Legislature(2001 - 2002)
11/07/2001 10:00 AM House NGP
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
November 7, 2001
10:00 a.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Johnny Ellis
Senator Donald Olson
SENATE MEMBERS ABSENT
Senator Rick Halford
Senator Pete Kelly
HOUSE MEMBERS PRESENT
Representative Joe Green, Vice Chair
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate
HOUSE MEMBERS ABSENT
Representative Brian Porter
Representative Reggie Joule
OTHER LEGISLATORS PRESENT
Representative Jim Whitaker
COMMITTEE CALENDAR
10:00 - 12:00 Washington D.C. update
· John Katz, Director, State/Federal Relations and Special Counsel
to the Governor
· 10:30 - 11:00 Duncan Smith and C.J. Zane, Legislative Advisors
with Dyer, Ellis and Joseph
· 11:00 - 12:00 Updated on Senator Murkowski's energy legislation
12:00 - 1:00 Lunch
1:00 - 3:45 Department of Revenue
· 1:00 - 3:00 Roger Marks, Economist, Department of Revenue
· 3:00 - 3:15 Ed Small, Cambridge Energy Research Associates
· 3:15 - 3:45 Larry Persily, Deputy Commissioner, Joint Pipeline
Office
Bill Britt, State Gas Pipeline Coordinator
· 4:15 - 4:45 U.S. Mineral Management Service
John Goll, Regional Director
John Larson, Geologist
PREVIOUS MEETINGS
July 17 & 18, August 14 & 15, September 19,
ACTION NARRATIVE
TAPE 01-21, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Joint Senate and House Natural
Gas Pipelines Committee meeting to order at 10:00 a.m.
MR. JOHN WILLIAMS, Mayor of Kenai, commented briefly, but due to
transmission difficulties, his testimony is not audible on the
tape.
CHAIRMAN TORGERSON recapped the Mayor's comments saying that the
main emphasis of the meeting was to spend a substantial amount of
time on the resources that are in Cook Inlet, existing industry and
other industry that has looked at Cook Inlet for some sort of
either supplying the resource or building their own industry.
This is very important to this community, since part of our
deliberations is how we can give them gas, if and when we need
gas, to the Southcentral Basin. We've heard some exciting news
about discoveries that have been bylines in the press. We hope
to elevate those to guide us over the next couple of days to
see what actually might be there and what we can count on for
additional resources.
Mr. John Katz, Director, State/Federal Relations and Special
Counsel to the Governor, testified:
Let me start by briefly describing the public policy arena
here in terms of five specific factors.
1. In terms of national energy legislation, I think it is
pretty clear now that we will not see that legislation on the
Senate floor before the Thanksgiving recess. Majority Leader,
Senator Daschle, has indicated five priorities for Senate
action in the immediate future and energy legislation is not
one of them. It seems increasingly likely, though not certain,
that there will be a session of the Senate of the period
between Thanksgiving and Christmas. If that is the case, it is
possible that energy legislation will be introduced and
perhaps brought to the Senate floor for debate and voting.
2. The second factor that I wanted to bring to your attention
is that in a very rare parliamentary maneuver, the Majority
Leader of the Senate has basically brought the development of
energy legislation under his personal aegis. In essence, he
has instructed the chairmen of the various committees that
have jurisdiction over energy issues to make recommendations
to him. He and his staff have taken the responsibility for
putting those various provisions into final form for debate on
the Senate floor. In the case of the natural gas pipeline, the
Senate Energy Committee has discontinued its markup of energy
legislation. Those markups began in August. Now the chairman
of the committee, Senator Bingaman, and his staff are in the
process of developing recommendations to provide to the
majority leader. We've been told that their goal is to make
those recommendations to the Majority Leader in the form of
legislative language by this Friday. I'll come back to that
later.
3. The third point that I wanted to bring to your attention is
that the Republicans in the Senate have grown increasingly
impatient with the pace of energy legislation in the Senate
and at various times they have indicated their intention to
develop an alternative bill of their own to bring to the
Senate floor. That effort has not been totally successful so
far. It has foundered perhaps on provisions relating to
ethanol and to electrical energy restructuring, not anything
that relates specifically to the natural gas pipeline. Another
possibility in this scenario might be for the Republicans to
take the House bill, HR 4, and propose that as amendments on
the Senate floor to other fast moving legislative vehicles. As
many of you will remember, HR 4 contains a specific
prohibition against the over-the-top route for the natural gas
pipeline and also includes provisions, which would authorize
oil and gas exploration and development in the Coastal Plain
of the Arctic National Wildlife Refuge.
Another factor that I think is quite relevant in this period
is the relationship between the natural gas pipeline and ANWR,
itself. I think it is safe to say that in the Senate, there's
broad bi-partisan support for the proposition of developing
and commercializing Alaska North Slope natural gas. There are
key questions concerning the legislation to accomplish that
purpose, but the basic proposition is not in question.
However, there are members of the Senate, including the
Majority Leader, and the Chairman of the Senate Energy
Committee who would like in essence to remove ANWR from the
Senate debate and substitute in lieu thereof the natural gas
provisions, perhaps some provisions relating to tax incentives
for heavy oil, treatment of stripper wells, and other
provisions relating to oil and gas, but not ANWR. The Senate
Majority Leader in floor statements and in press briefings has
indicated his strong support for the natural gas pipeline as a
hydrocarbon alternative along with other provisions for ANWR.
He talks about the jobs that would be created with the gas
line and other advantages to the country. Conversely, there
are other members of the Senate who want to make sure that
that linkage doesn't occur and the parliamentary scenarios
that they envision would ensure that the gas line and ANWR are
considered separately and are both voted on in the Senate.
The final factor, which is relevant to the specifics of the
natural gas pipeline is the position of the federal
administration. I think it's safe to say that the formal
position of the federal administration is to be project and
route neutral and not to propose legislation relating to the
gas line at this time. I believe that there's also a great
deference to the political leadership of Alaska, the
Congressional delegation, the Governor, the state legislature
in terms of what we think and how that is factored in by the
President and Vice President. They also support the
commercialization of North Slope natural gas, but their
principle focus, I think is safe to say, has been on ANWR.
There are, I believe, three pivots in the Senate - Senator
Murkowski, Senator Bingaman, and Senator Daschle, as we
consider natural gas pipeline legislation. There are several
factors, I think to look at, as those parties consider the
issue. The first is whether to include the producers' enabling
legislation in the energy bill, itself. I won't elaborate on
that legislation now unless you want me to since we've
discussed it previously or the alternative to rely on the
ANGTA regime, which was enacted and decided in 1976 and 1977
by Congress and the President.
Another factor of chief determinant is whether the gas
pipeline should be considered within the context of national
energy legislation or perhaps as free-standing legislation. A
fourth factor is should that legislation be route and project
neutral or should it prohibit a particular route, for example,
the over-the-top route. Finally, another very important
determinant is whether there will be tax incentives in the
final package in order to promote commercialization of North
Slope gas generally or to influence the choice of route by
perhaps providing tax incentives to only one route and not to
others. You've just heard the chairman's comments on Senator
Murkowski's work with respect to the gas pipeline and I would
not presume to add very much to that description. Senator
Murkowski is clearly looking at the advisability of
introducing legislation and, if so, what the components of
that legislation should be, whether it should rely on the
matrix of the enabling legislation or in the alternative on
the ANGTA regime. I think it's best to leave that at that
junction pending anything further from Senator Murkowski or
his staff that they would want to share with the committee
later on.
The second determinant that I mentioned earlier, is Senator
Bingaman. Even though markups are no longer occurring on
energy legislation in the Senate Energy Committee, he and his
staff are working very diligently on several different
provisions including provisions concerning the natural gas
pipeline and I believe it is their goal to make their
recommendations to the Majority Leader at the end of this
week, if that's at all possible.
My guess, and it is only a guess, and I may be contradicted by
what actually comes out later, is that that legislation will
rely very heavily on the producers' enabling legislation and
that it will at this juncture stipulate a particular route. I
believe that Chairman Bingaman is also very interested in
developing some economic incentives or tax incentives to
commercialize North Slope gas. I know that he and his staff
are looking at a spectrum of possibilities which include
accelerated depreciation on construction; secondly, reducing
the commodity risk by establishing some sort of floor price
and; third, even the possibility of an investment tax credit,
but those matters are not within the jurisdiction of the
Senate Energy Committee. They are, in fact, province of the
Senate Finance Committee, Senator Baucus' Committee. It is by
no means clear at this point whether there will be any of
these tax incentives in the Majority Leader's final bill and,
if so, what provisions they might be.
The third pivot is the Majority Leader. He is pivotal
obviously in two respects. One is within broad parameters, he
will control the Senate floor; he will control the timing of
Senate consideration. He will decide when to introduce
legislation and then later when the debate will occur. Of
course, those decisions could be overridden in various
parliamentary ways on the Senate floor, but it is not usual
that that would occur.
