's hundreds of millions of dollars at each step.
So [those are] the differences between our cases
before the FERC. The Anadarko-Tesoro case is the one
that the judge thought was most reasonable and
specifically made a point of saying you don't get to
double recover your investment. You just don't get to
do that in rate making. You only get it back once.
10:07:54 AM
MR. BRENA continued:
Slide 12 shows the build-up from their rate to our
rate and where the money is and what the differences
are. Please don't be confused by the revised rate
being $1.98 because that's the $2.04 cent rate just
stated on a composite basis. That is the $2.04 rate.
The $2.04 rate is the Valdez rate. The $1.98 is a
composite rate. It's the same effective thing.
And you can see that them wanting to get their
deferred earnings twice, the shippers, the ratepayers
pay them their deferred earnings once and they wanted
it a second time. That was $1.78 of the difference.
You can see that they had a starting rate base
adjustment that was 29 cents in the difference. And
you see them wanting to recover their investment
twice, a portion of their investment twice,
particularly pretend that they had gotten straight
lined for the last 30 years when they had actually
gotten accelerated, that's $1.31 a barrel. And those
are the major differences in the theory and the rates.
10:09:05 AM
CO-CHAIR GATTO questioned whether the accounting procedure rules
are so flexible that these monstrous adjustments can be made,
i.e. declaring deferred earnings twice. He asked if anyone
could make such a statement without a red face.
MR. BRENA said they have made that statement for over a decade
at multiple proceedings and forums.
CO-CHAIR GATTO asked if the state could do that with its own
investments and tell the IRS it wants accelerated depreciation
but in five years change its mind and take the straight line
depreciation.
MR. BRENA said it could not. He asserted their theories strain
credibility in his and others' minds.
10:10:53 AM
MR. BRENA continued:
DR&R is a separate conversation but I just want to
bring it to your attention because there is a huge
amount of potential money at stake for the state and
so I just want you to have some idea of the magnitude
of the issue.
As I mentioned earlier, this is just the cost of
taking a pipeline out of service at the end of its
economic life. The basic concept is that whatever it
costs you to take it out of service, of course you
can't collect it from your rate payers because you
don't have rate payers when you've taken it out of
service. Even if you did have rate payers, the last
person on the line shouldn't pay all that cost. It
ought to be paid by everybody because that's a cost
that everybody should spread over the entire life of
the line.
The carriers have collected $1.5 billion from 1977 to
date for DR&R. A huge issue in the federal case and
will remain for some time is how do you determine what
their earnings have been on those collections because
those are shipper funds. We put on a case that the
judge disagreed with but we showed what they have
actually earned. We went back and calculated their
unrestricted return on equity for the companies that
were distributed the funds. So this is how much they
made actually. They made $15.7 billion so, in total,
they have collected and earned $17.2 billion.
Now their need - and this is all in same term dollars,
their need is $2.6 billion. They said they need $2.6
billion. They have actually collected $1.5 billion.
They have actually earned $15.7 billion on the $1.5
billion that they've collected. So they're $17.2
billion richer for a $2.6 billion cost.
Now one of the basic principles of cost-based rate
making is you don't get a profit on your cost, you
just get your costs back. You get a profit on your
investment. You don't get a profit on your costs.
Whatever it costs to operate, you get that back.
10:12:40 AM
CO-CHAIR JOHNSON asked why the judge disagreed with the $15.7
billion if Anadarko-Tesoro laid out a case that definitely said
that is what they made and what the difference would be.
MR. BRENA replied the difference is substantial. He explained
the judge said, for rate making purposes, there was no authority
to look through the regulated entity to what their parent
companies actually made on distributed funds and attribute that
back to the ratepayer or the regulated entity. She did not want
to trace them all the way to their actual integrated use. The
judge did hold the companies collected and earned $2.9 billion
to date and their need is $2.6 billion. She based that on
"Moody's AA Actual." He pointed out those funds were not
actually invested in Moody's AA Actual and if one looks at the
regulated entity, their allowed returns were massive and were
higher than the parent companies' 15.2 percent actual use. That
is and will continue to be an issue to the proceeding.
10:14:03 AM
CO-CHAIR JOHNSON inquired whether [a copy of] the judges ruling
of $2.9 billion is included [in the documentation provided].
MR. BRENA said it is not; that amount is actually a calculation.
CO-CHAIR JOHNSON asked Mr. Brena if that is his calculation
versus the judge's calculation.
MR. BRENA clarified the judge did not do a calculation. She
determined how a calculation would be done. If one does that
calculation, the amount is $2.9 billion. He asserted this is
the area in the case where he doesn't agree with the judge.
CO-CHAIR JOHNSON asked if that is the only area where Mr. Brena
disagrees with the judge. He suggested 15.7 is a huge number
and he wants to deal with information that a judge has found to
be credible, which the $2.9 billion obviously is. He asked Mr.
Brena to point out his discrepancies with the judge's opinion.
MR. BRENA said that is the only issue where he disagreed with
the judge. He remarked the judge didn't say that earning lacked
credibility. She used it in her reasoning to reject a risk-free
rate calculation. She did not disagree with the earnings amount
of $17.2 billion; she said as a regulator she could not trace
the funds through to their actual use. He stated the companies
actually collected and earned a total of $17.2 billion, the sum
of $15.7 billion and $1.5 billion. He didn't want to give
members the impression that the judge disagreed with his
calculation. She did not. She actually used it to reject one
of their positions. The problem was she could not trace the
funds. All of those funds were distributed to the parent
companies and use for unrestricted equity. She pointed out that
FERC looks to the regulated entity, not to what the parent
companies made with the distributed funds.
CO-CHAIR GATTO asked if Mr. Brena calculated the $15.7 billion
by looking at the annual rate of return and determining, "this
money earned the same annual rate of return as the company in
general and therefore this money, even though it's mixed in the
overall money that the company has, this specific money, if it
earned only its percentage of all the money, would have earned
$15.7 billion. Is that how you arrived at that number?"
MR. BRENA replied, "Exactly."
10:17:34 AM
REPRESENTATIVE GARDNER inquired whether the judge said she
lacked jurisdiction to use that calculation.
MR. BRENA said she did not use that term. She said no FERC
authority allowed it to use the parent companies' returns to
determine the earnings on the DR&R fund. Given that she
rejected the parent companies' use of capital structure, she
looked at Moody's AA actual.
10:18:20 AM
REPRESENTATIVE GRUENBERG asked what kind of authority the judge
indicated she would need to use the parent companies' earnings.
He questioned whether any authority exists that prohibited her
from taking action.
MR. BRENA answered the judge said no precedent existed; she did
not say that she lacked authority.
REPRESENTATIVE GRUENBERG asked if that is the point of appeal.
MR. BRENA said the briefs have not been filed yet.
REPRESENTATIVE GRUENBERG asked Mr. Brena if he plans to include
that point in the brief.
MR. BRENA said he is considering it. He then continued his
presentation:
Let me point out too, that we had put on an
alternative case. The $2.04 was what we put on as our
primary case and what we asked her to accept. With
regard to the DR&R, the FERC deals with it
conceptually two ways. They kind of create a fund or
they kind of allow a rate-based credit. We did ask
for them as an alternative to apply a rate-based
credit and she didn't like that idea much either.
But let me point out that everything that we're
talking about goes to transportation rates and then
DR&R is not a current transportation rate because she
didn't allow the collection of any DR&R in the $2.04
rate. The DR&R goes, what do you do because you've
collected $1.5 billion over - since 1977 forward and
you haven't accounted for it and you haven't said what
you've earned on it and nobody knows how big the pot
is. You guys say you need $2.6 billion but we don't
know how much you have. So what do you do about it?
What we said is regulator regulate. This needs
regulatory oversight. They need to provide an
accounting. We need to set an earnings rate. We need
to figure out how we're going to figure this out. You
can't wait for 30 more years and then just litigate
it, so that's our basic position. So I want to be
sure, too, how the DR&R fits into the case that we
prevailed in the position that there should be no
further DR&R collections in the $2.04 rate because
they haven't demonstrated that they needed the DR&R.
10:20:47 AM
CO-CHAIR GATTO referenced a document before committee members
named "United States of America 119 FERC 63,000-007." He asked
members to turn to page 74, "Issue 3F," and said it is pertinent
to the current discussion. He read from page 74, "What is the
appropriate rate of investment?" and said that is followed by a
description of how the companies determine that. He read:
The carriers claim that the cost of capital should be
based on the capital structure of the carriers' parent
companies, the parent companies' cost of debt and a
cost of equity established using the TCF methodology
with oil pipeline proxy companies or using a risk
premium methodology if appropriate .... Additionally,
the carriers argued that they should get a two
percentage point equity rate and premium.
MR. BRENA said the consistency of rejecting the companies'
capital structure to determine return by tracing through the
DR&R funds was important to the judge and is one reason she did
not trace the funds. Regarding what Co-Chair Gatto just read, he
explained the parent companies' capital structure for major oil
is heavily weighted towards equity. They requested the highest,
most heavily weighted equity structures that FERC has ever
considered and they lost. The equity decreased from 90 percent
to 45 percent.
10:23:53 AM
MR. BRENA continued his presentation:
I wanted to comment on the State of Alaska's positions
because this committee has an oversight function and
the state's stake and the lessons for the gas line, my
last slide. Let me say in the history of the State of
Alaska's position, or Slide 14 - let me start out by
saying none of the points I'm about to make are
comments on the Palin Administration or the current
attorneys involved in these cases. I know that Phil
Reeves was available to answer questions to this
committee today or he was going to be. I think very
highly of Phil Reeves and he's one of the best that
they've had on these kinds of issues for some time.
And the Palin Administration, I believe, is headed in
the proper direction in terms of trying to rein in the
abuses in pipeline transportation. So these are
comments on the prior history generally because - and
I go into history because if you don't figure it out,
it's hard to correct it and so I just want to tell you
my opinions for the value that they contribute and
we'll kind of go from there.
The state has consistently been out-resourced in
pipeline matters - consistently. They've been out-
litigated. They've been out-negotiated. They've been
out-staffed just across the board. So, anything that
you guys can do to get the state the resources they
need to do these jobs right is what they need to do.
They compete with the best and the brightest in the
world. People that go around and do this, you know,
this is all they do. They know their stuff well.
I've been litigating against these guys for a couple
of decades. They are good. They are very, very good
and that needs to be recognized.
The state has had very limited success with regard to
the oil pipeline. The state has never established a
just and reasonable rate in Alaska's history - not
one, not one ever. That's too bad because if you
establish just and reasonable rates, you establish
principles that apply to pipelines but then you go
back to if what you're always doing is negotiating,
and never - it's just common sense. If you're going
to negotiate with me and you know that if our
negotiations break down, I'm going to take you to
court and beat you, then you negotiate differently
with me and I do beat you. You negotiate differently
with me than if we're negotiating and I never end up
taking you to court all the way through and forcing
the hard decisions on the system. So you've got to
win some cases to get good deals from major oil. If
you don't, you're not going to get them - period.
The results have been bad settlements and one of the
things about the settlements that strikes me in
particular is that there's no way to be sure that the
deals stay fair for the parties. You know, like the
TSM deal. They took the state out of the game - a
major financial player. They took the state out of
the game and then they linked return to throughput
that they know a whole lot more about than you guys
ever will. And then, when the throughput was a whole
lot higher than what everyone thought it would be,
then they were making a 50 to 100 percent return a
year on the line while the state sat helplessly by as
a signatory to the settlement and couldn't do anything
about it.
Well, if you do a deal, you don't base it on
information that you don't have control of and you do
it in a way so that if it goes out of sync with
reality, you can bring it back. You don't just enter
long term 20 or 30 year deals without those basic
principles. Nobody does it in business and stays in
business and it's what the state does, consistently.
10:27:52 AM
CO-CHAIR GATTO asked, "So making 50 to 100 percent on the line
because the line was entirely within the state, then FERC had no
influence?"
MR. BRENA said for regulation to work, someone has to ask it to
work. The state is the obvious player to do that because it has
the greatest financial stake in the outcome. However, the state
agreed to sit on the sidelines. He pointed out that 30,000 of
800,000 barrels of oil moving through TAPS daily are owned by
independents. The rest of the oil is moving through affiliates
so the BP shipper is not going to file a protest against BP
pipeline and the producer is saving 25 cents of every dollar
from the state royalty and severance taxes. They analyze this
on an integrated economics basis. When you have affiliated
shippers on an affiliated line and not many independents, and
the state is on the sidelines, there is no one to ask FERC to do
its job. No one has, which is why FERC has never established a
just and reasonable rate on an Alaskan line until its initial
decision.
MR. BRENA continued his presentation:
Okay, some of the settlements that the state has
entered into, like the feeder lines going into TAPS,
they're agreements on rates. It's not clear what the
depreciation is that's in that rate. It's not clear
what the DR&R is in those rates. Given the fact that
they go back and restate that - I mean I'm in a case
where they've said that the depreciation that they
collected under a settlement shouldn't be counted
against future rates and therefore we should be able
to collect it again from future rate payers. Well you
ought to be pretty clear about, in your settlements,
about what elements of that settlement that affect
future rates - about what you're collecting in that
rate. I mean if, for example, you don't know what the
depreciation is, then when that settlement ends, what
you have is a mess because you don't know how much
investment is left in there. You don't know how much
DR&R has been collected. You don't know what the
earnings rate is in the DR&R. Every one of the state
settlements is like that.
10:30:21 AM
The Murkowski gas line agreement - the only worse deal
I've ever seen in the past was that one and I won't go
into that anymore.
The state has put itself on the sideline in these old
deals but they are also restrictively interpreting the
terms of those to keep themselves on the sideline
longer than they need to be.
The duty to defend the TAPS settlement, for example, I
made a major point of saying that third parties had
the right, under the settlement, to go ask for a just
and reasonable rate and that's what we've done. The
carriers have advanced arguments and said that under
the TAPS settlement agreement we don't have that
right. The state has sat silently by while the
carriers have misinterpreted the settlements that
they've entered into with the regulators.
So I think that they're - and the state actively
litigated against in-state shippers for a decade
trying to force down our throat TSM rates, which were
far higher for - after, you know, please share with me
just for a minute - I was at the hearing where the RCA
or the APUC at the time approved the settlement. I
was there for Tesoro and I said that the APUC should
approve the settlement. The reason that I said that
is because prior rates were settled and future rates,
if we disagreed with them we could protest them and
get what was fair. So we agreed with it because that
was the deal.
When we finally went around to file and to argue that
the future rate was unjust and unreasonable, the
carriers started arguing we didn't have the right to
do that. That was a part of the deal. It's always
been part of the deal and so they went back and said
well, Robin, you supported the settlement. Yes, I
did, but the settlement said we had the right to
protest future rates and now you're telling me the
settlement says we don't have the right to protest
future rates. That wasn't the settlement that I
supported.
10:32:30 AM
CO-CHAIR GATTO asked if the settlement was in writing.
MR. BRENA said it is in writing and was stated in testimony and
they haven't been able to persuade anyone of their positions.
REPRESENTATIVE GRUENBERG asked Mr. Brena to describe the deal he
thought was made.
MR. BRENA said it was described in sworn testimony. The
representations and presentations to FERC and the RCA made clear
that future rates were not settled. They filed a 50-page
explanatory statement of their settlement in detail and brought
in their experts. The carriers' argument metamorphosed from
saying the original deal was something different to the fact
that FERC somehow approved it over the passage of time.
CO-CHAIR GATTO said he is amazed there is no document that says
the parties agree to specific stipulations rather than simply
saying something was on the record so cannot be disputed.
MR. BRENA clarified the settlement does not settle future rates.
He continued his presentation:
The no clear consistent policy or client - I started
the presentation by saying you need to get two things
right. You need to get access right and you need to
get rates right. If you don't do those two, then you
haven't got it done. One problem - there's no clear
policy concerning access and, obviously, to the degree
that Alaska has to rely on independents and is trying
to open up competition on the Slope and maximize its
resources, obviously to the degree that it can open up
the Slope to other players is better for the state.
So the state should have a clear and consistent policy
for open access to fuel facilities, to pipeline
facilities, to the whole system necessary to develop
the resource.
10:34:56 AM
REPRESENTATIVE WILSON recalled that when this issue was debated
during the regular session, the producers were opposed to the
state having access.
MR. BRENA said he did not hear all of the producers' arguments
so he could not respond. He added that with an affiliated
controlled gas line, there is tremendous financial incentive to
not open access to that line to a competitor.
REPRESENTATIVE WILSON believed the majority of the producers
argued against access but some did want it.
MR. BRENA agreed that trying to get open access from a
controlled facility would be very difficult.
10:36:27 AM
MR. BRENA continued with his presentation:
So no clear or consistent policy or client - you know,
there needs to be a clear policy towards open access.
There needs to be a clear policy on cost-based rates.
People that build infrastructure should be able to get
their investment back. They should be able to make a
reasonable return. They should be able to recover
their operating costs. But they shouldn't be able to
game it into a tax savings mechanism against the state
by having such exorbitant returns that, in effect,
they are transferring profitability from production to
transportation and impacting the ability of
independents to explore on the Slope, impacting the
state's royalty and severance taxes, and impacting the
value of those resources to value added manufacturing
in Alaska.