The second place where he will be very important is on the
substance of natural gas legislation, itself. In various
contexts, he has indicated his strong preference for the
southern route. He has not yet, to my knowledge, indicated
publicly whether he would support the ANGTA regime or the
producers' enabling legislation, but he is clearly
knowledgeable on this subject and, as I indicated earlier,
would actually like to substitute the gas line and some other
oil and gas provisions for ANWR. He wants to give a broad
deference to his various committee chairmen as they formulate
different elements of the energy package, but he has reserved
to himself some of the final decisions on what that package
will look like. There are other members of the Senate who have
expressed an interest in natural gas legislation, some for the
enabling legislation and some for the ANGTA regime, and
specifically for the southern route and they are part of the
dialogue now with Senator Bingaman and Senator Daschle about
how this will ultimately proceed.
In terms of the various advocates in the process who are
treating the Senate on the gas pipeline issue I think you're
going to be hearing from various proponents and so I will only
briefly for the purpose of this testimony characterize what I
understand to be the position of the parties as they continue
to advocate those positions. The North Slope natural gas
producers have remained very strong advocates for their
enabling legislation, which they allege to be route and
project neutral and simply to present an alternative to the
ANGTA regime. They have also indicated that that legislation
is absolutely crucial in their deliberations about whether to
go forward in the effort to commercialize North Slope natural
gas.
Foothills and some of the other previous partners in the
Foothills project have indicated their strong preference for
the ANGTA regime perhaps as amended by some legislative
language that they proposed, which would focus on the
environmental process and confirm the decisions made by the
executive branch in 1977. They believe that that legislation
is the quickest way to commercialize North Slope gas and to
generate jobs and they also feel that if there's any
alternative to that, the calendar may then become free to
adopt an alternative to the ANGTA regime and the international
agreements that form part of that regime. The State
Administration has continued to advocate the Governor's 10
principles as described in his testimony to the Senate Energy
Committee in October. We continue to place heavy emphasis on
the ANGTA regime and particularly on the southern route. I
think in those respects our advocacy has been quite similar to
that of Chairman Torgerson and the principles that the Joint
Committee has adopted. We've also emphasized the other
principles in that package or policy. Recently, we have felt
that for the most part our position and the position of the
legislature are well understood by members of the Senate and
so the Governor has shifted some of our focus to the
commercial world. I should mention that when the Governor was
here we met with many members of the Senate Energy Committee
to express our support for the pipeline for the southern route
and also for ANWR. We've since followed up on that.
In terms of the commercial situation you will hear in greater
detail from the pipeline companies, themselves, but I think
they would tell you that they are on track to reconstitute
their partnership and to deal with the very important issue of
the contingent liability, the $4.2 billion matter that we've
discussed previously and that sometime in the not too distant
future they will be prepared to discuss more formally with the
producers how they might jointly proceed, but I'll leave those
commercial presentations to others.
Finally, I would say that I think I've accurately described
what the situation is today, but it's very fluid. It could be
influenced by any number of permutations and combinations in
the Senate, itself, and it also could be influenced by
external events relating to supply price and possible supply
dislocations.
10:24
REPRESENTATIVE GREEEN asked if the switch in leadership was good
news or bad news in terms of getting this issue to the floor and
not be bottled up in committee.
MR. KATZ replied that was a good question and that this is only the
second time that anyone could recall that this parliamentary
maneuver has occurred. He thought it was a set back. He said that
Senator Daschle is on record as supporting the southern route and
he thought Senator Bingaman was inclined toward a more route
neutral approach. He didn't know how that would be resolved. Also,
the Majority Leader felt that the pace of activity in that
committee and other committees with relevant jurisdiction was quite
slow and maybe the best place to speed it up would be in his office
inviting all the relevant committee chairmen to submit their
recommendations to him. "It's not a particularly democratic process
at this point, but I think it is an effort to get a comprehensive
bill done.
MR. KATZ said that it was a set back for everyone who supports
opening ANWR, because they thought they had the votes in the Energy
Committee and the Majority Leader who opposes ANWR did not want to
see a bill come out of that committee with ANWR in it.
He guessed that there wasn't sufficient time in this session of
Congress to both introduce a bill and debate it. He thought the
best that would happen would be introducing a bill that would be
debated some time next year unless the Senate adopts the House
bill, which is highly unlikely, and then there would have to be a
conference committee. There are a lot of factors that bear on the
answer to this question.
CHAIRMAN TORGERSON asked if he had heard anything from the
environmental community about routes.
MR. KATZ replied that they had commented, but not with great vigor,
yet. They are very much into the ANWR gas pipeline dynamic. They
object to the northern route, some support the southern route and
some simply don't oppose it. He thought it would help the
democratic majority if they voiced their opinions.
CHAIRMAN TORGERSON said he asked that question because the
producers' legislation mirrors many provisions in ANGTA. One is the
limited judicial review process for challenges, which the
environmental community is not very enthusiastic about. "…is it
just something that we don't have a bill in front of us where
they're holding back in the weeds until they see something actually
in writing."
MR. KATZ said it might be more of the later and he hadn't seen them
get to the level of detail that is suggested by his question.
For the most part they're focusing on ANWR to the extent that
they're focusing mainly on the choice of route. Although, when
the details of the legislation come out, I would not be at all
surprised to see them focus on the expedited judicial review
issue. But it is in ANGTA and it is in enabling legislation.
It's a principle that I think a lot of people endorse at this
point.
CHAIRMAN TORGERSON asked where the legislation was that the
Governor said he was going to have Mr. Katz draft and introduce to
Congress as a guideline.
MR. KATZ replied that it is drafted, but it hadn't been given to
anyone. He said it wouldn't be productive for them to propose
actual legislative language at this point. If circumstances change,
they can do it.
10:32
MR. DUNCAN SMITH, Dyer, Ellis and Joseph, said he placed the call,
but C.J. Zane would comment.
MR. ZANE reported that from their perspective people in Washington
D.C. are trying to figure out how to deal with ANWR. "There are
lots of moving parts here."
He said that the energy bill could move quickly to the floor if
ANWR were to be dealt with in some other way than in it. He said
that Senator Daschle was going to put some kind of energy bill on
the Senate calendar, so it is available if favorable circumstances
arose. He thought that Foothills would have more political momentum
going if they could have the withdrawn partners issue resolved and
they have been working diligently to pull their deal together.
MR. ZANE said that Senator Murkowski had draft legislation "that he
wants to keep in his hip pocket, but my latest intel is that it is
not being laid on the table in any official capacity at this
point."
MR. SMITH added that the last time a Majority Leader took a bill
out of committee and took control of it was in 1960. The situation
is very fluid and it's all within the control of the Majority
Leader.
REPRESENTATIVE GREEN asked if he foresaw sort of a quid pro quo
that could pull ANWR out of the loop.
MR. ZANE said that the delegation is taking the position that, "You
don't get our gas in exchange for us giving up ANWR. You'll get our
gas, which you've already said you need, if we get ANWR. In the end
ANWR will help continue the potential for even more gas delivered
to the Lower 48."
He said that Senator Daschle would like to use this as a quid pro
quo and the delegation is aware of that and they are working very
hard to see that that doesn't happen. They are considering
attaching it to the economic stimulus package that the President
really wants or by attaching HR 4, the House bill that contains
ANWR, to one of the packages.
MR. ZANE said further that:
All of these moves and counter moves in the end are
interrelated so that you could end up with an energy bill with
ANWR and a gas line provision in it, but only after Daschle
agrees to some parliamentary procedure that lets ANWR have its
day on the floor. Some of the Democrats will make the argument
that we'll vote against ANWR and vote for the gas line. I
think that efforts will continue to separate the issues and I
think that our delegation will not be comfortable with a gas
line bill where there hasn't been some accommodation made on
ANWR. If that combination and deal gets made, it could happen
this year. If it doesn't get made, then the idea is to go into
next year.
TAPE 01-21, SIDE B
10:26
REPRESENTATIVE GREEN asked what the chances were of it happening
this year.
MR. ZANE said there was about a 20 - 25% chance that the ANWR issue
gets resolved satisfactorily so that we also get an energy bill
this year.
REPRESENTATIVE DAVIES asked what the chances were that we get
neither this session.
MR. ZANE replied:
It's too simple to say it's the reverse of what I just said -
that it's a 75% chance that we get neither, because I actually
think that we have a little bit better than a 75% - I would
say that we have about a 50/50 chance of getting ANWR dealt
with this year on some other vehicle, some other legislative
package. I say that because the delegation wants it; the White
House wants to see it happen, in my view. We have a 50/50
chance of getting ANWR, but it doesn't necessarily translate
then that we have a 50/50 chance of getting both. I do think
our chances of getting both are much better once you have ANWR
dealt with.
CHAIRMAN TORGERSON said:
Well, C.J., you know our position is just to reaffirm ANGTA.
So we're not really pushing for gas legislation. I've heard
two different stories on what might be in Senator Murkowski's
legislation. One is starting with the producers' legislation
and then three or four other provisions. The other one
reaffirming ANGTA, well first the producers would have to
[indisc] Foothills and have to get their act together within a
certain timeframe. So they would have the first right of
refusal. My understanding is under the producers' legislation
it would transfer to Foothills to do that and the other one
that I heard is actually from Mr. Katz and it's just the
opposite of that. It reaffirms ANGTA for a period of time and
then if they didn't perform under ANGTA, they would revert to
the Natural Gas Act and approve the producers' legislation.
CHAIRMAN TORGERSON asked them to chase down the answer to that
question. He said:
This committee has voted to uphold the provisions of ANGTA,
but if it's the wisdom of Congress to adopt the producers'
legislation under the Natural Gas Act, then we've got several
hundred pages of amendments that we want them to consider
along with that.
MR. ZANE responded that they understand and they have passed that
on.
10:52 - 11:03 Break
MR. ZANE continued to say that Senator Murkowski's draft
legislation was never something he was committed to; he wanted
staff to put concepts down on a piece of paper to see what they
would look like. He has heard from several people on that, but he
is in no way ready to move. It would bar over-the-top; it would
give prominence to the existing ANGTA law and the Foothills
project, but only for a period of time, like a couple of years. He
continued:
If an agency, like FERC, were to certify that an official
application had not been filed by a certain date, then after
that date, certain other provisions in this draft language
would become effective, like the ability to file for a second
southern route under the Natural Gas Act with its own set of
judicial and environmental review provisions in it that are
different than the ANGTA provisions. In other words, the
environmental [indisc] and expedited review provisions in
ANGTA would stay in effect through the time where the FERC
conditions would kick in if nothing gets going on the
Foothills project.
CHAIRMAN TORGERSON said he thought there were a couple of other
provisions; one was access by nonproducers into the line. He said:
I'm not too sure this committee would oppose that as long as
we do it in sequence of reaffirming ANGTA for a period of
time, giving that period of time to the owners of the
franchise, Foothills or whoever ends up gobbling up all of
Foothills, Duke or West Coast or TransCanada, and give them a
reasonable length of time to formulate their proposals, which
we know they're working on now and then if that all boils up
so that the project doesn't completely go away, then it would
revert to the same sort of conditions to the producers. We
haven't taken a position on that as this committee, but my
guess is that isn't too far from our original point.
MR. ZANE said the important thing about the language is that
Senator Murkowski is looking for a way to lock ANGTA in, at least
for some period of time after which they get sunsetted out.
CHAIRMAN TORGERSON reiterated that they didn't oppose that as long
as the timelines are right.
REPRESENTATIVE DAVIES asked if after the FERC certification
happened, were the other provisions substantially similar to the
producers' legislation that the committee has seen so far.
MR. ZANE said he thought it was more likely to be what Senator
Bingaman proposes rather than the producers. He wasn't sure that
the producers liked this. He knows they don't like the
reauthorization of ANGTA.
REPRESENTATIVE DAVIES asked if it wouldn't be hard to actually put
a project together under ANGTA if the producers were dragging their
feet. "It still puts the producers' bill in the drivers' seat in my
opinion. Could you comment on that?"
MR. ZANE replied, "I think you have to ask Senator Murkowski and
his staff those questions."
He assumed if the Foothills project can really get going, major
U.S. companies would be involved who on their own can be
significant in terms of capital for the project and political
clout. It's possible the producers would see that it's not
beneficial to drag their feet.
CHAIRMAN TORGERSON said they should remember that the producers are
authorized to be partners, also. They are the ones who are pushing
for the 82 amendments. He asked if there were any further
questions for Mr. Zane or Mr. Smith. There were none and he thanked
them for keeping the committee informed.
[END OF TAPE]
11:19 - 1:08 Lunch Break
TAPE 01-22, SIDE A
MR. ROGER MARKS, Economist, Department of Revenue, was the next
speaker. Chairman Torgerson had asked him to put together some
models on netback and different aspects of the economics.
MR. MARKS said that he had presented the committee with an economic
model in July and was asked to come back and present it in more
detail. He said when looking at the models the focus is on what it
means for something to be economically feasible. He explained:
One of the crucial issues that determines economic feasibility
is how risky a project is and how that comes in to determining
feasibility. That's why I really wanted to spend some time
discussing how risk and especially in the context of this
project, how commodity price risk, that is the price of gas
and how it affects the riskiness of the project and the
economic feasibility of the project.
We're going to talk about the commodity price risk. It's
useful to just pause for a second and discuss how the price of
gas is established. Getting away from gas and just talking
about any commodity, the price in the market for any commodity
will equal the lowest cost to produce new supplies.
What does that mean? If we take an example of something that
has nothing to do with gas. Let's just say I invent a robot
that will change the oil in your car and let's say I can
produce that robot for $100. I figure people will pay $500 for
this robot, so I manufacture these robots for $100 and sell
them for $500 and make a lot of money. Well, pretty soon
someone will come along and say, 'Gee, this guy is spending
$100 to produce something and selling it for $500. I can
produce that thing for $100, too, and I'll sell if for $400
and take all his business away. Pretty soon, someone else will
come in and say, 'Well, I can sell if for $300 and eventually
the price will come down to the cost. In economic terms it's
called the marginal cost and the marginal revenue. The
marginal cost is the cost to produce the unit and the marginal
revenue is the price. Basically, in markets, if they're
operating properly, the price of that commodity will for the
lowest cost to produce new supplies.
How might this come into affect for North Slope gas? Let's say
the price in the Midwest in the Chicago area is $3.00. The
market price for natural gas, whether it comes from Alaska or
whether it comes from Louisiana. Let's say that people figure
out they can make money building a North Slope gas line if the
price in Chicago is $3.00. Then all of a sudden, Venezuela
looks up and says, 'Gee, we have a lot of gas here and we're
interested in selling LNG in the United States and we think we
can bring LNG into the United States at a cost of $2.00 and
make money selling it for $2.00. So what happens is at that
point, if you have power plants in the United States or a
local distribution company, you say, 'Gee, I can buy gas in
Louisiana or Alaska for $3.00 or I can buy gas from Venezuela
for $2.00. At that point, the same process that happened with
the robot would happen with gas and eventually the price of
gas would come down to $2.00. With that sort of help the price
is established and since if you're someone who's thinking
about producing gas and building a pipeline to bring North
Slope gas to market, you have to be concerned about what the
price of gas is going to be in the future. Because the price
of gas is so volatile and so unknown, there is significant gas
price risk facing someone who decides to build a project.
The question then becomes who will assume this gas price risk
and how will they assume it. One way, and this is how if
things are evolving the way I see it, I believe what will
happen at some point in time is the North Slope producers
decide to go ahead with this project, they will have a third
party build and operate the pipeline and they will pay someone
to build the pipeline and they will ship the gas. Someone like
Foothills, Enron, Duke or El Paso or Williams.
If the project is structured like that, the only way a
pipeline company will get financing to go the project is if
the producers make throughput guarantees if they guarantee
they will pay to ship a certain amount of gas for a certain
amount of time. That way the producers would assume the gas
price risk. If the producers assume this risk and let's just
decide Duke Energy, for instance, is going to build this, and
they go to the bank and say we're going to build this and
their bankers say to them, 'Okay, what you have to do is get a
throughput agreement. It's going to be a 4 bcf/d line and we
figure the tariff is going to be $2.50. If the producers,
Exxon, Gulfs and BPs, say, 'No matter what, they will pay
$2.50 for 4 bcf/d for 20 years, if they guarantee to pay to do
that, then we'll finance the project.'
Well, if that happens, let's say the producers commit to pay
$2.50 for 4 bcf/d for 20 years and then the price drops to
$2.00 like we talked about a few minutes ago, the producers
could loose a lot of money. That's an extreme example, but if
they loose a penny on 4 bcf/d for 20 years, that's $300
Million they would loose over 20 years, which is a lot of
money. If they lost .50, like they have up here, that would be
$15 Billion.
Another way gas price might be assumed if, for instance, these
pipeline companies instead of having the producers take the
gas price risk, the pipeline companies come in and say, 'Okay,
we'll buy the gas from the producers on the Slope for .50 or
.75 or $1.00, we'll buy it from them, we'll ship it and then
we'll sell it ourselves in Chicago. That way the pipeline
companies would assume the gas price risk. Either way, someone
assumes the gas price risk. If the pipeline companies assume
it, then the project becomes much riskier for them. The whole
lynchpin in this project is the gas price risk and who is
going to assume it.
I've talked to several of the pipeline companies over the last
couple of years and from what I understand them saying is they
probably are not going to assume the gas price risk. That's
not what they do. They build and operate pipelines and that's
why I said earlier, as this project structure seems to be
evolving, I believe the producers, if it's built, will
probably assume the risk. But it's possible the pipeline
companies could assume it, as well.
While thinking about the project and those different project
structures that I presented, the question you need to ask
yourself is who is assuming the gas price risk. It's also very
important to understand that the gas price risk is different
than the pipeline risk. If we have a project structure where
if Duke is building the pipeline and the producers are
assuming the gas price risk, the pipeline risk is much, much
different than the risk of the producers would take. The
pipeline company would certainly face risk. There's cost
overrun risk, there's environmental liability contingencies,
it's possible the regulators might not let them recover all
their costs.