The no clear client comment - the attorney general has
interpreted a statute to mean that the attorney
general is both the attorney and the client on oil
pipeline matters. That's never made any sense to me.
I think they are reading the statute wrong and what
you have is, over the years you've had an attorney
general without a client. I've often tried to say
okay, well who is your client, who do I sit down and
talk with? Issues with regard to natural resources,
it seems, should be left to the Department of Natural
Resources and that should be the client that the
attorney general represents. But they've interpreted
that statute to mean the attorney general is the
client and the attorney general is the attorney. It's
a misreading of the statute in my judgment. It's
something the legislature ought to clarify - who the
client is to the degree it's being interpreted and
applied that way.
Trying to get accountability for these pipeline calls
- whose making these decisions? I've tried to trace
them through and good luck. There is a shape shifting
body of people that are involved in decision making
that go - some are in DOR, some are in DNR, some are
in the Governor's Office, some are in the Attorney
General's Office. There isn't one consistent line of
responsibility. So it ought to be policy driven, it
ought to be policy driven by the department as it is
in every other area that is responsible for the
development of our resources, which to me is DNR.
CO-CHAIR GATTO asked if Mr. Brena is saying the DNR commissioner
should be the lead player while the attorney general would
assist the commissioner with contract making.
MR. BRENA emphasized in every other area of law, attorneys have
clients, but not themselves. In gas and oil pipeline policy
matters, the attorney is the policy maker because of how they
have interpreted the statute. The result has been a blurred and
shifting authority within the state as to how the policies are
to be made and implemented.
REPRESENTATIVE DAHLSTROM asked who "they" are in regard to
interpreting the statute.
MR. BRENA clarified he was referring to the attorney general's
interpretation of AS 42.06.140 (a)(10).
REPRESENTATIVE DAHLSTROM asked if Mr. Brena was referring to the
current attorney general.
MR. BRENA said he was referring to former attorneys general. He
added they do things with a certain amount of bureaucratic
momentum. This is an unusual area that needs to be straightened
out. He finds it amazing that the attorney general, who is the
acting attorney for resource development agencies, has
interpreted the statute to mean the attorney general is the
client and attorney. It makes no sense.
REPRESENTATIVE GRUENBERG said the members of the House State
Affairs Committee have pursued other areas where the attorney
general's role is questionable but he was not aware of a problem
in this area. He then read AS 42.06.140 (a) (10):
The commission ... [referring to the RCA] shall
provide all reasonable assistance to the Department of
Law in intervening in, offering evidence in, and
participating in proceedings involving a pipeline
carrier or affiliated interest and affecting ... the
interests of the state, before an officer, department,
board, commission, or court of another state or the
United States.
He said he reads that as only authorizing the commission to
assist the attorney general in its representative capacity, such
as an investigator or police officer would assist the district
attorney.
MR. BRENA agreed with Representative Gruenberg's interpretation.
REPRESENTATIVE GRUENBERG asked Mr. Brena if he has any written
documentation to show the Department of Law has interpreted the
statute as he described.
MR. BRENA said he would check to see whether he has any written
information to substantiate his assertions. He has asked the
attorney general's office who its client was. In P97-4 when the
state was opposed to lowering the rates to just and reasonable
levels, he raised that issue in the hearing room for the record.
He offered to follow up and get that information to the
committee.
10:42:56 AM
REPRESENTATIVE DAHLSTROM asked the co-chairs to request
clarification from the current attorney general.
REPRESENTATIVE GRUENBERG believed the House State Affairs
Committee members are interested in dealing with the question of
whether the attorney general represents the state or the
governor.
MR. BRENA asserted resource development is within the purview of
the Department of Natural Resources (DNR) so this is one arrow
DNR should have in its quiver. He then continued his
presentation:
Slide 15 - thank you for your patience. The State of
Alaska financial stake and I use this as a rule of
thumb, the 25 percent, that's historically correct.
The new tax regime had made that calculation more
complicated and ... so I'm just using that as a rule
of thumb. But of refunds and interest for 2005 and
2006, and the judge's ruling did say that it's just an
increase in rates for these years subject to refund
and I suspect that that will be something that people
are considering, whether to take a brief on exceptions
for. The state has a huge financial interest in that
issue. My client does not - clients.
Then 25 percent of lower refunds or interests - 2007
going forward - I think we're going to be able to get
the $2.04 rate. Anything above that - I mean once you
get that in place then the benefit starts flowing. I
think we're going to be able to get there by the end
of the year. I hope we can. The DOR's calculations
that you've seen in the paper and that have been
reported to this committee I think understate the
benefit to the state and what they assume in their
calculation is that the benefit ends at the end of
2008 because that's the termination of the TSM.
So they assume that ... beginning in January 1, 2009
that cost-based rates are just magically in effect on
TAPS. Well, I showed you their case that said that a
$5.63 rate was the way they calculated Opinion 154 B
so they put on two cases. They put on two alternative
cases: the SAC that said that the rate ought to be
$6.00 and the Low Cost Method. And their 154 B
calculation said it would be $5.63. They put on a 5
and a half buck case and a 6 buck case to justify a $4
rate.
Now if you think that in January 1, 2009 without these
decisions all of a sudden Anadarko-Tesoro's or the
state's interpretation of 154 B is going to be
automatically put in effect, then go ask Alice because
that's just not going to happen. So, the deal where
our calculations of benefit from just [indisc.], are
going to carry forward.
10:46:34 AM
Now there would be a counter-argument that would
suggest that at the end of the line is agreement among
the parties with regard to depreciation balances and
property balances and those kinds of things. That's
not persuasive to me. So, the real benefit of this to
the state is on a going forward basis but at long last
cost-based rates are being set on TAPS and that means
that the tax avoidance game is ended. That's the real
benefit here.
CO-CHAIR JOHNSON asked whether the state can sue to recover that
money even though the state defended the producers in the case
and has [offered] a settlement agreement.
MR. BRENA responded, "You get your money despite yourself."
CO-CHAIR JOHNSON asked whether the state will have to take the
case to court.
MR. BRENA replied:
Anadarko and Tesoro, or their representatives in the
back room, ought to get a Christmas card from the
state. ... I'm hopeful that the state will be able to
walk through the front door and say if the FERC does
establish a J&R rate, a just and reasonable rate, that
refunds ought to be available. Please understand that
it's Anadarko-Tesoro's theories that are making the
state money. Anadarko-Tesoro doesn't have a dog in
this fight. In fact, we lose a little bit of money if
the state makes money in these historic years.
CO-CHAIR JOHNSON asked if the state is precluded from taking
legal action because of its previous agreement.
MR. BRENA said the assistant attorney general is reviewing that
right now. He does not believe a lawsuit will have to be filed.
The mechanism for refunds is to ask for clarification, and when
FERC orders refunds, they are paid. If FERC establishes a rate
and orders refunds, they are paid, so no independent legal
action should be necessary. He said the amount of the refund
for 2005 and 2006 is in question because the basis on which it
will be calculated is unknown at this time. That is not a
refund issue; it is just a question about the amount.
MR. BRENA continued his presentation:
And then, of course, unless the state has given it
away through the royalty settlements, there is also an
opportunity for 25 percent of the DR&R refunds. To
take it back to the theories that we advanced, you
know the $17.2 billion versus the $2.9 billion, it
doesn't matter what number you use. If you use the
$2.9 billion, you take the life of this line out 40
years and you use the judge's decision, then earnings
are going to accumulate on the weighted cost of
capital, say at 8 percent. So your earnings are going
to go up for the next 30 years at 8 percent. Your
costs of DR&R are going to go up by 2 or 3 percent so
you are already over-collected. Thirty years from now
you are going to be massively over-collected. It
doesn't matter what calculation you use. There [are]
massive over-collections and refunds.
10:50:22 AM
If you use how much they actually made on it, then
there are 2 or 3 billion at stake now. If you use the
judge's calculation of prior earnings, then there's a
hundred million at stake now and refunds, and there
will be 2 or 3 or 4 or 5 billion at the end of the
life of the line. Either way, please pay attention to
it. It's a whole bunch of money and it makes a
difference.
10:50:55 AM
REPRESENTATIVE GUTTENBERG asked Mr. Brena to address his opinion
of how the attorney general's office defines its duty to defend.
MR. BRENA said eight years ago he wrote an assistant attorney
general a 23 page memorandum on the duty to defend. He
explained the history of the agreement and his exact position.
He agrees and disagrees with parts of the state's position. He
agreed that the state cannot sign a deal that says it will not
protest a rate as unjust and unreasonable as long as it is
operating under the TSM because it cannot sign a deal and then
violate it. He agrees the state cannot say it's unjust and
unreasonable. He believes locking into a deal like that
disallows any opportunity to assure the deal stays fair.
MR. BRENA then said the state does not have a duty to defend
something that is not being attacked. Part of the deal was that
any third party shipper could get a just and reasonable rate on
these lines. The attorney general stepped up at the time and
said the state might not even be involved in those proceedings.
His concern is that since the state did step up, it first read
the duty to defend to mean it had to oppose Anadarko-Tesoro. He
further said:
Well you don't have to oppose somebody. We were
getting what they said the deal was. So I think that
they misread their duty to defend in opposing
establishing just and reasonable rates before the RCA
and I think - and at this point they changed their
position on most but not all of that. And I think
that they are unduly restrictive in their
interpretation of it on the federal side. On the
federal side, for example, like - we're talking about
refund issues. Let me give some examples. I hope
that the state will step forward, even though it says
that it can't say that a J&R rate should be
established because it agreed to live with the TSM
rates. But the question is if the FERC establishes
our J&R rate, then what are ... the legal consequences
of that? I don't think there's anything restricting
the state from saying that.
So I think the state should speak and hasn't spoken to
say what the deal really was and what it wasn't. I
think the state should speak and hasn't spoken with
regard to what the deal is silent on. DR&R is a
perfect example. The settlement agreement says DR&R
will be collected. It doesn't say whether it's
refundable. It doesn't say how it will be accounted
for. It doesn't say what the earnings rate will be.
The settlement that the state entered into is silent
on all those massively critical terms. So why should
the state under the duty to defend sit silently by and
not speak on those issues? I think that they should.
So I think that they misread the duty to defend and,
by the way, even when we get our rate, our $2.04 rate
or our $1.96 FERC rate, nothing changes the deal that
the state is in. So if nobody is attacking it,
there's nothing to defend.
So, in summary, I think the state misinterpreted and
misapplied the duty to defend in opposing the in-state
refiners trying to get a fair rate on the state side
and I think that their interpretation to date on the
federal side has been more restrictive than the
contract calls for. I think the state is staying on
the sidelines when it ought to get in the fight,
particularly when the carriers are misrepresenting
what the original deal was or adding terms to it that
weren't settled. Does that respond to your question?
10:55:55 AM
REPRESENTATIVE GUTTENBERG said it did.
MR. BRENA offered to provide a copy of his 23-page memorandum on
the duty to defend.
10:56:23 AM
REPRESENTATIVE GUTTENBERG noted that under the judge's ruling,
the difference between the intrastate and interstate rates is
about $2.00. He asked Mr. Brena to address how the carriers
justified applying that cost.
MR. BRENA asked for clarification of the question but first
explained when the state said the federal rate was too high
under the discrimination theory and asked the FERC to lower the
federal rate to the state rate, the carriers argued that
assuming FERC has that authority, Section 13.4 of the Interstate
Commerce Act (Interstate Commerce Act) says the federal
government can set aside and establish a state rate if the state
rate is noncompensatory and a burden to interstate commerce. He
asked Representative Guttenberg if his question was in regard to
the carriers' claims under Section 13.4 of the ICA.
REPRESENTATIVE GUTTENBERG said the carriers are adding the
difference onto their interstate rate so he is trying to
determine how the carriers would justify that to interstate oil.
MR. BRENA said one mechanism of the TSM establishes total
revenue requirement regardless of jurisdiction. He continued:
Say that's $1,000 and then whatever the state rate
pays, whatever the state shippers pay, say $100, they
pay and then the rest they get from the federal
shippers and so the rest in that case would be $900.
When the RCA lowered the federal rate by half, it took
the $100 and turned it into $50, which means, because
of the way the TSM works, they are allowed to collect
$950 because either way they are still entitled to
continue to collect $1,000, and it's just a matter of
whom from. When the state shrunk the rate, then they
shrunk the state contribution, then they grew the
federal contribution, which cost the state royalty and
severance taxes, which is another flaw in the
settlement.
But, how did the - I'm understanding your question to
say how could they justify asking federal shippers to
pay for portions of rates that have been specifically
held by the state to be unjust and unreasonable.
REPRESENTATIVE GUTTENBERG said that is correct.
MR. BRENA replied:
I don't think that they could do it without the - I
mean how do you say that excessive return on the state
side that was disallowed by the state commission
automatically has to be paid by federal shippers?
That's not fair and that's not fair at all. And they
weren't successful in that and that is one of the many
reasons why the TSM jurisdictional allocations are
misallocations. That's one of the many reasons why
the TSM can't work to set just and reasonable rates
because it disregards jurisdictional integrity.
11:00:23 AM
REPRESENTATIVE SEATON asked Mr. Brena to elaborate on his
statement about giving away the 25 percent DR&R refund through
royalty settlement agreements.
MR. BRENA told members the state has comprehensive royalty
settlement agreements with all of the major producers. He does
not believe those agreements contemplate DR&R at all but he
believes [the carriers] would argue that any refunds associated
with DR&R should go to the affiliate shippers. In that case, BP
pipeline would pay BP shippers a huge refund. That only affects
the state because the wellhead value of Prudhoe would increase
retroactively. He advised it is necessary to think through
whether that issue was settled under the comprehensive royalty
settlements that the state has entered into and whether funds
are available now, which would impact the funds for royalty
calculations for those periods or for the current period.
REPRESENTATIVE SEATON questioned whether that is a state issue
and not something Mr. Brena is concerned with. He clarified he
is trying to figure out who needs to analyze that.
MR. BRENA believed the assistant attorney general should be
asked whether the state has a financial interest in DR&R refunds
if they are ordered. Those issues are being decided by the
FERC. The judge suggested putting it off until the end of the
life of the line but he disagrees. However, regardless of when
it is addressed, the question is whether it is refundable and
where the economic benefit flows. He pointed out his clients
have an interest in the state rates for DR&R. The RCA put off
the DR&R until the end of the life of the line and closed the
rates down without forcing them to justify the collection of the
rates for prior periods. He agrees with the RCA's actions in P
97-4 but not in P 86-2.
REPRESENTATIVE SEATON asked Co-Chair Gatto to have the committee
follow-up on that issue.
11:03:46 AM
CO-CHAIR GATTO suggested having a separate fund for DR&R
collections.
MR. BRENA said that is an interesting concept. Given the state
is comprised of 50 percent state-owned land and the primary DR&R
obligation is contained in the right-of-way agreements, he
believes the state should strengthen its leases and right-of-way
agreements to ensure its financial stakes are protected.
11:05:26 AM
CO-CHAIR GATTO asked Mr. Reeves to give his presentation after
Mr. Brena was finished and the committee takes a short break.
11:06:20 AM
MR. BRENA continued with his presentation:
Having been in the trenches for a couple of decades,
I've learned some basic lessons. And so I want to
share those with you guys. You can ignore them or
listen to them. It's clearly your choice but I want
to be sure you hear it. The first thing is don't
leave anything to FERC.
11:06:53 AM
CO-CHAIR GATTO interrupted to note that Alaska Gasline
Inducement Act (AGIA) has rolled-in rates with a 15 percent top,
yet shippers are allowed to protest the rolled-in rates. FERC
is involved in the protest with the words "rebuttable
presumption." He asked Mr. Brena to explain the connections
between peaks and rebuttable presumptions and what the
objections to rolled-in rates could be.
11:07:49 AM
MR. BRENA said he was not prepared to comment directly on the
terms of AGIA but he would comment on some of the underlying
concepts. He explained:
The first, if a shipper wants to protest a rate,
there's nothing that's a deal between the state and
whoever the pipeline owner is that keeps that person
from being able to go to FERC and say the rate is too
high. ... So when I say don't leave anything to FERC,
I don't mean foreclose a shipper's rights to take an
issue to FERC. What I mean by don't leave anything to
FERC is that one major thing that the Murkowski gas
contract did was leave a lot to FERC. All the details
I'm sitting here talking about weren't addressed and
that's where the money is. So, it's too important to
leave the issues - let me back up one more step.
You need to understand FERC isn't known as a real
active regulator and FERC's regulatory policies have
evolved within the context of Lower 48 pipelines that
it regulates, which largely have competitive
alternatives. So if you develop a policy, you know,
down south, if I've got some gas in the line and you
want to charge too much to put it through your
pipeline, I'll go put it in your pipeline or her
pipeline or I'll build my own. Those aren't options
up here. So at the core, FERC is not, as a matter of
its regulatory structure and mission and the way it's
defined its policies with regard to pipeline
regulation, is not well suited to the circumstances of
Alaska.
Secondly, pipeline regulation is the poor step-child
at FERC. They don't like it. They don't like to have
to do it. They view it as disputes between large
financially interested parties that have minimal
impact on customers and they want to be done with it
as quick as they can. So when you take all those that
we have policies based on an entirely different set of
circumstances that exist in Alaska, and the regulatory
hesitance to get involved in these massive cases
between well-financed parties, then FERC is not a very
good arbitrator or protector of the state's financial
interest.