But these risks are much different than the risks assumed by
someone who is going to live or die with gas price. I believe
these risks are less, as well. It's important to understand,
though, that someone building and operating the pipeline is
going to face a whole different set of risks than a producer
who is guaranteeing to pay the shipped gas, no matter what the
price is.
So, if you think about this gas price risk, what companies are
going to do is sit down and think about what might happen to
the price of gas and even though the average price might be
$3.00, they might say, 'Well, there's a 50 percent chance
prices might be $3.00, but there might be a 40 percent chance
it's $2.00 and maybe a 10 percent chance it's $7.00. That all
averages out to $3.00. But they'll look at that and say, 'Gee,
there might be a 40 percent chance we're going to loose money
on this and loose a lot of money. So, they're going to look at
what they see as their distribution of possible gas prices,
look at what the loses might be, how big they might be and how
frequently they might loose money and that's going to sort of
shape how they view the whole riskiness of this project.
When a company is doing a feasibility study or an economic
study on the viability of a project, the way they address risk
is through what's called the discount rate. What the discount
rate looks at is what kind of return do we have to give
investors to make them feel comfortable investing money in
this project. Every new project needs cash and they get that
cash from investors, probably in the form of debt or the form
of equity. The company, when it's getting cash for a project,
is going to compete with investments from other projects. An
investor can invest in a gas pipeline in Alaska or he can
invest in an internet startup company in Silicon Valley. All
these investments compete with each other and the investors
are going to expect a certain rate of return before investing.
The important thing about this is the amount of return that
they expect to get for investing is going to be commensurate
with the amount of risk in their project. For example, today I
can buy a one-year T-bill from the federal government backed
by the U.S. government. There's practically no chance that
they'll default, so I can invest $100 now and one year from
now get back from the government, I think interest rates now
are around 2 - 3 percent, and get $102 or $103 back a year
from now. On the other hand, if I'm an investor and I'm trying
to find an investment and I look on the internet, people
looking for investors and suppose I see that some is starting
up a travel agency that's going to specialize in bringing
people to Afghanistan today and they're going to pay 3
percent. It cost them $100 to bring people over, but they'll
charge $103. I'm going to look at that and say, 'You know, for
the same $100, I think it's a lot riskier investing in the
Afghanistan project than buying a T-bill from the federal
government. What kind of return would I expect to invest in
the Afghanistan scheme? Maybe I'd want 100 percent return. If
I put $100 down, I'd expect $200 back because the odds are so
risky.
The question with this project becomes what kind of risk
surrounds the price of gas. A project will generate cash
flows. In this project you'll be selling gas in Chicago and
you'll make money on that, no matter what the price and you'll
have costs. You'll have your tariff, you'll have operating
costs, you'll have taxes to pay. What comes out of that are
the net cash flows. The net cash flows go to both the debtors
and the shareholders and this is the return paid to investors
and this is called the cost of capital. It goes to both
debtors and shareholders. It's sometimes called the weighted
average cost of capital or the WAC. And the rate of return
that these investors require to invest in this project is
called the hurdle rate or it's also called the discount rate.
In modeling projects, what a company will do is they'll have
their own assessment of what kind of return given the risks
that investors will expect from investing in the project and
that will become the hurdle rate and if the cash flows don't
generate a rate of return that exceeds that hurdle rate, they
will not consider the project economic.
We might ask what happens if a project generates a rate of
return less than what the shareholders expect. Let's say I
expect a 15 percent rate of return in a project and I invest
$100 and it turns out it's only going to return 110 percent.
What will then, if I'm still going to expect 15 percent, what
that means is that the shareholder will only put $95 down, if
I'm going to get $110 back rather than $100. In essence, what
that means is that value of the stock goes down and
corporations these days are structured to make the lives of
the managers very miserable if the value of the stock goes
down. So, management is not going to do anything to make the
value of the stock go down, which is why they need to earn a
rate of return that investors expect given the risk.
Again, I'd like to point out that this discount rate, if we're
addressing the project where someone like Exxon is figuring
out whether or not to have someone build the project so they
can sell gas and Exxon is assuming the gas price risk, the
discount rate they have is going to be very different from the
discount rate someone like Duke is going to have to build a
project. Numbers have been thrown around that maybe there
might be a 9 percent cost of capital on the pipeline and a 15
percent discount rate for the project. Those numbers are not
inconsistent at all. What they are is two completely different
investment decisions with different sets of risks.
Now the question is what might be the discount rate for this
project. Generally, when you try to figure out the discount
rate for a project, you want to figure out what the risk or
discount rates are of comparable projects with similar
business risks. It's not difficult these days to look at
different companies just to see what their costs of capital
are and see what discount rates companies use as a whole. One
reason is that projects that have a discount rate, not
companies. It's not hard to figure out what Exxon's cost of
capital is. However, if Exxon decided to go into the airline
business, they would not use the discount rate they use for
exploration and development for oil and gas. They would use
the discount rate the airline industry uses.
This project we're talking about here is very unique and it's
difficult to find the proper analogue business risk that would
be comparable. For instance, something like Enstar just has a
gas distribution system in Southcentral Alaska is not an
appropriate risk analogue. The exploration and development
arms of these producers are really not an appropriate
dialogue. One can make the case that a well-diversified
exploration program is probably not that risky. If you can
make a lot of money off of one well and you're drilling in
five different places and you think one of them is going to
come in, that's a whole different set of risks. Even other gas
pipeline projects are not appropriate analogues for this
project and the main reason why is simply their high
transportation costs for gas from Alaska. If the Prudhoe Bay
gas field were located in Indiana right now and it was 50 mile
pipeline trip to Chicago, that gas would be commercialized by
now, because it would be very unrisky. Alaska is
geographically about the end of the line in terms of economics
on gas projects. So, it's really difficult to say what the
discount rate is and each company looks at it their own way.
Each company will probably have a different assessment about
what the discount rate is and I'll say right up front that I
do not know what the proper discount rate should be for this
project. I'll also say that this whole presentation has been
sort of surrounded in gloom. I wanted to represent what the
risks are and how bad the risk could be. Again, this is not to
say that this couldn't be a splendid project and there's no
advantage to companies to look at a project through more risky
eyes than what it really is, because if there's an opportunity
to make a lot of money, they will do that.
What I'd like to do is also talk about a couple other concepts
before we get going, specifically in the model. I would like
to put up the model to show those ideas.
CHAIRMAN TORGERSON asked if he was going to comment on the press
releases where the producers say the gas lines are not economical,
because they make 11 percent and not 15.
MR. MARKS replied:
Basically, my model if you put the producers inputs into them,
I get the same outputs the producers get. As I said in July,
we are certainly not specialists on what the capital costs of
the project are and that's a big determinant about what the
answer is. So, we really don't have an opinion on the veracity
of the inputs. If the inputs the producers have represented
are indeed the true inputs, I believe the outputs they have
generated are indeed the outputs. When they put up 11 percent
as a return, that is the return with those inputs. Again, I
have no idea what the right discount rate is. That 15 percent
is something the three of them put together for presentation
purposes. I think each company has their own different idea on
what that number is.
CHAIRMAN TORGERSON asked if they would characterized 11 percent
return as a nonprofitable project.
MR. MARKS replied, "There's a difference between profit and, again
with my Algerian project, you could earn 3 percent and not be
profitable. That does not necessarily make if feasible."
CHAIRMAN TORGERSON asked if they could explore that today, because
they need to get past the news releases saying that 11 percent is
not a profitable project. He knows the regulatory agencies
generally give pipelines between 8 and 12 percent return as a
built-in profit in their tariff. He assumed that they would like a
higher number because of the risks that might be involved, but it's
an uncharacteristically higher number as it relates to what our
regulatory agency gives.
MR. MARKS replied:
Let me answer your second question first. Again, if the
regulatory agency gives the pipeline a 9 - 12 percent rate of
return, that is not inconsistent with a producer who needs 15
percent to make this project work, simply because they're two
different investment decisions. One, the return a regulator
would give a pipeline company, if a regulator is going to give
that return to the pipeline company based on the risk they
face, the pipeline company is only going to get financing
given the throughput guarantees. With those throughput
guarantees, the risks the pipeline companies face, I believe,
wants a lower rate of return than what the producers would
want facing the commodity price risk. That's not to say that
the pipeline company doesn't have any risk. They do. There's
cost overruns; there's the possibility the regulators might
not let them recover all their monies and there could be a gas
explosion in the middle of downtown Fairbanks or Edmonton, for
instance. So, building a pipeline is not riskless, but it's a
less risky activity. Again, what we have here are two
different projects facing two different profiles. One is a
decision to build a pipeline with a throughput guarantee. The
other is the decision to make that guarantee knowing you could
possibly loose a lot of money if gas prices go low.
To answer your first question, again, I don't know what the
discount rate is. It would be foolish for me to try and say
what that is. I could probably give you a wide range, but the
range would be too wide to be meaningful. What we can do with
the model is look at what rate of return you get on your
different inputs and how different inputs or tax regimes or
prices affect the rate of return and see how close you get to
a hypothetical target.