So, my suggestion is that the state takes care of its
own financial interests by contract. These are your
resources. You have several opportunities to take
care of and maximize the value of your resources and
not leave it to the whim of a regulator in D.C.... The
way the leases are written and what the terms are -
very important powers. You have the right-of-way
agreements. You have whatever kind of deal gets
struck under whatever legislation. It should define
the way that FERC will regulate because whatever you
guys agree to, FERC will go along with. But if you
don't agree, and if it's silent, then the carriers are
going to be in a favorable forum to increase the
profitability of these lines to levels and ways that
foreclose independence from exploring on the Slope,
getting access to this line and paying fair rates.
And that's not in your interest. It's not in your tax
interest. It's not in any of our interests that that
happen.
So don't - don't leave important issues for the FERC
to decide because the devil is in the details. Strike
deals where you agree on what you're going to present
to FERC because whatever you present to FERC is what
FERC will go along with. If the state and the
carriers agree, whoever the carriers are, if the state
and the carriers agree on cost-based rates, open
access, rolled in rates, FERC is going to go along
with that. If you guys don't address it, then you'll
have a huge amount of unnecessary litigation that will
probably result in compromises to the state's
financial interest. So - and I've learned long, long
ago, don't try to solve a local problem in D.C. So
don't leave major, major issues. Access, and this
goes - the second thing, resource the effort. Get the
best and the brightest. Perform your oversight
function. Be sure it's being done. Have it be an
open process; resource the effort properly.
11:12:46 AM
REPRESENTATIVE ROSES asked if Mr. Brena means by "resource the
effort" that the state gets out-litigated, out-negotiated and
out-staffed so it needs to hire somebody to do it. He noted Mr.
Brena said don't leave anything to FERC but he also said the
state is not in the best position to negotiate so the state is
caught between a rock and a hard place.
MR. BRENA said he means it should be a priority from top to
bottom; he believes it is in this Administration. By "resource
the effort" he means hire the best and the brightest because the
opponents will be the best and brightest at every level. He
pointed out the expectation has been that people who play
infrastructure games make 50 to 100 percent return and cost the
state 25 cents on every dollar for that access. They control
the North Slope's development through control of the
infrastructure and shift profitability away from the development
of the resources both upstream and downstream. The state needs
clear policies on open access and cost-based rates. Those two
things will end the games that have cost the state billions of
dollars.
11:15:05 AM
CO-CHAIR GATTO said the public demands that legislators take
action so legislators tend to rush. It takes a certain amount
of courage to say we're just not ready. He said it is difficult
for politicians to do both jobs - the economics and politics.
He said he favors an economic focus because the state does not
want a bad deal. He wants one that will benefit future
generations.
11:16:35 AM
MR. BRENA said the legislature has a constitutional mandate to
maximize Alaska's resources.
CO-CHAIR GATTO indicated that Mr. Brena's arguments bolster the
legislature's argument that it is not ready. Everyone is
working together, but it still may take time.
MR. BRENA said he favors development of the resource and
building a gas line or multiple gas lines and nothing he is
saying should be interpreted any other way. He is saying those
things need to occur but should be subject to contracts that
make sense for Alaska and the independent explorers and
independent refiners.
CO-CHAIR GATTO said legislators know that 35 TCF is not enough.
If additional exploration does not occur, the state will not
have enough resource and will run out before the gas line is
paid for.
11:18:45 AM
MR. BRENA continued with his presentation:
I think I clarified what I meant by resource the
effort. "Get Gas for Alaskans." You know, in third
world countries, they extract the resource and ship it
to somewhere else to add value. That's what happens
in third world countries all over the world. If it's
possible to add value to that resource before it's
shipped, and we're seeing, for example, Saudi Arabia
moving in the direction of rather than just extracting
and exporting its crude oil, of building refineries so
that it can export products, anything that we can do
to get gas to value-added manufacturing in Alaska
would have a huge, huge impact. I was sitting around
talking with somebody yesterday and I said what would
happen if they put in the leases that 30 percent of
the gas and oil had to be processed in Alaska - value
added. What would that do to the economy of Alaska -
that one simple lease term sentence? Who knows? And
I'm not suggesting that. I'm just saying think about
it and find ways. We've got Agrium running at less
than half capacity for gas. We've got Tesoro
constrained on gas. The value-added manufacturing in
this state adds tremendously to the economy of this
state.
Figure out ways that we can maximize the value of the
resource in Alaska before it's exported. Why can't we
do better than a third world country that simply
exports its gas and crude oil? Why can't we do what
we need to do to add value to that resource to the
degree it's possible to get it done? So we need ... a
fundamental shift in thinking. We've got gas prices
going through the roof for 60 percent of Alaskans
because of these increases in these contracts linked
to Henry Hub. I was involved in those cases - getting
the most recent contract rejected by the RCA because
they're just getting ridiculous.
So we've got $7 gas, we've got industry shutting down.
We got Tesoro constrained at its refinery because of
its gas constraint. We've got crude oil drawing up to
our own in-value manufacturers in Alaska. Those guys
add a lot of jobs, high paying jobs, to the state.
The future of this state depends on your ability to
shape public policy so that independents can get
access to the Slope and develop those marginal fields
and so the value-added manufacturing has a way to
realize the benefit from those resources.
So please get some gas for Alaskans. Get access
right. There's no - if people can't get in the line,
they won't invest in drilling the holes. And get the
rates right. I've talked about those issues, rates a
lot more than access, but those are things you've got
to get right. You've got to get gas for Alaskans.
You've got to get access right. You've got to get
rates right. The policies that you develop have to do
those three things. If they do those three things,
then a whole lot of good things are going to happen.
If they don't, a whole lot of good things aren't going
to happen. So when I view, based on my experience,
what I'd suggest, that's the heart of it.
The last one I changed - I said have a very good
reason. I changed "damn" to "very good reason" but if
you give control of this gas line to a few major
producers, be sure you know what you're doing and you
have real good reasons for doing it. And I say that
because just on a fundamental economic level, you need
to understand the way the game works. Okay. If
Representative Seaton owns the line, he is the
producer and it's his line, and I want to ship gas in
it, it has to go to the market that he is serving. He
has no incentive at all to let me into that line. And
so, he's going to nominate 100 percent of capacity to
the contract carriage provisions to his own arm. He
is going to service Chicago or whatever markets the
pipeline goes through.
Now I come in and I want to service those same markets
but to do that, I need his cooperation. Think about
that. I need his cooperation to compete with him.
Now first, there is no capacity in the line because he
has nominated 100 percent of it. It doesn't cost him
anything to nominate 100 percent of it because he pays
it to himself. So the whole concept of some sort of
demand charge - he's paying it to himself - so what if
he pays demand charges to himself. He has to carry
the cost of the line. He's happy to do that to keep
me out of his markets.
Okay, so how do I get in? Okay I can't get in. I
asked him to release part of his capacity. He has no
obligation to do that. I've got to go litigate it in
FERC for five years in order to get it. That works on
my economics? I'm trying to develop a field here.
I'm trying to bring something on line. In order to do
it, I either need him to bless it, which means I've
got to give away a huge amount of the profitability of
the field, or I have to go litigate at FERC for 5 or
10 years before I can even start my first [indisc.]
Not a very good position to put me in.
Then the expansion - okay, well why don't you, since
you have it all nominated because you predict you're
going to need it all Representative Seaton, why don't
you double the capacity of it or add 25 percent of it.
Okay. Are his engineers going to hop right on that
job? Okay. Are those costs going to be penciled out
exactly? No wonder why he doesn't want rolled-in
rates because rolled-in rates mean that he'll have to
share the cost. Well he designed this line so it's
even expandable. If he has choices, okay, he's going
to build the line so it covers his capacity. He can
build that line with the initial design so that it
builds it to that capacity. He can make incremental
expansion cheap or expensive. What's he going to do?
Well, I'm not impugning bad motives to anybody but I
am saying follow the economics because he has an
obligation to his shareholders to maximize the value
of their resource. Is he maximizing that resource by
agreeing to expansion, letting me compete in his
markets, bring excess gas into those markets - depress
the retail price of the gas in those markets, cut down
his transportation rates? Of course not.
So think about the impact just on access if he is both
the producer and the pipeline owner. FERC never deals
with these issues because those third party lines ...
in the Lower 48 aren't owned by the producers. They
are owned by independents so none of the FERC policies
are going to save us. Think about the impact on
rates. He's got this thing going on where he pays
himself the highest rate possible because every dollar
he overcharges himself, he saves himself a quarter in
state royalty and severance taxes. Now I want to come
in. He's squeezing the economics of my field. He's
squeezing it because I can't get in. He's squeezing
it because it's not cheaply expandable. He's
squeezing it because it's going to take years of
litigation to do that. Now he has a rate. Now I've
got to go into a rate case? So think about the
perfect example of the impact on rates from affiliated
ownership in TAPS. No matter who calculates it,
there's been billions of dollars of over-collections
and that's come right out of whoever wants to develop
the resource. They can't develop that resource. It's
a hurdle.
And then finally, think about the impacts on the State
of Alaska's power to manage and tax its own resources.
When you link the producer and the pipeline owner, you
see the negotiations are over producer profitability.
We're talking about a highway here. We're talking
about a pipeline. We're talking about transportation.
We're talking about midstream. If he is both of
those, then he's going to negotiate for a better deal
as producer and so you're going to be talking about
tax systems. You're going to be talking about
arbitration in Seattle rather than in the state
courts. You're going to be talking about all of these
things where you're going to be asked to give away the
state's rights to manage its own resources.
Now let me switch that. Let's say he's the producer
but you're the pipeline owner and I'm the state.
11:27:53 AM
Well then if you can't get in, you're going to
litigate for me. If the rate is too high, you're
going to litigate for me. There is a natural balance
when it's a third party shipper and when the producer
is a third party shipper and the pipeline is owned,
then there's a natural incentive for regulation to
work. I'd just ask you to think through the way that
the game actually works in terms of the fundamental
economics for how pipelines work because the
fundamental economics for pipelines say affiliated-
owned lines have restricted access and high rates and
nonaffiliated-owned lines have open access and lower
rates.
My last slide is some jump sites to some of the orders
and stuff that I thought might be helpful background.
If you choose to, you can go to them and take a look
at it.
11:28:46 AM
CO-CHAIR GATTO thanked Mr. Brena for his presentation and asked
Mr. Dietrick if he was prepared to talk to the committee after
its lunch break.
11:29:34 AM
LARRY DIETRICK, Director, Division of Oil Spill Prevention and
Response, Alaska Department of Environmental Conservation (ADEC)
said he did not have much to add on the pipeline tariff issues
but would be available whenever the committee reconvened.
11:29:54 AM
CO-CHAIR GATTO asked Mr. Reeves to address the committee.
11:30:22 AM
PHILIP REEVES, Senior Assistant Attorney General, Oil, Gas &
Mining Section, Civil Division (Juneau), Department of Law
(DOL), told members the following:
... I'm the assistant attorney general charged with
managing the current TAPS litigation at the FERC. I'd
like to start out with a quick review of the state's
protest position in the current TAPS-FERC litigation
then review the judge's decision on the discrimination
claim and explain where we're looking to go from here.
Just real briefly on the duty to defend question - the
state is party to a settlement agreement with the TAPS
carriers that was executed by the parties and approved
by the FERC in 1985. I'll refer to that as the TSA.
The TSA is a legally binding contract between the
parties and its term runs at least through the end of
2008. It provides a formula and criteria under which
the carriers annually calculate and file new TAPS
rates. It expressly requires the parties to defend
against any litigation that affects the validity and
enforceability of the agreement or any provision
thereof. This duty to defend is a contractual duty
and, in essence, requires the state to support and
defend TAPS rates that are filed in conformance with
the TSA. If the state were to protest TSA conforming
TAPS rates at FERC, the TAPS carriers would surely
petition the FERC to dismiss the state protest as they
have repeatedly done in the current FERC litigation
and, in our judgment, the FERC would likely dismiss
the state in order to keep it from breaching its FERC-
proofed contract.
After the current protest in December of 2004, the
TAPS carriers filed 2005 interstate rates for TAPS'
shipments from Pump Station 1 to Valdez that were a
volume rated average of $3.71 a barrel. The RCA
regulated intrastate rates for shipments from Pump
Station 1 to Valdez have remained at $1.96 a barrel
since the RCA's decision on Tesoro's protests in
Dockets P 97-4 and P 03-4. Thus, the 2005 TAPS rates
for identical shipping services varied by $1.75 a
barrel depending on whether the shipments were in
interstate or intrastate commerce.
The final paragraph of the TSA rate methodology,
Section 211 (e), provides that notwithstanding any
other provision of the TSA, rates charged for TAPS
services are subject to legal prohibitions on unjust
discrimination and undue preference. In other words,
rates that are unjustly discriminatory or unduly
preferential are not TSA conforming rates. The TSA
duty to defend applies only to TSA conforming rates
and thus the state was able to protest the TAPS 2005
interstate rates on the grounds of unjust
discrimination.
The legal prohibitions on unjust discrimination and
undue preference are set out in Sections 2 and 3 of
the Interstate Commerce Act. I'll refer to that as
the ICA just for shorthand. The ICA was enacted in
1885 and so there's a long history of rate
discrimination case law to rely on when applying its
terms. The basic premise of the ICA discrimination
case law is that rates charged for substantially
identical services must be substantially identical.
Thus the state's protest cites to the nearly double
rates charged for interstate versus intrastate
services on TAPS as proof of unjust discrimination.
The remedy for unjust discrimination under ICA Section
2 is to reduce the higher rate to a level comparable
to the lower rate. The state is therefore seeking to
have the interstate TAPS rate reduced to approximately
the level of the $1.96 intrastate rate.
Now the state initiated the current litigation at the
FERC by filing its discrimination protest to the 2005
TAPS rates. A day after the state filed its protest,
Anadarko and Tesoro jointly filed a protest to the
2005 TAPS rates on separate grounds. The FERC
consolidated the protests for a hearing.
11:34:48 AM
MR. REEVES continued:
The parties have since continued their protests on the
TAPS 2006 and 2007 rates on the same grounds.
Anadarko and Tesoro are not parties to the TSA and
they are not subject to the duty to defend and have
taken no position in this litigation on whether the
'05, '06, and '07 TAPS rates are calculated and filed
in conformance with the TSA.
Mr. Brena has explained again today, obviously well
explained, Anadarko and Tesoro's challenges in this
case but I would say that a focus of the case was on
the fact that Anadarko claimed the FERC rates are not
in conformance with the FERC non-settlement rate
methodology, which is known as the Opinion 154 B
methodology. That's the just and reasonable rate
methodology that the FERC utilizes.
In response to the Anadarko and Tesoro evidence
regarding its TAPS 154 B calculation, the TAPS
carriers filed their own much higher 154 B
calculation. In response to the state's
discrimination protest, the carriers then claimed that
their 154 B calculation shows that the intrastate rate
is too low and the discrimination should be alleviated
by increasing the intrastate rate. The state
therefore responded by presenting its own 154 B
reference rate calculation to establish that the
intrastate rate did cover its fair share of costs of
operation of TAPS. The state's 154 B evidence
presents rates and rate components very similar and
close to those presented by the Anadarko-Tesoro
evidence.
The focus of the litigation thus became an argument
over the proper calculation of the non-settlement 154
B rates for TAPS. Judge Cintron's decision, following
a lengthy review of the filed testimony and arguments
from all of the parties regarding the appropriate
calculation of TAPS rates under 154 B methodology,
Judge Cintron ruled in favor of Anadarko-Tesoro's
protest and found that the carriers should be required
to filed new rates going forward after 2006 at
approximately $2.00 per barrel. She then moved on to
address the state's discrimination claim and in
paragraph 263 of pages 112 to 113, she ruled:
This decision contemplates new rates that will be
substantially less than the carriers' 2005 and 2006
original filings. Anadarko-Tesoro's Opinion 154 B
interstate rate calculation is $2.04 for 2005 and
$1.83 for 2006. The state's Opinion 154 B reference
rate for interstate rates is $1.96 and $2.05 for 2005
and 2006 respectively. The intrastate rate set by the
RCA is $1.96. The difference between these rates and
the RCA established rate are minimal. Accordingly,
the discrimination has been alleviated and the state's
discrimination claims are rendered moot.
So, in summary, Judge Cintron found that by equalizing
the TAPS interstate and intrastate rates going
forward, her ruling for Anadarko-Tesoro alleviated the
discrimination that the state had protested. Now
that sounds reasonable as far as it goes, however the
state's discrimination protest does not seek relief,
only from discrimination and rates charged after 2006.
We also seek to cure the discrimination rates already
charged in 2005 and 2006. And in ordering refunds for
2005 and 2006, Judge Cintron ignores our
discrimination protest, which she found to be moot,
and relies on a legal precedent that has applied only
in a select few just and reasonable rate cases - that
is in non-discrimination cases. The precedent she
relies on limits refunds to the difference between the
rates actually charged and the last permanent
unprotested rate that was in effect prior to the
filing of the current protested rate. In this case
she ruled that the 2004 TAPS rate was the last legal
rate for calculation of refunds.