CHAIRMAN TORGERSON asked if the 11 percent rate of return includes
things such as the loss of oil production, if any, if we take 4
bcf/d off the fields. Also, he wanted to know if they are including
the netback of gas or is it just strictly pipe line economics.
MR. MARKS responded that he understood the 11 percent rate of
return is not predicated on any oil losses. He explained with the
use of his model.
REPRESENTATIVE GREEN asked what would happen to the rate of return
if they set this up at $2.50 and they find gas at $2.00. He also
wanted to know if the miscible liquids had been considered in the
netback value to the state. Those liquids could be extracted before
the gas goes through the pipeline and money could be made there.
MR. MARKS replied that in the example he used $2.50 was the tariff.
He didn't think it was possible to enter into real long-term gas
sales contracts for significant volumes.
There is no real market out there. You can't go to the New
York Mercantile Exchange and sort of hedge gas 20 years out. I
don't think most power plants and local distribution companies
are willing to enter into long-term contracts on the sales
side.
On the second question, the liquids. This is what the
producers have told me and this how I believe they have
modeled it and how I've modeled it. They have told me that the
composition of the residue gas would be 1080 BTUs per mcf.
However, the gas distribution system in the Upper Midwest can
only take 1040. For the other 40, they said the cost of
extracting the liquids would offset the value of that extra 40
BTUs and it was a wash pretty much. Some people have said that
the residue gas might have much higher BTUs; it's something
the Department of Revenue is not an expert on. But that's the
best information we have on that right now.
1:42
REPRESENTATIVE FATE asked regarding the gas price risk if he or the
producers had a constant in the formulas which says that in the
future there may be a different process in establishing gas price
making the gas price risk more tolerable in the computation of
their return on investment.
MR. MARKS replied, "Yes, if you could lock in $3.10 for 20 years on
4 bcf/d, that would reduce the risk of a project and the hurdle
rate would be reduced as well."
REPRESENTATIVE FATE asked if there had been any constant computed
on, at least, the expectation that might happen. He explained that
he has heard people in the industry say that some type of pricing
mechanism is needed to stabilize the price of gas. "If that's true,
then the gas price risk would be leveled at some point and the
computations would be more bearable relative to the return on
investment."
MR. MARKS responded that he was not familiar with any proposed
ideas to stabilize gas prices. Consumers want the price to be as
low as possible and there would be resistance if there was any
effort to put a floor on prices.
CHAIRMAN TORGERSON commented that one of the producers asked some
members of Congress to entertain a floor on pricing.
If the price of gas went down to around $1.50, then there
would be some sort of royalty or dollar exchange to give them
downside protection, but that hasn't materialized. I'm sure
the answer to your question would be yes, it would be less
risky if they would have a government guarantee. That goes
without being said. I also don't think there's anybody
entertaining that currently, but we don't know that either.
REPRESENTATIVE FATE responded that was why he wanted to know if it
had been introduced as a variable in any modeling.
CHAIRMAN TORGERSON responded that it hadn't been introduced, but it
hadn't been thrown out either. He thought it would be an upward
battle.
REPRESENTATIVE DAVIES clarified that he thought part of the
question was whether it was a factor in Mr. Marks' model and he
heard the answer to be no.
REPRESENTATIVE OGAN asked if it was correct that a long term gas
contract was for about one year.
MR. MARKS said he wasn't sure, but probably not much more than
that.
REPRESENTATIVE OGAN asked if anyone had considered what the energy
market would be in 2040.
MR. MARKS replied that the reason it's difficult to do that is
because for years the gas price was $2.00 until about a year and a
half ago when prices shot up to $10.00. That happened mainly
because inventories were very low and last winter was the coldest
winter in 100 years. "The big unknown is what happens to supply
when you go from a $2.00 well to a $3.00 well. There's basically a
continuous line at any time the price goes up."
He explained that all of a sudden the gas that cost $2.50 - $3.50
to produce that wasn't economic before becomes economic. No one
knows what the shape of the line would be - whether a whole bunch
of gas would come on line or a little bit. He thought that when
prices shot up, most analysts underestimated the amount of
additional gas that would come in. So, it's difficult to forecast
what happens 10 years from now. "Alaska would be just about the
most expensive gas on the market when it comes in."
MR. MARKS said he wanted to further explain the discount rate
issue. He said that the discount rate represents the return to both
debtors and creditors. "It's a weighted cost of capital that's an
average of your debt and your equity."
TAPE 01-21, SIDE B
1:55 p.m.
MR. MARKS said there might be a question of why there are no
interest payments if you are incurring debt. He answered:
The way corporations do their modeling is they assume you have
all equity financing with no explicit debt payments.
Therefore, your cash flows go to pay off both the debt and the
equity. That rate of return, the 11.1, is called the return on
investment.
The alternative way to do this would have been to actually
model in the debt payments. What happens then is since you're
leveraging, since your rate of debt is less than your rate of
equity, what you're left with then, your cash flows would be
greater; but, since you paid off your debt, what you're left
over with in the net cash flows goes on the equity. So your
discount rate instead of being the average cost of capital,
it's your average cost of equity, which is greater. But, in
general, the results you have would be the same in terms of
feasibility or not. But, what corporations do is model all
equity with an average cost of capital as a discount rate.
The other thing I'd like to point out is from what people say,
'Why don't you just leverage the whole project? Why couldn't
you borrow 100 percent at a low rate?'
What happens even if you could get 100 percent debt financing,
which you couldn't, but, if you could, theoretically, what
happens is that every time you incur more debt, the next set
of debt you incur is more risky, because people who are
incurring debt in the back of the line aren't in the back of
the line. They're going to get paid off after the people in
front of the line. If you incur more debt, what that does is
make your cost of debt at the end of the line higher. Or, if
you do have shareholders behind the debt holders, what that
does is make the shareholders' investment even more risky,
because there is not only more debt in line in front of them,
but it's higher cost debt. The finance theory says and
actually two economists want to help [indisc.] in proving this
that the weighted cost of that much capital is actually
indifferent to your debt equity structure. If you try to do
more debt to help a project, what happens is your cost of
equity goes up and your weighted average cost of capital is
unchanged.
CHAIRMAN TORGERSON asked how he treated property tax (ad velorem
tax).
MR. MARKS replied that for the pipeline there was a four-year
construction schedule and, "each year you start paying property tax
as soon as it goes in the ground even before revenues are
generated."
He said the model shows how things work and answers questions. He
again read a caveat that he had read in July that says, "The
following numbers do not represent what the Department of Revenue
believes the economics of the project are. They simply represent
what the economics would be and with the specified inputs. The
Department especially claims limited expertise as to capital
costs."
He explained that he just used the peak revenue year of 2015 for a
project that starts in 2007 and state revenues would be $626
million. He continued to explain his slides.
CHAIRMAN TORGERSON asked if the economic limit factor (ELF) kicked
in immediately on Prudhoe Bay gas.
MR. MARKS replied that there is an ELF on Prudhoe Bay gas right
now, although there are very small volumes that are sold to the
refinery. The ELF gives approximately 300 tax-free barrels of oil a
day or 3,000 MCF/D of gas.
If oil and gas come out of the same well, which they will in
this case, the tax-free treatment is pro-rated between the oil
and gas. So, with a gas sale, basically you have relatively
less tax-free oil and so the oil ELF goes up.
CHAIRMAN TORGERSON asked if he was predicting there would be zero
loss of oil after they depressurize the field. He also asked what
they should use for a fair comparison of projects, like LNG Al-Can
route and the GTL project. "Which one makes the producers more
money and which one is best for the State of Alaska?"
MR. MARKS replied no to the first question. He said further:
If the producers are going to do the project, whether it's
GTLs, LNG or a pipeline through Canada, there's no project
that they will do if it's not economic to them. I don't see
the state doing this project. If they're doing it, it has to
make sense to them…. So, the first thing you have to look at
is the rate of return. Different projects, again, are going to
face different risks and so each project will not have the
same discount rate.
CHAIRMAN TORGERSON asked how he got his rate of return.
MR. MARKS replied that the rate of return was the internal rate of
return from [indisc.]. "The reason it dropped from 11.11 to 10.77
is because I just put in the oil losses now.
CHAIRMAN TORGERSON asked if he compares three categories, the well-
head, the total state revenues and the rate of return, between the
different projects would they have a good feel for which one pays
the state most and pays the producers the most.
MR. MARKS said that was fair, but to keep in mind that different
projects have different discount rates.
2:06
REPRESENTATIVE GREEN said the affects the loss of oil would have
bring to mind the questions:
Will there be and when will there be a loss of oil? Is it
going to be immediate or is it going to be down the road a
ways. If it's down the road a ways, is the value of the lost
oil discounted at the same rate that we're discounting these
other things…
He also asked if the items in the model could be changed one at a
time to find the sensitivity.