So based on that narrow precedent, Judge Cintron has
limited the refunds for 2005 and 2006 to the
difference between the TAPS rates charged and the 2004
TAPS rate, which averaged about $3.05 a barrel. Her
decision to limit the refunds is subject to a legal
challenge even when applied in the context of a J&R
rate protest and the FERC staff presented that
challenge in their reply brief earlier in this
proceeding. The state has an alternative and perhaps
stronger argument to raise the refund limitation
ruling through its discrimination protest.
11:39:23 AM
That's because under Interstate Commerce [Act]
Sections 2 and 3, rates that are unjustly
discriminatory or unduly prejudicial are illegal and
the remedies for such illegal rates is to remove
virtually all of the discrimination by resetting the
interstate rates at a level comparable to the lower
interest rate charged for comparable services.
Judge Cintron acknowledged this requirement for
equivalents in interstate and intrastate rates when
she determined, as I quoted earlier, that by setting
interstate rates that are minimally different from the
intrastate rates, she had alleviated the rate
discrimination protest by the state. However, the
effect of her proposed refund decision is to allow the
carriers to retain tariff payments at a $3.05 rate for
2005 and 2006. This is still one dollar more than the
$1.96 intrastate rate or than the 154 B rate that she
established as appropriate for 2005 forward. Her
refund decision does not create the minimal
differences between interstate and intrastate rates
that she relied upon to support her findings that the
state's discrimination claim is moot.
So, where are we going to go from here?
11:40:31 AM
MR. REEVES continued:
The state is considering filing exceptions to Judge
Cintron's decision on refunds on a couple of points.
First, we feel that the state's discrimination claim
is likely not moot since the judge's refund decision
shows that substantially different rules will apply in
calculation of refunds in a J&R rate litigation as
opposed to discrimination litigation.
Second, we think that allowing the carriers to retain
a $3.05 per barrel rate in calculation of refunds for
2005 and 2006 does not appropriately remedy the
discrimination and rates for those years. In
accordance with a ruling on the discrimination claim,
the refunds must result in no more than minimal
differences between the TAPS interstate and intrastate
rates for 2005 and 2006, as well as going forward.
So that pretty much concludes my remarks. I
understand that there are some people from the
Department of Revenue who will be testifying regarding
the numbers involved in the different refund
scenarios. It's my understanding the state has a
couple hundred million dollars at stake, including
interest. That concludes my testimony. I would be
happy to attempt to answer questions.
11:41:47 AM
CO-CHAIR GATTO requested that Mr. Reeves to submit his testimony
in writing to be included in the record.
11:42:20 AM
REPRESENTATIVE SEATON asked if anything in the royalty
settlement agreements would limit the state's ability to recover
25 percent of the DR&R refunds.
MR. REEVES said he recently discussed that issue with Anthony
Scott at DNR. They realize the need to go back through the
royalty settlement agreements through any tax settlements to
determine exactly what limitations exist and what actions the
state can take once the FERC issues an enforceable refund order.
He noted 25 percent is an "off the cuff number." Half of that
would be from royalties and half would be from production taxes
so both of those agreement areas will have to be reviewed.
Because the state is not an actual shipper on TAPS, it will not
receive refunds directly. The refunds will primarily be
determined by recalculating the wellhead value of the oil and of
taxes owed. He noted the state has many different royalty
agreements on different fields. Those agreements may have
limitations but that has not been the focus up to this point in
time. However, he is working with DNR's Division of Oil and Gas
on that.
11:45:09 AM
MR. REEVES asked to address questions regarding the Department
of Law's position asked during Mr. Brena's presentation.
CO-CHAIR GATTO asked Mr. Feinberg if he wished to testify at
this time.
11:45:35 AM
RICHARD FINEBERG, Investigator, Research Associates of Ester,
said at this point he would much rather listen to the
differences between Mr. Reeves' and Mr. Brena's comments. He
thanked the committee for its efforts and strongly encouraged
the committee to obtain the written materials Mr. Reeves
reviewed because of confusion on some of the points he made. He
said, as a member of the public, it is unfortunate as a matter
of public policy that Mr. Brena had to carry this function when
he has a dog in the fight. He commended Mr. Brena for his clear
and powerful testimony.
MR. FINEBERG said the testimony presented to the committee has
been so excellent, he sees no need to repeat what has already
been presented. He encouraged committee members to request
written responses from the Department of Law to ensure they get
clear answers on key points. He asserted his questions and Mr.
Brena's testimony are very consistent.
CO-CHAIR GATTO noted that Mr. Reeves has agreed to provide the
committee with his written testimony.
11:48:32 AM
MR. FINEBERG then asked if this hearing will be transcribed into
a written format. He feels it is important for committee
members to know exactly what they heard today compared to what
they see in writing.
11:49:13 AM
CO-CHAIR GATTO said notes will be available from House Records
without an official tape. He then asked Mr. Fineberg if he
agrees with Mr. Brena's disapproval of a Department of Law
attorney acting as both attorney and client.
11:52:24 AM
MR. FINEBERG said he believes very strongly that a line agency
should be making tariff policy. He expressed concern that he
did not fully understand Mr. Reeves' testimony about the
discrimination charge. He understood one argument but not
another. He felt the public policy needs to be very clear and
he believes the history of the TAPS settlement clearly states
that policy should drive tariff management issues and should be
made by a line agency.
MR. FINEBERG told members he worked at the Office of Management
and Budget in the 1980s and has studied and watched government
for 35 years and spent 10 years in Juneau. He stated:
I cannot think of any other place where the Department
of Law is its own client. It serves as the executor
for client agencies and, I believe, that's where many
of our problems stem from. That is not all of them
and that is why I think we should submit, in writing,
but I strongly believe that policy for tariff
management should be vested in a line agency with
close interagency cooperation. Then we turn the
Department of Law loose and let them run and get the
job done for us.
MR. FINEBERG clarified that he is the principal investigator in
his own firm. He is an independent economic and environmental
analyst. He is a consultant largely to non-profit and
government agencies on North Slope and TAPS issues.
CO-CHAIR GATTO asked if he is testifying for a paid client.
MR. FINEBERG said his testimony and work on petroleum production
profits tax (PPT) last year and all of the work he has done this
year have been done on his own initiative and at his own
expense. He was a state bureaucrat and is delighted to do some
public service, so he is not representing any client.
CO-CHAIR GATTO expressed appreciation for Mr. Fineberg's work.
MR. FINEBERG told the committee, for the record, many of the
projects he works on are funded by the environmental community.
11:55:12 AM
REPRESENTATIVE SEATON asked if Mr. Reeves had any comments to
make.
11:55:47 AM
MR. REEVES said he would like to address the question of what
state agencies are involved in tariff practices. He said he
doesn't have any policy view or make policy on the
interrelationship between the various agencies. However, it has
been suggested that statutorily, DNR should be the line agency.
He has no problem with that and is working closely with DNR.
However, he pointed out that 50% of the state's financial take
comes from property taxes, which is in the purview of the
Department of Revenue. This issue is overseen by a committee
made up of members from the Department of Law, Department of
Revenue, and the Department of Natural Resources. He asked
members to remember that the Department of Revenue does have a
stake in these decisions.
11:57:08 AM
REPRESENTATIVE SEATON asked Mr. Reeves about items not covered
under the duty to defend the TAPS settlement agreement, such as
DR&R and what would be done with those funds. He asked if the
Department of Law assumes if something is not specified in the
agreement, it is still required to defend that, rather than
proceed forward with further clarification of those items.
MR. REEVES said the language in the duty to defend applies to
any litigation that affects the validity or enforceability of
the agreement. In this case, the state's protest on
discrimination grounds was very legitimate. The state is
concerned that it not be dismissed from the case, particularly
since Anadarko-Tesoro is capable of defending itself.
11:58:56 AM
REPRESENTATIVE SEATON said he would like to see some of the
issues brought up in testimony in writing and to know whether
the current Administration's position is to defend items that
are not specified in the TAPS settlement agreement or whether
its role is to clarify those items.
12:00:07 PM
REPRESENTATIVE GRUENBERG referred to AS 42.06.140(a)(10), and
asked Mr. Reeves to comment on the Department of Law's
construction of that statute.
MR. REEVES replied that he tried to respond to that issue when
he pointed out that both the Departments of Revenue and Natural
Resources are line agencies that have roughly equal financial
interests in royalties and taxes. The Department of Law's
practical policy is to work with both departments in all matters
involving TAPS at the moment. He said he has not participated
in, nor is aware of, any formal interpretive review of that
statute.
12:01:39 PM
REPRESENTATIVE GRUENBERG asked Mr. Reeves, "Do you believe that
the Department of Law is its own client?"
MR. REEVES replied:
The only way I can answer that is the attorney
general, by that statute ... is charged with certain
duties. I certainly agree, and our practice is, that
the Department of Natural Resources and the Department
of Revenue both have statutory duties that relate to
this and therefore we work cooperatively on it. So
who is the client? Is it the Department of Natural
Resources? Is it the Department of Revenue? Is it
the Department of Law? I don't really have an answer
to that. I think it's kind of a - you know, it's not
the typical attorney/client situation that you have in
private practice so I'm not sure that I can answer
that. And, to the extent that it requires a policy
decision, I'm not authorized to really take that on
here.
REPRESENTATIVE GRUENBERG asked Mr. Reeves if he sees any
conflicts between the three departments and how he would handle
them if he did.
MR. REEVES answered conflicts occurred when the Department of
Law was defending the TAPS settlement before the RCA based on
its duty to defend. He was not involved in the case at the time
and does not know the level of the conflicts. As a practical
matter now, department representatives have substantial
discussions on TAPS issues and work to reach a consensus.
12:04:07 PM
REPRESENTATIVE DAHLSTROM reminded members that the co-chairs
have agreed to ask the current attorney general to address
Representative Gruenberg's questions.
12:04:51 PM
MR. FINEBERG offered an historical perspective. He said in
1990, the Commissioner of Revenue, the late Hugh Malone,
recommended that DNR be the lead agency. He informed members
that a complicated and detailed historical record on this issue
is available and he hoped the committee would get as much
information in writing as it can.
12:06:39 PM
JONATHAN IVERSEN, Director, Tax Division, Department of Revenue,
told members he has updated some numbers that he previously
presented to the committee based on revised numbers from the
administrative law judge's decision. He ran numbers out to 2008
because, at that time, the state has the option to renegotiate.
He said no one disputes the tremendous benefit the future tariff
reductions will bring to the state. He explained:
With that assumption, if we also make the assumption
that a final refund would be coming based on this
decision after it works its way through the court
system in 2010, we're looking at an amount of roughly
$500 million. If you add, then, at 10 percent
interest, it's adding about $100 million in interest
at that point. So that would be about $600 million.
If we took our previous numbers, which are all based
at the $2 rate, instead of at the '04 rate that the
judge imputed for '05 and '06, then that number,
including interest, at '10 goes up to around $800
million. So those are some speculative numbers and I
just want to clarify that those are speculative but
that's what we've run so far based on the new numbers.
CO-CHAIR GATTO said that members are interested in the amount as
they need to be aware of future sources of revenue to run the
state in the future.
12:08:55 PM
CO-CHAIR GATTO recessed the meeting to 1:30 p.m.
1:44:50 PM
CO-CHAIR GATTO reconvened the meeting and introduced Mr. Brock
and asked him to begin his presentation.
1:45:00 PM
TONI BROCK, Technical Director, BP Alaska, explained his
position is a new one with three primary duties. One of his
roles is to provide petro-technical shared resources to all of
BP's North Slope operations. He also defines BP's tactical and
strategic plans for operations management systems and processes.
His third role is to independently verify that BP's operations
adhere to BP's standard code and policy. He gave the following
testimony:
I'd like to start off - I'd like to introduce myself
and my organization and then, Mr. Chairman, take this
forward through the events since August of last year
with a view to sharing with you the areas that BP has
been in action, and share with you our process for
assuring integrity over the pipeline systems that we
have on the North Slope since the incidents of 2006.
And then I shall take you through a lot more detailed
presentation on the OTL - oil transit line -system
with the present program that we've been managing this
winter. And then finally I will take you through BP
Alaska - our forward plan, actually, just addressing
what have we learned through 2006 and what are the
issues that we're addressing as an organization, not
least in integrity management but as an organization
moving forward.
Again, my name is Toni Brock. I've got 21 years with
BP Exploration and I've worked in operations around
the globe during that period of time. I've worked the
North Sea, Southeast Asia, West Africa, the Gulf of
Mexico. My last job was as an operations manager for
one of our fields in the North Sea before coming to
Anchorage to set up the new position of the Technical
Directorate in Anchorage, Alaska. I moved here with
my family, my wife and two sons, in August 2006. I
moved from Aberdeen, Scotland.
My primary role when I moved over here was actually to
start to set up this new technical directorate
organization, as I said. The role was seen as a new
role. It was seen to add independent oversight to how
we run our operations. It was set up to look beyond
the day-to-day operations but to be more strategic on
how are we actually going to set up reliable, safe
operations and manage them for the future looking at
BP's future of 30 years, 50 years future in Alaska.
That was the primary role to do that.
Over the course of the last eight months, I actually set up
that organization. The organization has in the order of
150 people. Of those 150 people, 60 of them are new
positions to BP Alaska. Those positions are primarily
focused at technical authorities and engineering capability
within the organization in Alaska.
Since the end of 2006, we've been heavily engaged with
the other operating entities in Alaska, such as the
ACT business units, such as Northstar, Endicott, and
Badami and also Milne Point and greater Prudhoe Bay,
defining accountabilities and roles within our BPX
organization to insure we have consistency in approach
and a clear line of accountabilities for managing our
day-to-day operations and insuring integrity in our
facilities.
In the course of this I'd like to actually refer to
the presentation that I've given out and what I'd like
to do is just go through the slide packet. There are
a considerable number of slides. What I'd like to do
is go through them and in the course of the
presentation I'm very happy to take any questions that
you may have and at the end again I will take any
questions you may have.
So my primary focus is actually just to give you a
brief update of how we resumed business and restarted
production in greater Prudhoe Bay, then move to
operations and integrity assurance and pipeline
renewal and the forward plan.
1:49:42 PM
REPRESENTATIVE GRUENBERG asked if the committee is going to
review activities back to the 1990s to look at how the corrosion
was allowed to occur or if the committee would only be looking
at the recent past.
CO-CHAIR GATTO said the legislature is trying to determine
whether to retroactively disallow the pipeline repair costs as a
credit against revenue.
1:51:25 PM
MR. BROCK said he is not a tax expert so his presentation is
focused on the future. His role is to ensure that BP has
learned from the past so that this type of incident does not
occur again. He said hundreds of thousands of emails have been
sent over the last seven years related to different discussions
and decisions associated with budgets and activities. Getting
the right balance between the targets set and actual
expenditures is an ongoing part of any business to ensure that
it is safe and viable. He said he has not reviewed all of the
documents nor does he have the insight to be able to answer
questions about them. He can only assure the committee BP is
looking to ensure safe operations in the future.
CO-CHAIR GATTO said the legislature would expect no less and
appreciates his testimony.
1:52:21 PM
MR. BROCK continued his presentation:
First of all I just wanted to ... orientate the
committee members to greater Prudhoe Bay itself and
this slide actually shows you the extent of the OTL
systems ... as they relate to the gathering centers
and flow stations, just to keep everybody up to speed.
On the left hand side of the slide, we refer to GCs
... which are gathering centers, these are processing
plants. Their primary purpose is to separate oil,
water, and solids from the oil that is produced from
our wells before actually putting them into the
transit line system, which you'll see there is red on
the diagram.
The references on the right-hand side of the slide to
FS2, FS1, FS3 - these are flow stations. These have
exactly the same purpose as gathering centers. This
is just a naming [indisc.] that comes from the
different heritages of the field when it was ARCO and
BP operated. But, for the purposes of this, I just
want to draw a reference to the GC1; GC2 to FS2 is our
primary oil transit line for greater Prudhoe Bay.
Over the course of 2006, we had two leaks on that
transit line system. One was actually one mile
downstream from GC2, between the section of line
between GC2 and GC1. The other was actually very
close to the facility at FS2. You can see there's a
line from east to west that's approximately 16 miles.
What I want to do now, I'd like to take you through
some of the business resumption program that BP put in
place within 100 days of the incident. Over the
course of that time, to reestablish production at the
facility, and you'll remember we shut down production
at the eastern side of the field after the leak
because we wanted to provide greater assurance that we
understood the integrity of that line before starting
up production. In the course of that we actually
removed installations and inspected and reinsulated
over eight miles of the transit line system. The
section that was inspected was actually the section
that is in service today. The section in the west
where we had a leak between GC2 and GC1, and the
section from FS1 to FS2, those sections were actually
put out of service and they're not in service today.
In the course of that time, we actually installed five
new bypasses. The issue for us there was that at the
time we didn't know whether we'd be able to
reestablish integrity within the systems that were
currently in place so we actually moved to put five
bypasses in place to ensure that we could get secure
enough supply in the event that we couldn't prove
integrity of the existing systems.
Also in the course of this we actually put 34 hot taps
in place in the western area of the field to drain off
oil from the line that actually had corroded through
and was leaking. And the idea was to de-oil that line
and give us satisfaction that that line was actually
safe and there was no other threat to the environment.