MR. MARKS replied, "Absolutely…"
He continued to explain that their oil loss model uses information
in a document from ARCO's oil loss announcements during royalty
litigation in 1992 (with their permission). The Department started
modeling the commercialization of North Slope gas around 1996. ARCO
said that it would be okay to publicly show the oil losses for this
exercise, but that he couldn't show the actual model, itself. He
has been told by oil companies now that thinking has changed and
what they thought in 1992 for oil losses was too high, but they
haven't talked about what they think quantitatively the losses are.
His model shows the oil losses as a function of when the gas sales
start, how fast they ramp up, and how much gas is sold. It's
basically a total amount of gas that has been depleted from the
reservoir over time and that's why the losses start out small and
grow.
CHAIRMAN TORGERSON asked why there was the NGL loss.
MR. MARKS replied that was because the gas was used to pressurize
recovery in the reservoir for the NGLs as well as the oil.
CHAIRMAN TORGERSON said if we're producing more gas, we should have
more NGLs. He continued to discuss figures in the model with Mr.
Marks.
MR. MARKS said that the big utilities in Asia have traditionally
structured their pricing with formulas tied to crude oil prices,
which had nothing to do with the cost of producing the commodity,
but that was changing.
Going forward, the whole gas purchase structure in Asia is
being decentralized on a much more profit oriented basis where
individual power plants and individual gas distribution
companies are going to be buying their gas. It's going to be
deregulated. It's going to be much more competitive and I
believe a gas structure in Asia will tend towards a structure
where a purchase price will have something to do with the cost
to produce it.
What that does is put Alaska at a tremendous disadvantage,
because there's a tremendous amount of gas in competing
jurisdictions in the Mid-East, Katar, Abudabi, Asia, Malasia,
Australia, Indonesia, Sokalin Island and basically that gas is
sitting at tidewater and doesn't have to bear the burden of a
pipeline.
Pretty much you can liquefy gas for the same cost anywhere,
ship it for the same cost anywhere. You can say that Alaska
might have some distance advantage over the Mid-East. The cost
of shipping LNG over the last two years has come down
drastically, so even big differences in shipping distances are
not that important. Furthermore, what we can tell pretty much
is all of Asia's LNG contracting needs, at least to the end of
this decade, have been met. Alaska, to bring the cost down,
would have to sell a tremendous amount of LNG, which is far
more than anyone is going to be looking for, at least in this
decade.
He said using this structure, you go for oil price risk instead of
gas price risk as the risk factor. He thought over time, the price
of gas in Asia would represent what the cost to get it there will
be.
CHAIRMAN TORGERSON asked if he had included the Port Authority
numbers in any models.
MR. MARKS replied that they are selling volumes that aren't even
discovered, yet. Their model uses 6 bcf/d for 30 years, which is 65
tcf, almost twice as much as has been discovered.
CHAIRMAN TORGERSON asked him about the GTLs.
He commented on GTLs, that once the product is made on the North
Slope, you would deliver it to the oil pipeline. So, there isn't
the problem of scale that you would have with LNG or the Canadian
pipeline. You don't need a huge project to bring the cost down. He
said:
The other notable thing about gas to liquids is the big
problem with Alaska gas that geographically, it's pretty much
at the end of the line. In these LNG and Canadian gas projects
the transportation costs just chew up the value. With oil,
maybe 25 percent of the value gets eaten up by transportation;
with gas it's about 90 percent. With a GTL project using the
trans Alaska oil pipeline, the variable costs of using the oil
pipeline are fairly low, in the order of maybe 20, 30 or 40
cents per barrel. Once you get the gas to tidewater in Valdez,
you can compete with other projects in the world. You get on
equal footing with other competing projects a lot easier since
you have the oil pipeline to work with and the costs are low.
Again, you don't have the transportation costs eating up the
value like you do on the other one.
What we modeled was a three-train project - each train
producing 100,000 barrels per day of this high value clean gas
product, part diesel and naptha. The price Exxon was looking
at two years ago was about $35,000 per barrel capital costs at
peak. I've reduced that to $30,000. If you read the
literature, people are even thinking about costs as low as
20,000 in projects going on in Africa now. People think it
would cost more to build something in the Arctic. They put
factors up to 50 percent or so on that. So, I've used $30,000
here. There's talk about Shell and [indisc.] building up in
Nigeria now for $20,000. So, what that amounts to with 100,000
barrels per day peak, a total CAPEX of $3 billion per train.
What you're getting is about .11 barrels of the product per
thousand BTUs. These are the price premiums in the market
today you can get for clean car diesel on the West Coast for
naptha. In Asia, you get about 30 percent over crude oil for
car diesel and 15 percent over crude oil for naptha. Again,
what you're doing is playing the oil price risk roller coaster
with a project like that.
Pretty much you have the same tax structure that we had in the
other projects. Looking at the cash flows…
CHAIRMAN TORGERSON asked how many bcf/d 100,000 barrels was or was
it all in BTUs.
MR. MARKS 872,000 MCF going in to produce 100,000 barrels of the
product.
CHAIRMAN TORGERSON asked what the rate of return was.
MR. MARKS replied that it was 8.87 percent.
REPRESENTATIVE FATE asked what the equivalent was in bcf/d.
MR. MARKS replied, "Remember this is only a 2.6 bcf/d, so these are
no comparables in terms of volumes."
CHAIRMAN TORGERSON asked if it was safe to say that the State makes
more money on GTLs in the pipeline.
MR. MARKS replied:
In general I would say, with all things equal, generally a
product that's tied to oil would probably be more profitable
than one kind of gas for no other reason than you have a
cartel propping up the price on oil-based products. So, if
indeed the price is tied to oil, that will affect the bottom
line. It's just what the price of these commodities turn out
to be.
REPRESENTATIVE GREEN asked when he did this model, if he reduced
the tariff on the oil, because there is more throughput.
MR. MARKS said that was right.
REPRESENTATIVE GREEN asked if other considerations were involved in
his model like if there were no new discoveries and they could
still have GTLs coming through the pipeline, keeping it viable.
MR. MARKS showed him a chart of oil volumes saying:
Here's an example of what tariff reductions are as a result of
the GTL volumes. It starts at 12 percent, but after the late
years of the North Slope when oil volumes are low, the tariff
reductions get sizeable. Who knows what the volumes are going
to be, but just with the inputs I have here, you have a $4 per
barrel reduction in the year 2038. I'm sure it won't turn out
that way, but at least it's being considered.
2:40
REPRESENTATIVE OGAN asked when he figured the royalties to the
state, did he figure on well-head price on gas or the royalty based
on a barrel by crude at processing.
MR. MARKS replied that he figured it based on gas:
It's 12.5 percent regardless of whether it's oil or gas, but
what you have is gas being produced. You don't have the well-
head, which is the point of production when they royalty is
assessed and going through this processing activity. Your
closest value at the end is just netted back and that total
gross value is divided among the total units of gas going in.
REPRESENTATIVE OGAN asked if he was saying it would basically be a
wash after they [indisc.] the 40 percent of gas.
MR. MARKS replied:
It doesn't matter, you could take the gas and you could turn it
into chairs and sell the chairs; and you have gross value just
divided among the amount of gas going in. You recognize that it's
sold as an oil based product and higher value, but in terms of
administering the royalty, it's just divided among the gas units
going in.
TAPE 01-23, SIDE A
REPRESENTATIVE GREEN asked on the conversion from gas to liquid was
he using conversion estimates back in the late 90s or current. He
thought that ratio is becoming more and more favorable.
MR. MARKS said he was using what Exxon's technology was in 1999.
CHAIRMAN TORGERSON thanked Mr. Marks for his testimony and
announced a short break.
2:43 - 3:00 - BREAK
[END OF TAPE]
[THE FOLLOWING TESTIMONY WAS NOT RECORDED]
Department of Revenue Deputy Commissioner Larry Persily said that
Cambridge Energy Research Consultants would present an update on
they see current and short-term gas prices in North America.
MR. SMALL said that one of the most obvious things he sees is the
overall economic weakness, but that they expect to see some
recovery in the mid part of next year and certainly in the second
half. Until then, the economic weakness translates into soft
demand. Demand is down in all sectors, especially steel and
chemical, but these are the areas in which they expect to see
recoveries in the third quarter. Demand losses next year due to a
return to normal hydrogenation will offset some of the return of
demand that was part of the fuel switching that occurred in the
first half of this year. "In other words, we are going to have
offsetting factors next year to a certain extent…"
Conservation has been a big factor especially in the residential,
but also in the commercial sectors. This is most apparent in the
West where the local distribution company programs for conservation
and the higher prices have had a big impact. "In fact, in the West
we expect demand to be down between 1.3 and 1.5 bcf/d through this
winter and on average next year."
Power generation is an areas where they expect to see some demand
strength. There is a question as to whether the long-term demand
for power generation has been impacted, which they believe has
happened. Growth has not been as strong as had been anticipated.
"Obvious, if you push demand down, it takes longer to get back to
that point and then to grow to a lower point than where you had
originally expected it to be."