In addition to that, with the isolation of that
section at GC2, we no longer had the ability to pig
that section from west so we actually installed a
temporary pig launcher in the western side to allow us
to pig that line with the smart and maintenance pigs.
By the end of the year, we'd actually run six cleaning
and one gauge pig and two smart pigs through the
eastern side of the field and similarly for the
western side of the field to verify the integrity of
that system. The results from those smart pigs verify
that the sections that we had in service were actually
fit for service. On that basis, we actually started
up at FS2 and our oil collect unit, through the
Endicott bypass system.
We actually, at that period, got a lot of cooperation
and support from the regulatory committees and
agencies to get our permits and commercial agreements
in place and we appreciate what we got from the state
on that. In the course of our inspection, we've
actually removed two 40 foot sections from the line to
allow us to conduct an in-depth investigation into the
mechanistic cause of the corrosion itself. Actually
in the course of the 100 days we actually increased
our North Slope count population by 700 personnel.
Today, we're actually running at peak personnel
numbers in excess of 2,000 people that our count set
at the North Slope. That's a 44 percent increase over
normal numbers.
Over the course of that period and through the winter
we actually went through seven major production start-
ups, which was a particular task in the course of the
winter. Actually, in January of 2007, we actually
reestablished production rates at a number prior to
the leak, so 430,000 barrels a day.
This diagram that I've showed illustrates the transit
lines and the simple [indisc.] format. It shows you
the positioning of the bypasses in relation to the
OTLs. What I'd like to refer to there is the red
sections are sections that we have out of service.
The section on the left between GC2 and GC1 actually
has been decommissioned and it has been deconstructed
through the course of this winter and is no longer in
place. The section between FS1 and FS2 is going to be
decommissioned and deconstructed through the course of
December-January this year and early '08.
This just gives you a sense of where we are with
regards to the bypass status and we do have a bypass
in place at flow station 2 but at flow station 1 we
actually have a bypass that's been built but it's not
in service. It's not in service because to put it in
service, we'd interrupt production and we don't see an
integrity reason for us actually to put that line in
service right now. In the event of an issue, it will
take us two days of shutdown to actually put that line
in service and commission it. Similarly for flow
station 3, we reckon the line is in place and the
final time will take us seven days if need be.
For the western area, we have a fully operational
bypass in GHX, GC1, and that is installed and it's
going to be in service until we get the replacement
line in. Similarly for GC1 and GC3, we have bypasses
in place and constructed and we estimate it would take
five days for us to actually commission those systems
if need be.
That was really just a very quick overview of what we
did to respond to the initial spill, to reestablish
integrity in the line, and also to provide efficient
redundancy so that we could reestablish reliable oil
flow through Prudhoe Bay. The next series of
photographs are really an illustration.
1:59:16 PM
REPRESENTATIVE FAIRCLOUGH asked for the definition of "OTL."
MR. BROCK replied oil transit line.
REPRESENTATIVE FAIRCLOUGH asked if the deconstruction costs are
being charged against incremental removal and restoration on the
pipeline.
MR. BROCK said he would have to refer that question to BP's
commercial team. He offered to get an answer to the committee.
CO-CHAIR GATTO asked Representative Fairclough if she used the
word "deconstruction."
REPRESENTATIVE FAIRCLOUGH said yes, that was the word Mr. Brock
used. She explained:
That's why I was wondering ... earlier this morning we
had a conversation about those costs being fixed and
sort of in an account or what Tran Alaska Pipeline
ownership ... as the oil team takes those dollars,
we're looking at, I believe, $1.5 billion as proposed
to be collected. And I'm wondering if they are going
to charge that cost of dismantlement, removal and
restoration, which would decrease that fund and goes
along with what Max was saying. We're trying to
determine what charges the corporations are going to
come back and charge against the line and I want to
know if we're deconstructing a portion of the pipeline
now, whether we'll have incremental hits to the DR&R
and how that will affect the FERC and the rate
calculations going into the future.
CO-CHAIR GATTO asked if DR&R funds are reserved for use when oil
no longer flows or whether it is accessible before that time.
MR. BROCK said he is not familiar with the requirements of that
act.
CO-CHAIR GATTO thought DR&R applies to decommissioning the
pipeline so he would not expect that fund to be tapped for
anything prior to that.
REPRESENTATIVE FAIRCLOUGH said BP has removed a part of the
pipeline and put in a new line, which would be part of the cost
of TAPS as a whole. She said deconstructing part of the line
could open up a way to use that fund.
2:02:02 PM
REPRESENTATIVE SEATON asked that the committee get an answer on
whether the DR&R fund can be used for TAPS and the flow lines.
He thought the flow lines are not included because TAPS begins
at Pump Station 1.
CO-CHAIR GATTO noted if the DR&R fund was used to pay part of
the costs, it couldn't be declared as an expense against the
revenues.
2:02:57 PM
REPRESENTATIVE FAIRCLOUGH thought Co-Chair Johnson's analysis is
correct, that being that Mr. Brock is speaking about a BP-owned
line, not TAPS.
MR. BROCK told members this line at Prudhoe Bay is owned by the
working interest owners: BP, ConocoPhillips, Exxon and Chevron.
REPRESENTATIVE FAIRCLOUGH said under that scenario, if the
owners deconstruct a portion, they could hit DR&R for a portion
of those funds because that is the purpose of those funds.
However, they could also consider the costs as an expense
because they are creating a new line.
2:03:50 PM
MR. BROCK continued his presentation:
As I said, these photographs are really - I'm not
going to go through them in detail, but they just
reference the scope of the work that was undertaken to
put the bypasses in place. We've had some inquiries
in the past to the extent of these lines. These are
relatively short, small bore diameter pipelines that
give us the extra redundancy to bypass the existing
oil transit lines if need be and I'll quickly move
through these.
What I did want to refer to actually is - so in BP's
response to the leaks in 2006, our primary concern was
to reestablish the integrity of the lines and then
reestablish production and I talked to that. In
addition to that actually, there [are] broader
implications of how we operate in Alaska. One is that
we want to actually ensure that we had a good
understanding of the corrosion mechanism at hand and,
as such, we've done a number of things to do that. In
the cause of our investigation, we've determined that
there are three factors that contributed to the
microbial-induced corrosion that we now feel was the
causal factor of these leaks. That is actually in the
build-up of or combination of sediments, water, and
low-flow velocities within the oil transit lines
themselves.
We also actually started to start a part of the
Department of Transportation correct batching order to
carry regular maintenance pigging on all of our oil
transit lines and also run intelligent pigs to verify
the integrity of those systems. And we've also
improved the safety standards that we work to and
integrity standards that we work to as we've got all
of our oil transit lines on to the Department of
Transportation's pipeline integrity management
program. Prior to this, the oil transit lines in
greater Prudhoe Bay weren't covered by this standard
and we volunteered to bring that line into that
standard now and, in effect, we're in compliance now
with that standard.
2:05:45 PM
REPRESENTATIVE GRUENBERG noted that Mr. Brock said BP was just
recently made aware of the cause of the corrosion, however
according to some [of BP's] e-mails, BP was aware that corrosion
was likely if steps to prevent it were not taken. He asked Mr.
Brock if he was aware of those e-mails.
MR. BROCK replied he has seen numerous e-mails from different
staff that made different assertions regarding corrosion and
inspection regimes within the field. He added the oil transit
lines were low-risk lines with regard to corrosion. BP removes
the gases, liquids and solids from the lines at the processing
facilities prior to entering the oil transit lines. The oil
transit lines only carry sales-quality crude. Those lines have
been inspected on a regular basis over the past 30 years. Those
inspections, up until the second half of 2005, showed
insignificant or negligible corrosion within the lines. After
that BP did see an increase in the corrosion rates so it
increased the frequency of its inspections and scheduled smart
pig runs. Unfortunately, the leak occurred in March, prior to
the scheduled smart pig run.
2:07:35 PM
REPRESENTATIVE SEATON referred to a memorandum he sent to BP
after BP staff testified on Aug 18, 2006 before the House
Resources Standing Committee. During that testimony, a BP staff
member stated what Mr. Brock just said: that BP didn't
anticipate corrosion because the water is removed from market-
ready crude before it enters the line. The committee's
information was that the TAPS operators knew the pipeline would
be subject to corrosion if it wasn't pigged regularly and BP
agreed to use cleaning pigs every two weeks, as well as to
regularly use smart pigs. BP says it has the same oil in its
gathering lines but didn't pig those lines for years. BP would
be responsible for the cost of pigging the gathering lines and
couldn't charge those costs off to the tariff, as it could with
TAPS. He questioned why Alyeska anticipated the problem on TAPS
but BP did not on its gathering lines. He noted BP has not
responded to his memorandum.
MR. BROCK said BP runs maintenance pigs every other day at its
BP greater North Slope facilities. With regard to its pigging
philosophy for its transit lines versus Alyeska's operations,
pig runs are determined by a number of factors, primarily
through operational requirements or corrosion management. Smart
pigs provide information on the line's integrity and identify
corrosion spots. The maintenance pigs used at Alyeska ensure
that lines are clean and are run for operational reasons.
Prudhoe Bay crude is relatively sweet with little wax. Other
North Slope fields feed into Pump Station 1 that have wax in
them. That travels down TAPS and comes out of the line itself.
His understanding is that one reason Alyeska pigs so frequently
is to remove the wax build up because it affects the hydraulics.
In the greater Prudhoe Bay's short pipeline system, wax does not
build up; it is run at higher temperatures. However, that
phenomenon occurs in TAPS' 800 mile pipeline.
REPRESENTATIVE SEATON asked Mr. Brock if Alyeska's maintenance
pigging is done to test for corrosion as well.
MR. BROCK opined that corrosion could be part of it. He said he
is not familiar with how Alyeska deals with its corrosion
systems but believes many factors are considered when looking at
a maintenance pigging operation.
REPRESENTATIVE SEATON requested a written response from BP to
his memorandum dated September 7.
MR. BROCK apologized for the lack of formal response and ensured
one would be forthcoming.
2:12:35 PM
REPRESENTATIVE OLSON pointed out the transit lines have not been
pigged since 1998. Legislators have been told that one reason
they have not been pigged is because the build up of wax
prevented BP from getting a pig into the pipeline, which
contradicts what Mr. Brock stated. To ignore that problem for
eight years is, in his mind, criminally negligent.
CO-CHAIR GATTO agreed it is confusing to hear that the shorter
lines have no wax but that they couldn't be pigged because of
too much wax. He repeated the need for a consistent written
statement from BP management.
2:14:52 PM
REPRESENTATIVE DAHLSTROM asked Representative Seaton who the
memorandum was addressed to.
REPRESENTATIVE SEATON replied it was addressed to the chairs of
the House and Senate Resources Committees, the Administration
and to BP. He noted Steve Marshall of BP made the statement to
the House Resources Standing Committee that lead to the
memorandum.
REPRESENTATIVE DAHLSTROM noted that Mr. Brock was not
responsible for the response but asked him for a date when the
committee could expect to hear from BP.
MR. BROCK said he would have a response to the committee by the
end of the month.
2:16:19 PM
CO-CHAIR JOHNSON expressed appreciation for Mr. Brock's work to
correct the problems but said the committee anticipated finding
out the cause of and how the leak occurred. He expressed
concern that the committee's questions are not being addressed
to the appropriate person. He asked that the committee get
testimony from the appropriate person in the near future to get
those questions answered. He suggested directing questions to
Mr. Brock about what has been done to remedy the problem.
CO-CHAIR GATTO said the committee has access to BP management
through Mr. Brock. He is sure Mr. Brock can convey the
committee's concerns.
2:18:41 PM
REPRESENTATIVE GRUENBERG agreed with Co-Chair Gatto and said the
committee's questions have nothing to do with Mr. Brock
personally. Members just want answers to their questions. He
stated his questions relate to a series of emails to and from BP
staff that appear to use a form of company shorthand. He asked
Mr. Brock to provide committee members with a key to what was
discussed; particularly in emails dated June 4, 1999 that refer
to a PW inhibitor and EC 1081A injected at stations GC2 and GC3.
CO-CHAIR GATTO asked what document Representative Gruenberg was
referencing.
REPRESENTATIVE GRUENBERG clarified he was looking at two e-mails
on the bottom of page 2 in Exhibit 4.
MR. BROCK explained that a PW inhibitor is an inhibitor added to
produced water (PW) systems. When oil is produced, water and
gas are produced with it. As the water and gas are separated
out to the export line, the produced water is reinjected to
maintain reservoir pressure. That term refers to a produced
water line for transportation of the produced water back for
reinjection. He explained the water is entrapped in the oil
when it is initially produced.
REPRESENTATIVE GRUENBERG asked if a produced water inhibitor is
a type of chemical.
MR. BROCK said it is.
REPRESENTATIVE GRUENBERG asked that chemical would have helped
to prevent corrosion.
MR. BROCK said the word "inhibitor" is used in a broad sense in
this case. He explained:
My understanding is that the chemicals used have got
two purposes. One is actually to aid inhibition in
the line but the system itself is inhibited from the
wellhead. As we produce oil, we inject inhibitor
directly at the wellhead and other parts of the
processing plant. Actually, produced water is
inhibited as it goes into the produced water system
from inhibition injected earlier on in the process.
What we're experimenting with here was actually
enhanced inhibition but also produced water has some
entrained oil in it and actually what we were noticing
was a build up historically of solids within that
line, kind of a film within the line but it does
effect the efficiency of the system and actually the
inhibitor here had a surfactant quality. It is what
helped break up that lining in the pipeline itself - a
bit like a washing detergent. Through the course of
our operations in Prudhoe Bay, we continuously look
for different types of inhibitors for our produced
water system to just aid the efficiency of that
system. Over the course of the years we have numerous
trials ongoing to find inhibition.
REPRESENTATIVE GRUENBERG asked, "When you talk about inhibiting
this sort of thing, would it have inhibited and potentially
prevented the type of corrosion that did occur?"
MR. BROCK answered it would not have in this case. The produced
water system is independent of the oil transit line system where
the leak occurred.
REPRESENTATIVE GRUENBERG asked if, in Mr. Brock's opinion, the
failure to put the inhibitor into the system would not have any
effect on preventing the corrosion.
MR. BROCK replied:
In this particular case, the inhibitor referred to -
as I read through the series of e-mails as I
understand it in the document - was part of a trial.
We have ongoing trials in this area and that let's us
know it had no effect on the corrosion and the leak on
the oil transit line system.
2:24:08 PM
CO-CHAIR JOHNSON asked where the August leak occurred.
MR. BROCK said that leak was a few hundred yards down the line
from FS 2 to FS 1.
CO-CHAIR JOHNSON noted the e-mail references GS 2, GS 1, and GS
3, so surmised that the inhibitor was not removed from the pipe
that leaked.
MR. BROCK affirmed that is correct and clarified that BP has
numerous pipeline systems in the field: gas lines; seawater
lines; gathering lines for gas, water, and liquid; the oil
transit lines; and produced water lines. Those systems are
independent of each other. That e-mail refers to a produced
water line, which is independent of the oil transit system.
REPRESENTATIVE GATTO stated:
I was shaking my head because it said being injected
at G2 and G3. It would have been in the section at G2
but it was a different line that they're referencing
here, a line different from the line that did, in
fact, corrode.
MR. BROCK said that is correct.
REPRESENTATIVE GRUENBERG said he needed to clarify that the
inhibitor was not put into the line that leaked; it was removed
from another line.
CO-CHAIR GATTO asked if the inhibitor was in the line that
leaked.
An unidentified speaker said it was not.
REPRESENTATIVE DAHLSTROM asked if the inhibitor mentioned is the
standard chemical mixture used so that members could assume that
was in the line that leaked.
MR. BROCK replied:
What I can say is the inhibitor that we referred to in
this e-mail was specific to a produced water system so
it wasn't in the oil transit line system. The oil
transit line system was inhibited with a different
inhibitor.
REPRESENTATIVE DAHLSTROM asked Mr. Brock how many types of
inhibitors are used.
2:26:40 PM
MR. BROCK said BP has inhibition programs for all of its lines.
He furthered:
What we'll have is we'll have inhibition programs for
all of our lines so we have the lines that come from
the wells are inhibited so as we get production out of
the wellhead, we inject inhibitor at that part of the
system. That inhibitor is dosed to allow - to keep
retained a percentage of inhibitors to right the
system even as it goes through into the TAPS - Trans
Alaska Pipeline system itself and that's our primary
inhibition system and that's the inhibition system
that inhibits the oil transit lines. The produced
water system has an additional inhibition in that line
itself. And the role of that was twofold. One was to
act as kind of a cleaning agent. Secondly was to see
if we could improve inhibition in that line itself.
One of the challenges we have with this type of trial
is that the rates of corrosion that we have take years
and years to manifest themselves so short time trials
take time to monitor and it takes us time to evaluate
them so it's quite common we'll have corrosion coupons
in the line that we'll put in. We'll do inhibitor
trials for awhile with new coupons and then we'll
retract the coupons and do assessments on them to
determine if the inhibitor was effective or not.
That's quite a long, drawn out process.
2:28:19 PM
CO-CHAIR GATTO pointed out chemical corrosion is caused by water
on metal but biological corrosion also occurs. He asked if both
types are treated with a different substance or whether BP uses
biocides and rust prevention agents.