CERA has seen roughly 55 gigawatts of new power generation this
year, almost all gas fired, and another 95 gigawatts of proposed
and under-construction generation for 2002. However, about 65
gigawatts will be built. In 2003, they are showing a larger number
of proposed and under-construction projects of 110 gigawatts, but
expect that number to get closer to 60. Certainly, in 2002 and
2003, there is power generation that will demand natural gas. The
bigger question is how extensive will be the operation of those
facilities.
[END OF UNRECORDED TESTIMONY]
TAPE 01-24, SIDE A
3:05 p.m.
If the economy does not recover as expected, then those facilities
will not be operating at full capacity and will not provide demand
strength.
The overall picture for the Lower 48 for 2002 is demand growth of
about 1.6 bcf/d from both power and industrial consumption. Again,
most of the growth is expected to occur during the last half of the
year.
In Canada, a similar demand decline is expected to couple with a
slower recovery. This is due to the fact that the Canadian economy
lags the Lower 48 and because there is less power generation built
there to provide the demand growth for the up coming year.
Because the injection season in the U.S. has ended with almost 3.1
trillion cubic feet (tcf) or close to the absolute storage capacity
of 3.2 tcf, storage in the Lower 48 will be a big major factor this
winter and through 2002. There is a net inventory increase of 733
tcf this year over last. An obvious impact of this increase is to
reduce winter prices. It will take an extremely cold winter to draw
the gas reserves down a significant amount or to the level they
were at the end of last winter. Additionally, they estimate that it
will take a decrease of about 2 bcf/d to refill the storage
reserves to the current level by the end of the 2002 injection
season.
The situation in Canada is similar to the Lower 48 with record high
storage levels in eastern Canada and near record levels in the
west. Here too, prices will be depressed.
Drilling in particular has been affected by the lower prices. They
estimate growth of about 400 million per day for 2001 and a decline
of about 500 million per day in 2002 due to the decline in drilling
they have seen over the last three months. Unless prices rise to a
sustainable $3.00 level, they do not believe drilling will recover
to the early 2001 level until later in 2002. However, the 500
million decline is more than offset by the increased storage levels
outlined earlier.
The Deep Water Gulf and the Rockies are still growth areas while
declines are being experienced in the more mature fields, the newer
fields that are more expensive from a production perspective and
the Shallow Shelf area in Mexico. Later in 2002 there should be
some recovery in drilling levels and will provide a better picture
of supply for 2003.
Canada differs in that drilling declines are typical in the fall
and increase in the winter for remote and exploratory locations.
Although it might be expected that remote and exploratory drilling
would decline with lower prices, all of the deep grades were fully
contracted last year for two and three year terms. Producers will
pay for the drilling rigs whether they use them or not, but the
odds are that they will use them. With the forgoing in mind, prices
should decline but not as much as in the Lower 48. Next summer
should not see a large drop because most of the drilling will be
shallow and more than economical at today's prices.
Because of the decline in Canadian demand and the lower storage
injection requirements for 2002, most of the anticipated 850-
million supply-growth will be exported to the Lower 48. It's
expected that the decline in Lower 48 supply will be more than
offset by Canadian growth next year.
The combination of demand decline and high storage levels and
increase in Canadian imports indicate continued soft prices. They
have declined from $3.25 to $2.75 and they expect them to stay that
way through the winter. With oil prices being lower and gas prices
close to $3.00, fuel switching becomes more attractive. Therefore,
oil will probably provide a ceiling for gas prices through the
winter.
Spring will bring even lower prices because there is a typical
softening of demand at that time and the economy probably won't
have recovered. This coupled with lower storage injection
requirements for next year will probably see prices pushed to $2.25
through early summer. If there is an economic recovery and the
typical summer demand for power generation occurs, then they expect
to see prices strengthen through the summer. A typical winter
season in conjunction with a Lower 48 supply decline and the
expected economic recovery should see prices back up to the $3.00
to $3.25 level for the winter period. This scenario should bring
back fairly robust drilling activity in 2003.
The price of Henry Hub is expected to average $2.71 in 2002 but for
the longer term there are adequate drivers to keep prices above
$2.00. Of equal importance, there are drivers that will keep prices
from staying much above $3.00 for the long term. Although there
will be some price volatility, they expect prices to range between
$2.50 and $3.50 between now and 2005.
CHAIRMAN TORGERSON said the last update outlined several
opportunities for Alaska gas to enter the market in 2008 and 2010.
He asked for the current projection for opportunities for Alaska
gas.
MR. SMALL thought the window of opportunity has shifted by about
one year. When demand decreases, it takes awhile to get back to
previous levels before you can grow beyond that point. Current
expectations are that there is probably opportunity for frontier
gas in the 2009 to 2010 time frame. Then in 2012 to 2014 there
should be need for additional gas. It's the same issue of where the
frontier gas will come from, but this is where the opportunity may
lie for Alaska and Arctic gas.
CHAIRMAN TORGERSON then wanted to know how they were plugging LNG
imports into their thought process.
MR. SMALL replied they were seeing the existing four LNG facilities
in the Lower 48 all come back on stream. Three are active now and
the last will come on stream next year. They expect those
facilities to expand in 2003 to 2005. They also expect to see
Greenfield LNG facilities built in the last half of this decade.
They do see that new facilities will be built, but don't know how
many.
Because of the September 11 attack, they are looking at the global
economy. The fragile nature of the Middle East could impact both
oil exports and LNG development from that region. This could have
an impact on the entire global LNG balance in the latter part of
this decade, but LNG is seen as being an integral part of new
supply in the Lower 48 in that time frame.
CHAIRMAN TORGERSON commented that he sees LNG imports rather than
other frontier gas as Alaska's biggest competition.
MR. SMALL responded that their definition of frontier gas is Artic
gas, which is both Alaska and Mackenzie, off shore East Canada and
LNG. Of those three, they see growth in LNG imports and offshore
East Canada. The questions now are what are the competitive forces
of LNG? Is Arctic gas able to compete and if so how will it
compete?
CHAIRMAN TORGERSON then asked whether CERA tracks the petro
chemical industry.
MR. SMALL said they do.
CHAIRMAN TORGERSON asked if there is a market for polyethylene and
the anticipated delivery date.
MR. SMALL said there is always the opportunity for a market, but
here too the question of how the petro chemical industry in Alaska
would compete globally must be addressed. Due to the cost of
transportation from the North Slope to tide water, Alaska would be
at a disadvantage because there are cheaper sources of stranded gas
globally. He was not sure about the window of opportunity, but
doubted it would be before the latter part of this decade.
CHAIRMAN TORGERSON then asked whether they were tracking the
fourteen countries that are starting GASPEC, which is patterned
after OPEC and would control world gas prices. He first heard of
this organization during his last trip to Washington D.C.
MR. SMALL replied that was outside his area of expertise, but that
he would have someone from CERA investigate. He added that the
success of such an organization would be more tenuous than OPEC
because it's a smaller part of a global market and transportation
costs would be more difficult to control. This said, it's not
beyond the realm of possibility.
CHAIRMAN TORGERSON said because energy security is such a large
issue, it's of greater concern that they are trying to do this than
the possibility that they will be successful.
REPRESENTATIVE DAVIES asked what the major risk factors CERA was
looking at in terms of economic recovery in the next six months and
if the recovery doesn't occur, what price sensitivities are they
forecasting.
3:20 p.m.
MR. SMALL said consumer confidence and employment are major
signposts and the current stock market malaise figures heavily in
consumer confidence. In general, companies starting to report
positive earnings even though they aren't the earnings anticipated
a year ago, which is a positive sign. Consumer confidence and
spending are critical in terms of bringing back demand in steel and
petrochemical sectors.
CERA does have a scenario that predicts recession lasting through
2004 and it shows prices of between $2.50 and $3.00 through that
period. In the context of Arctic gas, the window of opportunity is
pushed well beyond 2010, possibly to 2015.
CHAIRMAN TORGERSON thanked Mr. Small for his testimony and
announced the pipeline ownership study would be discussed next.
MR. LARRY PERSILY explained part of his testimony would duplicate
part of Roger Marks testimony because risk is key in determining
whether the state should become an owner or financier of the
project. He then gave the following report:
Pursuant to your instructions in Senate Bill 158, the Department of
Revenue and its consultants have been working for the past few
months compiling a report for the legislature on the merits of
state or public ownership and/or financing of a natural gas
project. In addition to consulting with experts on debt financing
and project financing, we've interviewed more than 30 individuals
plus representatives from 10 companies in the oil and gas industry
- not just the producers but the large and not-so-large players in
the pipeline business. Our list of interviews also has included
many Alaskans involved in banking, the oil and gas industry,
legislators and business leaders.
Certainly, the Alaskans we interviewed all would like to see a gas
line built to create jobs in Alaska, to generate tax revenues to
pay for public services, and to promote the economic activity that
would come with such a large construction project. Obviously, we
don't need a study to tell us that. What we're looking at are the
risks to the state - and the benefits - of becoming a member of any
partnership that builds and operates the line. And we're looking
at how - and what would happen - if the state wanted to raise the
hundreds of millions or billions of dollars needed to buy into the
project.