MR. BROCK said BP's system uses an inhibitor and biocides
combined.
CO-CHAIR GATTO asked which is more severe.
MR. BROCK replied the two have different purposes. The biocides
kill the bacteria while the inhibitor coats the pipe to protect
it.
CO-CHAIR GATTO asked if water corrosion of the pipe is more
severe than biological corrosion.
MR. BROCK said that depends upon the operating environment and
other contributing factors, such as temperature pressure. All
of those issues need to be addressed in BP's corrosion program.
CO-CHAIR GATTO said he was curious to know whether answers exist
at this time because he is often asked about how the corrosion
happened by the public. He asked where the bugs come from.
MR. BROCK said the bugs are in the matter that formed the oil.
CO-CHAIR GATTO asked if they live in the seams and come up with
the oil.
2:30:14 PM
MR. BROCK said they do. He added BP evaluates the corrosion
mechanisms and threats within given systems because each type of
environment in which the corrosion manifests itself is unique to
a certain set of circumstances. BP evaluates the correct
inhibition for a given circumstance and a given system.
2:30:38 PM
REPRESENTATIVE FAIRCLOUGH asked what the capacity volume is on
the lines BP is running.
MR. BROCK said the oil transit lines are currently running at
approximately one-quarter of their peak throughput rate with a
current volume of about 350,000 to 400,000 barrels per day.
REPRESENTATIVE FAIRCLOUGH, for the record, stated:
Some of the validity of using inhibitors versus
pigging or other things that actually physically touch
the system on the interior of the line makes a big
difference on capacity volume and flow through and so
I would expect, from what I know about the inhibitors
and the cleaning of the line, that if the line is not
running full we're going to have more corrosion
because the inhibitors aren't hitting where they are
supposed to hit anymore.
CO-CHAIR GATTO asked if the replacement line has a smaller
diameter so it would fill more quickly.
MR. BROCK said reduced volume impacts the velocity. BP reviewed
the existing system to determine repair options. Its primary
concern is that Prudhoe Bay is a declining field yet it has a
long life ahead of it. BP wanted to design a system that would
be useable for the next 50 years and a system optimal for the
types of production rates and fluids it would carry. BP felt
the current system design of pigging, chemical inhibition,
metering and leak detection needed to be replaced. As such, it
chose to replace the existing system rather than repair it.
CO-CHAIR GATTO asked if BP has used plastic pipe.
MR. BROCK said it has not used plastic pipe at Prudhoe Bay but
it has commissioned an entire overhaul of its corrosion
management strategy of its North Slope operations. BP has the
final draft report for approval and that strategy suggests
considering life-of-field material selection. As BP looks for
renewal and to building new facilities to deal with the
transition from viscous oil to gas, it is looking at stainless
[steel] materials and plastic for future operations and
refurbishment
CO-CHAIR GATTO said he recognizes plastic could fracture at
minus 80 degrees.
MR. BROCK acknowledged the basic premise is that plastic pipe
has good corrosion resistance but relating that to valves and
safety and pressure systems presents a challenge.
CO-CHAIR GATTO said he was curious because a new hospital
installed an all plastic sewer line.
2:34:24 PM
REPRESENTATIVE GRUENBERG referred to an e-mail on the top of
page 4 in Exhibit 4 from Dominic Paisley (ph) to PBU, etc. He
noted Mr. Brock said these e-mails referred to a different
pipeline. He asked if the statements in that e-mail are equally
applicable to the pipeline in question.
MR. BROCK said he was not in a position to review all the
technical aspects referred to in the email to determine whether
they refer to a likely corrosion assessment. He is not aware of
what assumptions were used regarding the life of the pipeline
and what inhibition systems were in place at that time.
REPRESENTATIVE GRUENBERG asked Mr. Brock if he knows what caused
the corrosion in the pipeline in question.
MR. BROCK replied:
In the oil transit lines, we feel it was a combination
of water, sediment build up and low velocity in the
lines. The low velocity in the lines allow solids to
fall out and water to fall out and they create an
environment that prevented inhibition from working
effectively.
REPRESENTATIVE GRUENBERG asked, "Well, if it was potentially
water, wouldn't the same kinds of statements that are made here
possibly be applicable there as well?"
MR. BROCK responded, "The case for the oil transit lines is the
combination of the factors."
CO-CHAIR GATTO commented:
I'm guessing the critters need water to survive and
when you get water trapped and the critters are living
in the water, you've got it all precipitated out and
it's being covered with solids, that's a great
environment. You get to hide underneath in the low
spot of the line and then as the biocides come through
they kind of float over the top and do not necessarily
penetrate the solids and you have a wonderful set up
for eating away in a very localized area ...
ultimately causing failure. Is that how it works?
MR. BROCK said he believes that is how it works. His primary
goal is to understand the causal factors so that the operating
environment within the pipeline systems can be changed to ensure
the bugs are killed and cannot breed in that environment. So
far, BP has enhanced the ability to inject corrosion inhibitor
directly into the OTL systems. BP does regular maintenance
pigging right now to remove any water from the system.
Maintenance pigs are used on the oil transit lines on a weekly
basis. He noted, as a result, the lines have no solid build up
and no bacteria build up.
2:39:05 PM
CO-CHAIR GATTO asked what BP would do if it discovered the
problem was due in large part to low velocity. He questioned
whether the velocity could be increased by alternating the use
of Line A and Line B.
MR. BROCK said BP is looking at two areas; the new system design
has addressed that. The smaller diameter pipe will increase the
velocity to three feet per second. The pump out at the flow
stations could be increased but that is constrained by the
export pumps at the facility at this time. Those are major
pieces of equipment so the facility would have to be shut down
to replace or upgrade those pumps.
2:40:09 PM
MR. BROCK continued his presentation:
... We're probably going to cover some of the material
that we've already covered in terms of the causal
effects and, as I said, we actually tried to - we
referenced a combination of water sediment bacteria
that led to this particular circumstance occurring and
we are doing a detailed analysis of that so it comes
out again in another slide.
What we looked at in our corrosion mitigation
strategy, we looked at a number of different
contributing factors. We looked at carbon dioxide
build up in lines, which is corrosive. We looked at
continuous inhibition against that. We looked at
stagnant water or sediment in lines and we used
maintenance pigs to extract that. And like I said
before, in the course of a year, we will run hundreds
of maintenance pigs across a multitude of our lines.
We've got full-time teams working entirely on that.
That's their full job at the greater Prudhoe Bay.
And in terms of bacteria ... we'll scrape the side
walls to remove any bacteria build up with the pigs
and use biocides in there. There are chlorides within
the biocides to kill the bugs.
CO-CHAIR GATTO said when carbon dioxide is added to water,
carbolic acid is created, which eats away metal.
MR. BROCK continued:
Where we're at right now - the status - is the lines
were cleaned extensively before the ILIs were run and
we run weekly and monthly cleaning pigs, depending on
which system we're talking to. We put supplemental
corrosion inhibitor into the OTLs and we analyze our
returns for bacteria build up and a repeat of the
circumstances we had before. Since August we've
actually carried out over nearly 24,000 ultrasonic
inspections. We do repeat inspections over areas we
know we've got known corrosion. The idea there is
that we're able to monitor the rate growth of any
corrosion. We will actually repeat smart runs this
summer and through the third quarter of this year.
That is to further verify that we're in control of any
further corrosion within the system.
This slide is really just to illustrate some of the
techniques that we use to do that ultrasonic
inspection. We do deep ultrasonic inspection a foot
at a time. It's a very detailed inspection over this
period and it gives us a representative example of the
condition of the line itself.
One of the things that is notable is that unlike other
pipeline systems in the Lower 48, our lines are above
ground and we have access to them. As such, we
actually conduct a lot of external UT inspections.
That's one of the reasons why we talked to - why we
were comfortable that we didn't run more smart pigs.
Well, we actually compliment the smart pig runs with
extensive UT inspections. That's not something that
other systems have got the luxury to do. To do that
you do need to remove the insulation from the system
to get access to the wall of the pipe itself.
This is an illustration of a smart pig. This to
itself is one of the tools that we used on the OTL
systems. The brushes you see on the right hand side
are actually giant magnets. They create a magnetic
flux and that allows us to [see] deviations within
that flux and read out - give us an insight to any
wall thickness and any deviations within the pipeline
itself.
As I said, we've carried out extensive analyses to
determine the mechanism associated with these
failures. On the western operating area of the field,
GC2 to GC1, we've had a consultant, Dr. David Dukette,
carry out a complete and thorough investigation and he
has confirmed that it is microbiological induced
corrosion - is, in effect, the mechanism at hand here.
In the eastern operating area, we are actually
carrying out a similar review right now and we hope to
have that report back by the end of the second quarter
of this year. In both cases we took out 40 foot
sections associated with the leaks so that we could do
a detailed analysis of the actual leak itself. These
diagrams just illustrate the process for removing the
pipe and give you an example of the pitting. Mr.
Chairman, you just referred to this type of very
localized pitting that we feel is the leak path.
2:44:33 PM
REPRESENTATIVE GRUENBERG asked if the photograph on the left
shows a segment of the pipe being removed.
MR. BROCK said that is correct.
REPRESENTATIVE GRUENBERG asked for a description of the
photograph in the middle.
MR. BROCK said the pipe was actually cut into sections to
analyze samples. The middle photograph shows sections from the
pipe sample that were removed being cut. The last photograph is
an example of pit and corrosion.
REPRESENTATIVE GRUENBERG asked about the size of the pit.
MR. BROCK estimated the pit to be 1/4 inch.
REPRESENTATIVE GRUENBERG asked if it goes through the pipe.
MR. BROCK said that particular pit did not.
CO-CHAIR GATTO asked if the photograph was on the inside or
outside of the pipe.
MR. BROCK clarified it is on the inside of the pipe.
CO-CHAIR GATTO noted a lot of gauging around the pit and asked
if that is additional corrosion or was caused by the pig.
MR. BROCK said he is trying to determine whether that is
residual water from washing the sample. He was not sure.
MR. BROCK continued his presentation:
One of the areas I wanted to show is - in carrying out
our investigations, we've actually determined that
we'd look at a broader, holistic corrosion control
strategy for all of our facilities on the North Slope.
We've called in an external team of BP experts and
industry experts to do that. We've also brought in
our working interest owners - ConocoPhillips and
ExxonMobil. We've actually been through and developed
a new strategy for our operations in the North Slope
that's at the final stage of sign off.
In addition, we're actually increasing our Corrosion
Inspection and Chemicals team. That's what the CIC
stands for. We've increased by 60 percent and we will
increase that team by 100 percent. Here in Anchorage
they will have over 30 permanent BP staff members
working on that team. Their primary role is actually
to take the strategy and develop specific plans for
each of our facilities with regard to the systems and
processes that they manage. This system will cover
all of our operations from drilling to oil production
to water handling.
In addition to that, we're going to put additional
positions on the North Slope. These additional
positions will be lead corrosion positions and their
job will be to coordinate our inspections and our
corrosion monitoring at our North Slope facilities.
This is a new position to enhance our understanding at
the facility level.
In addition now we're also working on a new smart
pigging philosophy. We have a new strategy that's
being delivered. This year we'll be running
approximately 18 smart pigs and we just ran the first
of those additional smart pigs this week.
In addition to that, we're committed to improving
overall awareness of corrosion in the North Slope
environment and, as such, BP had actually sponsored a
program through NACE to develop a new week long class,
which our personnel will go through and it will be
open to all of the members of the industry to actually
raise awareness with regard to corrosion beyond the
preliminary understanding. BP is funding 100 percent
of that.
2:48:39 PM
REPRESENTATIVE SEATON asked if 18 smart pig runs will occur in
2007.
MR. BROCK said 18 individual smart pig runs are programmed to be
run in the overall pipeline system. That will cover gathering
lines, the OTLs, and the produced water systems.
REPRESENTATIVE SEATON asked if 18 smart pigs will be used
continuously in the field.
MR. BROCK said a number of pigs could be run on different lines
multiple times. They will be different sizes and run through
different systems.
REPRESENTATIVE SEATON inquired whether BP's entire system will
be covered in one year.
MR. BROCK said it will not. It will cover the area BP believes
needs to have smart pigs. That is determined by the program
schedule or from review information from the leak.
REPRESENTATIVE SEATON asked what percentage of BP's lines in the
Prudhoe Bay unit will be covered.
MR. BROCK said he could not answer that question at this time
but would provide the information at a later date.
CO-CHAIR GATTO asked how Mr. Brock would respond.
MR. BROCK said he would send a letter to Co-Chair Gatto for
distribution to committee members.
2:50:55 PM
REPRESENTATIVE GRUENBERG referred to an e-mail at Tab 3 dated
July 27, 1997 and asked if the e-mail related to the line in the
first diagram under discussion.
MR. BROCK said the e-mail contains no reference to a specific
system but he does not believe it is referring to TAPS.
REPRESENTATIVE GRUENBERG said it looks like BP came up with a
long-term smart pigging contract 10 years ago. He asked Mr.
Brock if, prior to 2006, BP had a smart pig contract in the
section of the line under discussion.
MR. BROCK did not know.
2:52:52 PM
REPRESENTATIVE SEATON said, regarding his September memorandum,
workers at Alyeska said they were extremely concerned for
several years that BP had no way to handle an anticipated large
amount of sediment that could not be handled by Pump Station 1
filters. He said the e-mail refers to Pump Number 1 so it
appears that is the line under discussion. He asked Mr. Brock
to incorporate that item into his response. He stated:
This is what is very much of concern, as
Representative Olsen had said earlier and we had
information from other sources at Alyeska that the
concern was that BP couldn't run a smart pig because
they couldn't handle all of the sediment that was
going to come out of that line. It seems like this e-
mail here, and this is way back from '97, is
indicating that this has been a problem that had been
anticipated from the Prudhoe Bay unit for a long time.
So if you would find out exactly which lines these are
talking about, and if this anticipated the identical
problem of not being able to run those pigs because
there was no contingency for handling the solids other
than slugging Pump Station Number 1 and shutting it
down.
MR. BROCK agreed to do so.
2:54:57 PM
CO-CHAIR GATTO referred to the first page of Exhibit 23, which
was a 2005 e-mail from Kip Sprague. He read:
Bitch, bitch, bitch. I will try to wrestle down some
middle ground between the reality of the situation and
some feel good place holders just to get people off of
your back. However, I will not run or sacrifice an
inspection strategy and program with limited resources
based on the conveyance of maintenance and our
operational impact.
CO-CHAIR GATTO said that is negligence in his opinion and
expressed concern that a better response was not provided. He
asked what a BP administrator would do with such a statement.
MR. BROCK stated it is disappointing to hear an employee so
frustrated by the process. BP needs to create an environment in
which employees can voice their concerns and issues so they
don't get to that stage of frustration.
CO-CHAIR GATTO said the e-mails capture his attention because
they show BP's record rather than glossy photographs that show
what BP is doing now to correct problems. He asked Mr. Brock to
express his concern that BP hears complaints and then produces
beautiful brochures to respond to them.
MR. BROCK said he would do that. He told members:
I mean words are words, presentations are
presentations and they actually don't mean anything
unless you take action. What I'd like to tell you is
that there are a number of things that we've taken
real clear action on. One is we set up the technical
directorate as such it's an independent body. So
these types of inquiries and queries actually have got
a functional oversight rather than being buried in the
line organization. So we have that independence when
it comes to issues of safety or the integrity of our
facilities. We have an independent body now that has
oversight on the decision making process. That's
first and foremost.
Two, this body that Kip Sprague worked for, CIC, [is]
embedded in the greater Prudhoe Bay organization.
That organization reports directly to me. Bill
Hedges, who is the CIC manager, reports to me and Kip
reports to Bill Hedges. I report directly to Doug
Suttles. So we have greater transparency to the
organization so that these issues aren't left buried
in the organization itself.
Finally, I think one of the issues for us is ... our
full understanding of risk. When we look back at the
analysis from Bruce Allen into the concerns we had and
how these leaks occurred, their reference was that
this wasn't actually about cost cutting or such. Their
evidence pointed to our overall awareness of risk
within the system itself. And on that, in effect,
what we've actually done is we've actually put in
place a rigorous risk register, risk review process.
That process is being embedded at the field level.
It's been embedded at the technician level, the
operator level and, as such, is managed up through the
field line to the senior members of the management
team in BP Alaska. That system will be there. We
review it on a regular basis. It's my role to present
that. Doug Suttles is President of BP Alaska and I'm
to ensure that we take proper action on these types of
issues so they get resolved and overall we're focused
on reducing risk within our field.
These are the things that we've done as part of our
overall package to actually address the learning of
the past.
3:01:39 PM
REPRESENTATIVE SEATON referred to Tab 18, page 2, regarding the
analysis of risk from Richard Rollun (ph) to CIC and others. He
read:
John and Rick,
Please see below a request from Roger. As with
previous years, our variable costs are in basically
two areas: inspection scope - reduce scope and
increase risks, inhibition levels - reduce inhibition
levels and increase risk. And then when outlining
risks it would be important to make sure that we note
all the potential risks and not just the increased
corrosion and leak risks, including commitments to
ADEC, reputation issues, workforce perception if
reducing inspections, inhibition levels and regulatory
requirements - any risks there.
REPRESENTATIVE SEATON then said it sounds like BP had fully
analyzed the impact of the budget cutting risks. The next part
of the e-mail read:
I want to see what it will take in terms of actions
and risk mitigations to those risks to reduce your LE
by $1 million by Wednesday morning .... We are in the
process of shutting down major repair work to
contribute $2 to $4 million.
REPRESENTATIVE SEATON noted that e-mail was sent in 2003. He
said that correspondence discusses a comprehensive look at risk;
not just inspections, inhibitions, and leaks. The author was
also concerned about reputation and workforce perception. He
questioned how the new analysis differs from that one and the
differences in treatment.
3:04:17 PM
MR. BROCK repeated it is disappointing to see the frustration in
the workforce. The workforce was trying to find the balance
between the right amount of expenditure to ensure the system is
safe and viable. The concern is that workers felt frustrated
that they were compromising choices. He pointed out:
Looking forward - and there's a multitude. You have a
document here that references numerous e-mails and, as
I've said, there's probably hundreds of thousands of
documents where if we take at any given point there's
a reference to some cost cutting and people's concerns
and opinions relating to that. We can go back in
these in depth, but actually I think what we need to
do is actually look forward to see what have we heard.
There's a leadership team in BP Alaska and we've been
listening really hard, not just to the concerns of our
employees here, and we have taken these on board, but
also to the findings of Bruce Allen, which we
commissioned to actually get to the root cause of
leaks here in Alaska to move beyond the mechanistic
causes to go on to the systemic issues and the
organizational issues within BP Alaska.
As such, we've listened to them. We've looked at the
recommendations and we're taking action with those
recommendations. From my perspective, I'm actually
proof. I'm the technical director. I have, at this
moment in time, over 150 technical experts reporting
in to me. That is different. The Corrosion
Management Team reports in to me. If they have
concerns about compromise of their program, then I
will address them and I'll address them independently
of the line, whether it relates to production or to
cause. My primary concern is the integrity and safety
of our operations. That's a demonstration of what's
changed.
In addition to that, our leadership team is committed
to changing some of the processes that we use to
manage and make decisions. Risk is actually much more
transparent in our business from the line up. It's
captured in a systematic way and it's reviewed on a
regular period. We look for resolutions of issues.
We look to engage the corporation's open
communications. If our employees have concerns, we
want them to be able to communicate them to senior
leadership without fear or concern as it relates to
them. We actually want to encourage people to raise
these issues so they can be addressed.
So what I'd say is we're in the early stages. I can
show you presentations but really we have to go beyond
words. I feel that we're now starting to get into
action. We've reorganized ourselves. We've put a new
leadership team in place. We're starting to address
the issues of the systemic culture and what it needs
to be to be a leading operator in Alaska for the next
30 years.
In the course of the presentation I'd like to get to
the last slide where I can talk to you more
specifically about some of the - where we're in action
and what actions we're looking to do.
3:07:12 PM
CO-CHAIR GATTO referred to Section 26, mid-page and read:
I just have a couple of concerns, the biggest thing
that we haven't pigged our sales transit line in over
15 years and I really don't know what to expect.
CO-CHAIR GATTO said that is a frightening statement. He
continued reading, as follows:
Ignition of the launcher, the launcher door seal, O-
ring, the sump pump and all of the associated piping
are unknown. We can functionally check the drain sump
system but it would probably be prudent to have all
the associated lines inspected prior to returning the
system to service as they are at a low point and have
been stagnant for years. I need to spec out and order
some replacement O-rings for the launcher doors.
CO-CHAIR GATTO pointed out the e-mail also reveals the launcher
doors hadn't been opened for 15 years.
3:08:14 PM
REPRESENTATIVE GRUENBERG asked if BP is faced with the choice of
doing preventative maintenance or setting aside clean up funds
for use in the case of a spill, whether a tax structure that
allows BP to deduct preventative maintenance costs but not clean
up costs due to negligence would encourage BP to take
preventative steps.
MR. BROCK said BP's primary focus is on safe operations. If it
needed to invest in preventative maintenance to ensure the line
is safe and integral, that is the action it would take.
REPRESENTATIVE GRUENBERG referred to an e-mail at the bottom of
Tab 5, which talks about 10 percent across-the-board cuts and
says, "...which we are most confident would allow significant
measurable corrosion damage to occur." He said that illustrates
to him that safety was not BP's priority; its policy was driven
by the bottom line.
MR. BROCK said that e-mail was sent in 1999; his statement
referred to BP's priorities today. He repeated BP's first
priority is the safety of its employees, the integrity of its
plants and the impact its operations have on the environment.
BP will take whatever actions are necessary to ensure it
operates to that standard.
3:11:43 PM
REPRESENTATIVE DAHLSTROM reiterated her concern that Mr. Brock
is not the appropriate person to ask certain questions of
because he is being asked to make policy statements for the
company. She stated the need to hear from higher level
management.
3:12:36 PM
REPRESENTATIVE SEATON reminded the committee that these e-mails
were sent when ELF was in place. Under the PPT, any spill
related costs are non-deductible while preventative maintenance
costs are deductible.
3:13:26 PM
REPRESENTATIVE ROSES felt it is important to discuss the e-
mails. He continued:
... First of all, if we address these and we know that
we have an issue over whether we have negligence or
not and we get back to dealing with the bills that are
out there to determine whether or not there's going to
be the allowance of the deduction over those costs to
replace the pipe, which is part of what this
conversation is about, I think the next question that
we would be asking them is okay, we've identified the
problem in the past. Now what are you going to do to
prevent it from happening in the future? And I think
that's what he's here to tell us but we keep
continuing to go back to trying to hammer away on what
caused the problem rather than answering the question
of what are we going to do to prevent it in the
future. So, I would hope that we could at least
finish this presentation before we keep going back to
this part.
3:14:32 PM
MR. BROCK continued his presentation:
...This was just a reference to the pipeline
surveillance that we have right now that gives us a
higher level of assurance that the system is integral
but I'll move quickly on to the current OTL
construction and then talk a little bit about the oil
transit line system itself and the replacement of that
transit line system. I'll try and capture the main
points. There [are] a lot of slides here and I'm very
happy to take any questions but first and foremost if
I could just dwell on this particular slide and spend
a little bit of time on it.
We've looked at the operation of this line. We've
looked at the state of this line through extensive UT
inspection and from smart pig inspections. Actually,
we've determined, looking at the longer life of field,
the next 50 years that now is an optimum moment, given
the condition of the line. It's been in operation for
30 years in one of the harshest operating conditions
in the world. It's operated well for those 30 years
up until 2006.
This system though, is a big system. It was made for
four times the capacity that it had previously.
Looking at the lessons we have learned, and we need to
actually redesign this system so that it actually
provides the right level of operability, the right
level of management and maintenance that we feel is
now necessary to take us through for the next 50
years.
And, as such, we're building a new system. We're not
repairing the existing system. And we're building a
new system because one, we want to size it right so we
get the right materials and we get the right
velocities in that line to mitigate against an
occurrence similar to the leaks we had in '06. In
addition, we want to put in permanent pig launching
and receiving at facilities that they would turn to
the doors and the catchers that you referred to in one
of the previous e-mails. [These are] permanent pig
launching and receiving facilities, facilities that
can be accessed and used year-round, not just in areas
when the weather is conducive to operations.
We want to put in place a new leak detection system.
We have an existing leak detection system that meets
our requirements right now but want to put in place a
new leak detection system that is more robust and want
to actually trial some new leak detection technologies
to see if we can improve what we already have.
In addition to that, it will take the building of, not
only an addition to put the pipeline but we're looking
to building 20 modules on skids that will provide the
facilities that we talked about above. And ... I
think our lines right now are 34 inches nominally
across the field, with the exception with FS 1, which
is 30 inches. These lines are going to be sized for
the full life of field, which will be 20 inches, 28,
15 and 12, respectively for it to cross the west to
the eastern side of the field.
As I said, we talked to the new system as we're going
to put it, so we talked to the pig launchers and
receivers for all sections. We've talked about
dedicated automated chemical injection in these lines
and we talked to a more sensitive, repeatable, turbine
full meter systems and a software package that is
consistent with other software systems that we use in
the Lower 48 and in the trial of the LEOS sensitive
early detection system. All of the new pipelines
[being put] in place will be in compliance with DOT
195. They will be carbon steel but they will be
fusion epoxy resin coated for external coating.
Installation of these will be in higher ... vertical
support members (VSMs) to facilitate wildlife access
around the pipelines themselves so that we've elevated
the systems where possible to avoid any clash with the
wildlife and create a better environment for that -
and also raising them higher to get away from snow
drifts or ponds associated with the lines themselves.
In addition, that will give us better access to our
corrosion coupon systems and maintenance.
3:18:26 PM
CO-CHAIR JOHNSON asked if Mr. Brock is classifying the rebuild
as maintenance or reconstruction.
MR. BROCK said he would classify it as reconstruction of a new
system with a gross cost of approximately $250 million.
CO-CHAIR JOHNSON asked if the new system would fall under the
replacement category under PPT and whether a tax deduction could
be claimed in the future under PPT. He questioned whether this
system is necessary and whether BP is building a Cadillac when
something less expensive would suffice.
MR. BROCK said he will refer those questions to BP's tax
experts. He said BP does need a new system for continued
operations at Prudhoe Bay for the next 30 years. The pipeline
systems need to be modified to handle more viscous fluids and
heavy oil on the western side of the field. He noted DOT and
ADEC have established new standards that require modifications.
3:21:11 PM
REPRESENTATIVE DAHLSTROM likened the project to residential
reconstruction in which various types of funding are sought
depending on the project and tax benefits. She said the state
may have to provide more exact definitions of such projects so
that the state and companies are using the correct terminology.
3:22:23 PM
MR. BROCK continued his presentation:
This is just an insight into one of the new pig
launchers that we've put in place. Some of the
facilities that we have right now are temperate and
adverse weather conditions are difficult for the
operators to safely operate. Our proposal is that we
will actually put - these new facilities will be
permanent, will give us year-round access and we're
using the operating groups and the operating teams to
actually help us design these so that these are
actually easier to operate and maintain and give them
year-round access to the facility.
I guess the comment here is we've had extensive
requirements from local, state and federal agencies to
allow us to have permits to go ahead and start the
construction of the new system. As such, we've had
great cooperation from the agencies as such and I just
wanted to recognize that as seeing it firsthand.
3:23:15 PM
CO-CHAIR GATTO referred to page 31, and said two points are
worth noting. At the top, it says, "Prior to the arrival of
Tony Brock and the creation of the Technical Directorate, there
was no formal process for assessing risk." Further down the
page, it reads, "Risk register is developed under Technical
Director Tony Brock." He pointed out Mr. Brock is on the "good
page."
3:24:01 PM
MR. BROCK continued with his presentation:
...This is really an overview of the leak detection
system and we're putting in new hardware, new reliable
systems. We're putting in a new software package.
These are, what we believe, are the best available
technologies within the industry. The industry has
moved on quite a bit. These are systems that will be
in place and reliable for 30, 40 years. The lower
reference is actually to a pretty unique technology.
It's a LEOS system. It's a system that is sensitive
to very small leaks. I don't know if you can recall
back to the eastern operating area, but we actually
had pinhole leaks of drops of oil that were coming
through and, as such, the leak detection system - it
went below the radar of that type of system. So we're
actually trialing this new technology to determine if
this more sensitive technology is applicable. It is
the first time that it's been deployed in an Arctic
environment in this circumstance. We have a similar
system in our Northstar transit line but that's buried
in the seabed. This is exposed to a much harsher
climate and greater swings in temperature. This is an
interesting trial for us. It will take us a couple of
years to prove it through winter and summer operations
but I think it's a unique system and I look forward to
seeing what the findings are on that.
On the transit line system itself, we had an extensive
construction season through January and April. We've
constructed two sections of the pipe. It has not been
put in service yet. It needs modules to be
constructed to allow us to do that. The overall
replacement of the 16-mile sections will be completed
and we hope to commission those in the fourth quarter
of 2008.
This is really just some of the major project
accomplishments and this, to date, took considerable
effort by BP and it was driven, in part, by the fact
that - one is the existing system is we are carrying
out extensive tests and inspections at the moment to
ensure integrity of that system. We do believe that
it is an old system and we do want to put a new system
in place. We put a lot of engineering effort into
designing a new system and starting the construction
and the project, so we made great progress on that
but, as I said, the 20-inch and 18-inch sections are
installed and I'll reference those and then - a follow
up slide.
The next series of photographs are really - I'm not
going to go into detail, they really give you an idea
of the scope. This is really just an example of just
a piece of insulated pipe at the gathering center 2-1.
These are the VSMs I spoke to. I'm really just going
to move through these unless someone has a specific
question but it's just an illustration.
This is the welding of the pipe itself and these
welds, when we put them in place, actually the
procedure and the welding itself is checked thoroughly
not only by BP experts but by Houston construction
experts and Department of Transportation experts.
This is just, again, sandblasting to allow us to coat
the weld after the weld's been completed. This is an
example of the techniques we use for weld inspection.
This is the follow up insulation and covering of these
welds. I'm really trying to demonstrate here that
we're extremely thorough in the construction and the
quality assurance process associated with these
pipelines.
This is just an illustration of the pipe being lifted
into position. We really had phenomenal performance
from the team working on this. The majority of the
staff came out of the Fairbanks union holds. A lot of
the extra workers came up from Anchorage and Fairbanks
to help us in this construction operation. This is
just an illustration of the line to Flow Station 1.
This is ... an illustration. The yellow sections show
you the sections of pipeline that we have currently
constructed and are in place.
This is one of the final slides to give you an
overview of the contracting parties that have come
into play here. The highlighted ones are actually
Alaskan businesses that have supported this operation.
You can see an extensive number of people in that and
the companies in that. And we had, working on the
pipeline itself, something in the order of 300 to 350
at peak working specifically on this pipeline
installation and that will carry through and some
appeared as we start to look at construction of pods
and modules.
This is the final slide, ... we're actually just
really starting to address some of the queries that
the committee had. These series of leaks actually
have - were a surprise to us. We pride ourselves in
being a lead operator in Alaska and we have a huge
role to play. We've had a huge role to play in the
last 30 years and we want to be here for the next 50
years and be seen by the state as a respected and
trusted operator. We want to be a lead operator in
Alaska. That's our goal and it's a priority of the
leadership team that's in place and (indisc.) here
today. Events of 2006 show that we've got some things
to learn and we need to change how we operate and
we're committed to doing that. In the process of
reacting to these spills, we've done a lot of
listening, a lot of learning. We know that there are
corrosion gaps that we need to address and we know we
need to improve our risk management. If you look at
our overall infrastructure and ensure integrity of
that entire system and we have the balance right with
cost management. We invest on our facilities and get
the balance right between safety integrity and the
business. We need to get our organization right so
that the organization functions and the issues that
are raised are addressed in a timely manner. We need
to pay attention to communication of culture. We've
got a series of documents here that relate to the
frustration of our employees. That's not acceptable.
We need to create the right culture and environment
where people can openly address their issues and voice
their concerns and they need to be addressed in a
timely manner.
So what we're focused on right now is we've talked
about organizational changes. We've got the technical
director but also in the greater Prudhoe Bay
organization we've added a number of positions to give
us greater supervisory control and a better span of
control. We've put area managers in place to address
some of the issues about a scale as complex and as big
as greater Prudhoe Bay.
We've got an extensive program for workforce renewal.
[We recruited] 50 technicians last year and we're
bringing in another 40 this year and we'll look beyond
that to ensure that we have the right workforce in
place going forward.
We're expanding our communications to encourage
broader open communications within our working
environment. And [indisc.] the place of addressing
the cultural issues that prevailed to ensure that we
have one BP that's trusted and respected to deliver
safe, reliable operations.
In the plant we're taking immediate actions to manage
our oil transit lines. We've modified our operating
practices. We've modified some of our maintenance
practices. We have this greater control and
assurance. We're carrying out comprehensive
inspections. In that we've actually commissioned a
new corrosion management strategy and in that strategy
we're looking at short term needs to address any
specific risks that are out there in our facilities.
We're replacing our oil transit line systems in
greater Prudhoe Bay and we've actually brought a team
in under Gary Bugel (ph), to set up a renewal projects
team and that team will be dedicated to looking at the
longer term renewal requirements of the greater
Prudhoe Bay facilities and the North Slope in its
entirety.
We're introducing new standard technical practices
that are BP practices in the technical directive to
ensure that these standards are enforced. We've got a
process. We're looking to comply with new regulations
with the Department of Transportation but also the
local ADEC offices and also the regulatory office
Process Safety and Integrity Management. As we talked
to, we've got a new, improved risk management process.
We've got a new corrosion management strategy. We're
looking at putting in place rigorous performance
measures so that we can actually monitor integrity
management across our facilities, not only in
integrity management but also in corrosion so that I
get to see, on a regular basis, are we conducting the
inspections we said we were going to conduct. Are we
acting on the result of those inspections where they
raised concerns?
So our overall goals are to establish trust from the
public, be an industry leader in Alaska, transform our
culture to one that's going to prevail for 50 years,
and provide sustainable performance through a new
operations management system.
3:33:33 PM
CO-CHAIR GATTO thanked Mr. Brock.
3:33:48 PM
REPRESENTATIVE SEATON requested a written response from BP
regarding whether BP has billed the other Prudhoe Bay partners
for the repair and maintenance work required by the shut-down.
He commented that one of the criteria under the PPT is that if
the partners decline to pay for certain items, those items would
not be eligible for a state [deduction]. It was his
understanding, as of a month ago, that no billing had been sent
to the other partners. He pointed out the legislature needs to
know whether it needs to create another way to address the
system, possibly by improper maintenance criteria, or whether
that is covered under existing law. He then asked whether BP
employees have received any communications telling them not to
put their concerns in e-mail messages.
MR. BROCK replied none whatsoever and, in fact, employees have
been encouraged to voice their concerns and pursue them until
resolved.
3:37:24 PM
CO-CHAIR GATTO clarified Representative Seaton questioned
whether employee concerns are in writing.
MR. BROCK said he was clarifying that BP employees have not been
told to not put their concerns in writing.
3:37:44 PM
CO-CHAIR GATTO said the legislature is working with the federal
government to obtain as much information as possible. He asked
Ms. Slemons of the PSIO to give her presentation.
3:38:14 PM
REPRESENTATIVE GRUENBERG said it is his understanding that
various state officials gave BP the "okay" to not perform
maintenance and inspections. He asked Mr. Brock if he could
comment on how that affected the company.
MR. BROCK said he can't comment on that specific example but
said BP is committed to working with state regulators,
particularly with the new PSIO office to ensure that appropriate
standards are in place and that BP adheres to those standards.
REPRESENTATIVE GRUENBERG asked if, in the future, BP knows an
action should be taken but a state official says that action is
unnecessary, BP should be let off of the hook.
MR. BROCK thought BP would operate to the higher standard.
REPRESENTATIVE GRUENBERG asked if that is a new policy.
MR. BROCK said that has always been BP's policy.
3:40:22 PM
The committee took an at-ease from 3:41 p.m. to 3:48 p.m.
3:48:16 PM
CO-CHAIR GATTO called the meeting back to order and asked Ms.
Slemons to brief the committee.
3:48:23 PM
JONNE SLEMONS, Coordinator, Petroleum Systems Integrity Office
(PSIO), Division of Oil & Gas, Department of Natural Resources,
told members she was not expecting to testify today. She
offered to answer questions or address a particular topic if
requested.
3:48:50 PM
CO-CHAIR GATTO referred to a letter and read:
Questions:
What did BP tell the Alaska Department of
Environmental Conservation in order to justify its
request that ADEC waive the pigging requirement in the
May 29, '02 compliance order by consent?
3:49:31 PM
MS. SLEMONS told members on May 16, 2007 the Congressional
Committee on Energy and Commerce and Subcommittee on Oversight
Investigations requested that the State of Alaska respond at a
follow up hearing to an initial hearing held immediately after
the partial shutdown of the Prudhoe Bay Unit. She thought the
initial hearing was held on May 15,2006, and that the
commissioner of ADEC testified at that hearing. She testified
at the May 16, 2007, hearing along with a representative of the
Pipeline and Hazardous Materials Safety Administration from the
U.S. Department of Transportation, a representative from the
Chemical Safety Board, and a representative from the
Occupational Safety and Health Administration. The committees
were reviewing the Texas City refinery explosion and whether any
similarities to the Prudhoe Bay spill existed. The two
questions in the letter Co-Chair Gatto referenced were asked of
her at the hearing. She answered them to a degree so the
committee requested more detailed information. She noted that
letter was sent to the congressional committee members with a
list of enclosures over one page long; House Resources Standing
Committee members do not have those enclosures.
REPRESENTATIVE GRUENBERG interrupted and inquired as to what
letter Co-Chair Gatto was referring.
3:52:35 PM
MS. SLEMONS noted that she provided Co-Chair Gatto with her copy
of the letter [to congressional committee members]. She then
told members, regarding the first question about what BP told
ADEC about the pigging requirement, she does not work for ADEC
and that Mr. Dietrick may have more information to offer. She
continued:
In our letter, which was, of course, coordinated with
the Department of Environmental Conservation [DEC] and
others in the state, we referenced various
documentation that outlined a sequence of
communications from BP that began several years
earlier, or at least one year earlier with their
indicating that there was significant sediment in the
lines, to the point that the testing of the leak
detection system, which DEC was requesting -
requiring, would be compromised. Let's remember too
that DEC's focus was on insulation and proper
operation of a leak detection system. Their primary
focus at that time was not sediment or pigging or
anything of the sort. So the pigging requirement was
included in their consent order as a prerequisite to
ensuring that the leak detection system could be
properly tested and operate properly.
So, BP had told them that there was so much sediment
in the line that they did not feel that the lead
detection system could be properly tested and
operated. So DEC included the pigging requirement in
the consent order to solve that problem. After the
consent order was issued, BP came back to DEC and said
in fact, we were mistaken, there's not nearly as much
sediment in those lines as we thought originally and
there's probably a half inch of e-mail documentation
that captures the internal discussions within BP on
that issue. So they told DEC that the sediment wasn't
nearly the problem that they originally thought that
it was. In addition, they told DEC that they had
installed pig launching and receiving facilities,
adequate to allow pigging at any time in the future.
This was important information for DEC to know because
it could have eliminated in their minds any concern
that they might have had remaining about what low
sediment levels they believed were still in those
lines.
CO-CHAIR GATTO asked whether DEC requested the data to back up
BP's statements about the sediment levels.
MS. SLEMONS said she was not sure what back up information was
provided to DEC. She offered to look into that. She then
continued her response, as follows:
So, that's what BP told DEC and that was - they then
followed that up with a request - a written request,
that the pigging requirement be waived and DEC agreed
that that was appropriate and waived the pigging
requirement in the consent order.
CO-CHAIR GATTO remarked that BP told DEC it overestimated the
problem so wanted to be excused from the requirement and DEC
agreed.
MS. SLEMONS said that is correct but, regarding BP's
overestimation of the problem, BP also said it had installed the
pig launchers and receivers, which would allow them to pig at
any time and would address the remaining sediment levels. With
that information, DEC agreed.
3:56:37 PM
REPRESENTATIVE SEATON asked if the pigging requirement was put
in place for testing and leak detection purposes. Initially,
DEC was told there was too much sediment to pig, but was later
told the sediment level would not make the leak detection system
inoperable so, because DEC's focus was the leak detection
system, it waived the pigging requirement.
3:57:27 PM
MS. SLEMONS said that is correct but again added that DEC was
also told pigging facilities were now available and pigging
could occur any time in the future and took that into account.
3:57:49 PM
REPRESENTATIVE GRUENBERG asked Ms. Slemons to describe the
initial requirement.
3:58:12 PM
MS. SLEMONS noted a copy of the consent order was in members'
packets and that it contains several requirements for certain
actions by certain dates.
REPRESENTATIVE GRUENBERG asked if it required that a certain
amount of pigging be done.
MS. SLEMONS said it did.
3:58:29 PM
REPRESENTATIVE GRUENBERG asked if DEC was told the pigging could
not be done because of too much sediment.
MS. SLEMONS said DEC was originally told that there was a great
deal of sediment in the line, which is why DEC required the
pigging.
REPRESENTATIVE GRUENBERG said DEC decided the pigging was
unnecessary when the amount of sediment was found to be lower
than estimated.
MS. SLEMONS replied, "In conjunction with the information that
pigging launchers and receivers had been installed, that pigging
could be conducted at any time in the future, DEC agreed that it
was not necessary for purposes of testing the leak detection
system."
REPRESENTATIVE GRUENBERG surmised that BP never followed through
with the pigging.
MS. SLEMONS said that appears to be the case.
REPRESENTATIVE GRUENBERG asked why DEC did not take the
additional step of ensuring that at least a minimal level of
pigging was done.
MS. SLEMONS reminded members that prior to 2006, people were
ignorant of the regulatory gap on the North Slope on the OTL
lines [and], in fact, were jurisdictional for the Office of
Pipeline Safety and the U.S. Department of Transportation. She
continued:
DEC's authorities would extend to those lines only for
purposes of environmental protection of air quality
and land and so forth and so they did not have a
requirement to ensure system integrity of the lines in
their ordinary course of business. U.S. DOT would
have had that authority. Now the gap arises in that
there were some exemptions within the federal
regulations that allowed those lines to fall through a
gap - create the gap, if you will, in that lines that
were in remote areas of very low populations were
allowed to be exempted, as were - there were a couple
of exemptions as I understand it and another one was
that - let' see, the population and the remoteness
were the two that these lines were ...
4:00:59 PM
REPRESENTATIVE GRUENBERG asked if BP was aware of the gap in
regulatory authority at the time DEC waived the pigging
requirement. He stated, "Because it would seem to me if they
were involved in regulating this, then they must have thought
they had required - they had the authority."
4:01:16 PM
MS. SLEMONS said it is her understanding that DEC believed that
U.S. DOT had and was exercising regulatory jurisdiction and that
both parties were unaware that the regulation was not be
properly exercised.
REPRESENTATIVE GRUENBERG asked if DEC was de facto regulating up
to that point.
MS. SLEMONS replied DEC was regulating pipelines from its
perspective as an environmental safety agency, to her
understanding. DEC was implementing its mission via oversight
of the leak detection systems. Therefore, the consent order by
decree focused on that system. The DEC was not so much
interested in overall operation and regulation; it was
interested in ensuring that any breach of integrity was
immediately identified and remedied.
REPRESENTATIVE GRUENBERG asked if the legal gap has been
remedied.
MS. SLEMONS answered that it has, to her understanding.
Congress passed the Pipes Act in late 2006, which expands the
Office of Pipeline Safety's authority and puts the lines in
question within the jurisdiction of the Pipeline and Hazardous
Materials Safety Administration and that agency is actively
pursuing regulatory authority over those lines now. When the
first bill was enacted in 2006, DEC was in the process of
promulgating regulations to bring flow lines under its
authority. She believes all regulatory gaps have been
addressed, however one of the primary tasks identified in
Administrative Order 234, which established the Petroleum
Systems and Integrity Office, requires that PSIO do a statutory
and regulatory gap analysis to ensure that any remaining gaps on
state lands regarding oil and gas are addressed. PSIO is
currently doing a gap analysis.
REPRESENTATIVE GRUENBERG asked if a copy of that analysis will
be presented to the legislature.
MS. SLEMONS said she would be happy to provide the legislature
with a copy and that she has committed to make annual reports to
the legislature on the PSIO's activities and findings.
CO-CHAIR GATTO asked whether DEC and the PSIO believe the one
percent threshold is adequate. He said the spill was detected
by a workman who smelled oil and the amount discovered on the
ground was the equivalent of six or seven days of leaking. He
noted a significant amount of oil leaked before it was detected.
MS. SLEMONS deferred that question to Mr. Dietrick of DEC. She
said DEC has been looking at its requirements for the detection
systems and the best available technology.
REPRESENTATIVE GRUENBERG asked if federal law preempts state law
or whether they have concurrent jurisdiction.
MS. SLEMONS said she was uncertain but believed federal law
preempts. She drew members' attention to the fact that the
Pipeline and Hazardous Material Safety Administration and DNR
have signed a letter of intent to cooperate in sharing
information and findings to prevent miscommunication.
REPRESENTATIVE GRUENBERG asked that Co-Chair Gatto request a
written response to that question.
REPRESENTATIVE ROSES asked whether BP ever actually made a
determination that the amount of sediment was lower than
expected. He asked:
Wasn't it BP stating that they had an excessive amount
and then therefore, it was stated that a pig needed to
be used to clean it up so that the system could be
tested properly and then they later on came back and
said oh no, there wasn't as much as we said there was.
So, the only really determination we have is their
first statement and their second statement and no
proof of anything in between.
MS. SLEMONS pointed out that BP reported to DEC through the
annually required charter agreement report that routine
maintenance pigging was part of BP's program for its OTL lines.
Without jurisdictional authority, DEC would have assumed that
regular maintenance pigging was being done.
REPRESENTATIVE ROSES asked if that kind of a discrepancy occurs
in the future, something will be done to verify the correct
statement.
MS. SLEMONS said it will; the agencies are trying to learn from
mistakes.
CO-CHAIR GATTO asked if a camera travels through the pipeline to
measure sediment levels.
MS. SLEMONS said the smart pigs collect and communicate data.
When a smart pig emerges from the pipe, the amount of
information it provides about the condition of the pipe is very
detailed.
CO-CHAIR GATTO asked, "I imagine they have arms on springs and
if they don't quite reach the end of the pipe, now they're on a
bunch of rocks that get all measured - not measured - recorded
so that at the end of the pipe you'll say at Section 142D we
certainly seem to have an inch and a half of sediment?"
MS. SLEMONS said it is her understanding that a smart pig can
report a location and other information about obstacles or
obstructions.
REPRESENTATIVE GRUENBERG asked if BP made any factually
incorrect statements in the key correspondence about pigging.
MS. SLEMONS said it is difficult to know exactly what
information was available to the people making the statements.
However, the correspondence does seem to imply that the pigging
activity was either planned and never carried out or
misrepresented. She said it is impossible to say whether
purposeful misstatements were made from the documentation she
has seen.
REPRESENTATIVE GRUENBERG pointed out the statutes prohibit false
statements. He questioned whether those statutes adequately
cover this type of correspondence and whether the departments'
procedures follow the statutes. He wants assurance that the
factual information provided in future correspondence can be
relied upon and, if not, legal consequences will ensue. He
asked Co-Chair Gatto to request an answer to that question from
the PSIO.
CO-CHAIR GATTO asked if Representative Gruenberg is asking
whether the penalty should be a felony.
REPRESENTATIVE GRUENBERG said the consequence could be a felony
or a misdemeanor. Under statute, false swearing is a
misdemeanor. He noted his questions are whether a situation
like this is covered by statute and whether the departments'
procedures follow the statutory requirement so that if factual
information is not provided, the Department of Law can take
action. Then, the legislature could determine whether the
penalties are adequate.
CO-CHAIR GATTO remarked, "And I could see the problem as a lot,
there's less, and neither term is quantifiable if, indeed, those
were the terms that were sent as part of the correspondence that
was involved in canceling the operations."
REPRESENTATIVE GRUENBERG said in matters of this type, it may be
a matter of crafting the statutes with mens rea, so that
criminal intent is not required; reckless behavior could be
penalized. He said his concern is whether the legislature needs
to take a look at whether the statutes are properly crafted.
MS. SLEMONS related that DOL is looking closely at the 2006
events on the Prudhoe Bay unit. She felt comfortable that DOL's
findings will provide a detailed answer to Representative
Gruenberg's question.
REPRESENTATIVE SEATON asked Ms. Slemons if she is comfortable
with the sufficiency of the changes proposed by BP.
MS. SLEMONS noted that BP is implementing far reaching
organizational changes, largely in response to requirements
placed on it by the Office of Pipeline Safety. She believes BP
is sincere. She noted her personal concern is that "a ship the
size of BP doesn't turn on a dime." It is difficult to change
an organization's culture. She said BP has been responsive to
the different agencies; she is hopeful BP is successful.
REPRESENTATIVE SEATON asked if the Office of Pipeline Safety
oversees the modules and all other infrastructure on the Slope.
He said he is concerned because the fire prevention and control
offices have lost people with knowledge of very intricate
systems.
4:18:54 PM
MS. SLEMONS told members:
... The Office of Pipeline Safety, as per its name,
looks at pipelines and their jurisdiction do still
have some limits. The letter of intent benefits not
only the petroleum systems integrity office at DNR by
being able to look at the federal information that
they have, it also benefits them at being able to look
at what we gather and find in the upstream for
[indisc.] fields. In fact, facilities themselves,
such as production centers, modules, gas processing
facilities and those kinds of things, are one of those
things that have escaped regulatory oversight, I
believe, for quite some time other than elements like
labor, [Occupational Safety and Health Administration]
OSHA, fire protection, that kind of thing. It is one
of the missions of the PSIO to fill those gaps and we
will be looking at facilities, not just pipelines, in
the system integrity plans that we will be requiring
from the unit [indisc.]. We'll be assessing the
technical sufficiency of those plans and then we will
be performing on-site assessments to ensure that
operators are complying with the system integrity
plans that are established. So, in short, to answer
your question, yes, we intend to look at facilities as
well as pipelines.
REPRESENTATIVE SEATON expressed concern about the staff cuts in
the upgraded systems because, to his understanding, proper
training to operate those systems has not occurred.
4:20:50 PM
MR. FINEBERG commended Co-Chair Gatto for the committee's
efforts.
4:21:29 PM
MS. SLEMONS told members it is her hope that the Petroleum
Systems Integrity Office will be reporting its findings to the
legislature routinely. She appreciates the committee's interest
in its work.
4:22:02 PM
CO-CHAIR GATTO asked how the PSIO came about.
MS. SLEMONS replied:
Mr. Chairman, it's had two life times already in its
short history. It was originally formed under the
Murkowski Administration under a different name. You
may remember it as the Lease Monitoring, Engineering
and Integrity Coordinator's Office - LMEICO. That
concept, while the goal and the mission remain the
same, the administrative structure and so forth have
been changed pretty significantly. Under Governor
Palin, it is the Petroleum Systems Integrity Office
and that's where we're going forward with it.
4:22:48 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 4:22 p.m.
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