Here are some of the questions we're trying to answer:
· What if we sign on as a partner and there are serious cost
overruns during construction? What if the partners are all
required to pay in more money to cover those overruns? Will the
state be able to come up with the money? It's always possible that
federal regulators - FERC - may not allow the pipeline owners to
recover 100% of the cost of any overruns. Is it smart to commit to
some possible unknown expense in the future, given that the state
already is running short of cash? Even worse, what if some
unforeseen event blocks or stalls completion of the line? Granted,
the risk is small judged by the odds of it happening, but the risk
does exist. We need to consider that the Constitutional Budget
Reserve Fund is at $2.8 billion and falling. We're looking at less
than $2.5 billion by the end of the fiscal year next June 30, and
perhaps as low as $1.5 billion one year later. The Permanent Fund
Earnings Reserve Account, which had $6.1 billion just a couple of
years ago, is around $2.7 billion this week after a bad year in
stocks while still continuing to pay full dividends.
· After the pipeline is built and the gas is flowing, there
are still risks to the owners of the line and/or the owners of the
gas. This is the cost of getting the gas to market, and whether
the market will be willing to pay that cost in full year after
year. Whereas the cost of moving North Slope oil to market is about
25% of the sales price at the refinery, the cost of moving gas to
Chicago is closer to 80%. There just isn't that much margin left
after paying the transportation tariff on a gas pipeline. A small
swing in the market price for gas could mean a loss for whoever is
carrying the risk. That's the central issue in all this. Who takes
the risk that, in any given year, the price for gas in Chicago will
not be sufficient to cover the tariff of moving it from Alaska to
the Midwest, plus the cost of production, taxes and a profit?
Generally, gas producers (the shippers) take this risk, but in the
case of the Alaska project, because of its size, we expect there
may be some risk sharing between the producers and pipeline owners.
Certainly, if the producers agree to take all of the price risk,
pipeline ownership could be a good investment for the state,
consistent with Permanent Fund earnings on a risk-adjusted basis.
As I said, we expect that the three North Slope producers are
hesitant to take all the risk - the risk of construction cost
overruns if they build the pipeline and the larger risk that some
years the market will not pay enough to cover the $2 plus pipeline
tariff plus other costs. Even if you lose just a dime on every
thousand cubic of gas in a 4 billion cubic foot per day line, that
loss could total $400,000 a day, or almost $150 million over a full
year.
Of course, pipeline companies would be happy to build the line if
producers agree to take all the risk, signing "ship-or-pay
contracts," committing to pay the pipeline companies a fixed tariff
regardless of the market price.
The decision whether to build the Gasline, and who will build it,
will come down to a deal over who is willing to share how much of
the price risk.
· Also thinking about risk, does it make sense for the state,
which is already heavily dependent on oil revenues, to take a large
investment in gas? Should we instead diversify from the oil and
gas sector in generating state revenues?
It's one thing for a corporation to take a risk that could mean no
dividends to shareholders if it goes sour one year. It's another
thing for a state to take a risk with providing essential public
services. Remember, we expect the Budget Reserve to hit empty in
2005, and the Permanent Fund earnings reserve has taken a major hit
in the stock market.
· Would the state be better off letting someone else take all
the risk, and we then would do what we do best - and that is tax
the profits?
· Putting aside the risk issues, we next will have to answer
the questions: What can the state bring to table as a partner in
the project? Would state government involvement actually slow down
a commercial operation? Does the state gain anything worthwhile
for taking a share of the risk?
In our research and analysis, and our interviews with producers and
pipeline companies, here is what we've learned:
· Project sponsors - be they gas producers or pipeline
companies - already have access to all the capital they need if
they decide to build the project. State involvement just isn't
needed for financing.
· State investment doesn't do anything to lessen the financial
risks for the other partners, so they don't gain anything from
having us as a partner. The marketplace dictates project risk, and
the state has no control over that.
· Alaska already has a significant future income risk in the
energy sector. Why would people want to compound the situation by
making a large, discretionary investment in energy? An executive
said by investing in a project that will not be cash-flow positive
for a number of years, the state is depriving its citizens of the
present-income value of its limited investment capital.
· Although some may believe the state would gain a "seat at
the table" as a partner in the pipeline, we wouldn't really gain
any more information than we would be able to get on our own -
through the Federal Energy Regulatory Commission, which would
regulate pipeline tariffs, and through the state's own regulatory
agencies. We couldn't use confidential, proprietary information
from the table against companies in tax cases, and we couldn't use
the information to out-maneuver our partners in gas marketing
opportunities.
· As a partner, the state might face the political temptation
to meddle in the business operation.
As one pipeline company said, the state would need to recognize
that board discussions are open, frank and confidential.
Decisions would need to be made for the best interest of the
project, not necessarily the state. Decisions of and debate of
the joint venture board cannot be shared publicly. This might
not be compatible with state ownership.
Another executive explained that a seat at the table is a fine
political concept, but the state's participation likely will hurt
the viability of the project. The decision-making process of the
state on the joint venture governing board likely will be
influenced by political, not business, concerns and will be slow.
Management of any joint venture is, by its very nature, very
difficult. A governmental entity will only increase the complexity
because governments are not accustomed to making quick, unemotional
decisions.
· The state already can regulate much of the operations of the
line through right-of-way permits and regulatory oversight
functions.
· Being a partner could put the state into a conflict of
interest situation. What would be more important to the state -
running the line at maximum profit, or following new, perhaps
costly environmental or safety or regulatory rules?
· A final question is, should the state own a piece of a
project in a foreign country?
If the state decided to go ahead and take the risk as a partner
in the project, where would we get our share of the cash to buy
into the Gasline?
Under existing federal law, the state or any other public entity
could not issue tax-exempt debt except for a very small portion of
the project. Only those facilities available for public use, such
as a dock or highway or distribution hub available for all users,
would qualify under federal law for tax-exempt financing.
Everything else would be financed with taxable bonds.
Federal law does allow the state to issue a limited amount of tax-
exempt debt for private-activity uses, but that currently is set at
$187 million a year, and is used in full by AHFC, AIDEA, the
student loan corporation and others.
Congress could change the tax laws as it has for other projects,
but without a change in federal law, tax-free bonds do not appear
to be possible for raising the state's share of buying into the
project. The same restriction likely would apply to a port
authority or other, similar public corporation or agency.
Another issue is that we don't believe the state could issue
general obligation bonds for this project. State ownership in the
Gasline likely would fail to meet the required standard of a
capital improvement or public improvement.
But if we could issue GO bonds for our investment in the pipeline -
assuming the state wants to preserve its existing AA credit rating
- a conservative estimate of our debt capacity would allow us to
commit no more than 5% to 8% of our general fund revenue stream to
debt payments. That's been the state's target for years, and it
has served us well in maintaining a good credit limit. At a limit
of 8% of general fund revenue, the state could issue somewhere
around $200 million to $300 million in 10- or 15-year bonds over
the next six years. Those numbers are based on the state's current
fiscal situation, meaning the budget gap. If the state were to
adopt new revenue sources, be it taxes or using some Permanent Fund
earnings, we would have the capacity to issue significantly more
debt by the end of the decade.
But also keep in mind that any estimate of Alaska's bonding
capacity today does not yet account for bonds under consideration,
such as the new DEC seafood lab, deferred maintenance on public
buildings, schools and harbors. The Gasline would have to compete
with all those other needs for GO debt.
The state or another public entity could issue revenue bonds,
pledging the future revenue from the Gasline to pay back the debt.
But there are some problems here, too.
· One, if the state backed the revenue bonds with a moral
obligation, we'd have to use tax money or Permanent Fund earnings
if gas line revenues were insufficient in any given year to cover
debt service. If we sold the bolds based solely on the gas line
revenue - with no other assets or income at risk - we'd probably
have to pay much higher interest rates to borrow that money. Much
higher than what the producers or pipeline companies would have to
pay on their own debt.
· Two, the state would be at risk if the gas flow or revenue
stream were disrupted. We would no longer have the revenue to pay
back the debt.
· Three, even with pledging future gas line revenues, the
state still couldn't match the excellent credit rating and lower
interest rates that companies such as Exxon and BP could get. For
example, looking at taxable bonds, the difference between Exxon's
AAA rating and the state's AA rating - if we could maintain that
grade - would be $20 million in interest payments in the first year
on a $10 billion debt.
· Four, we don't believe 100% project financing is feasible
for this project for any governmental entity. Regardless of what
the port authority is told by its lawyers and financial advisers,
our research indicates it is close to impossible to obtain 100%
debt financing for a project operated by a government entity with
no experience in such projects and with just a single source of
revenue to repay the debt. The answer might be different if the
producers were willing to absolutely guarantee a high enough price
for a high enough volume of gas for a long enough period of time to
pay back the debt, but if they're going to take all the risk, why
would they want to work through the state or a port authority when
they could issue their own debt at a lower cost?
One other comment I want to make is that back in 1978 the pipeline
companies were encouraging state investment in the project.
Federal law back then prohibited oil and gas producers from owning
a pipeline, so that source of funding was not available. The
project was estimated to cost $20 billion or more, and that was
more than the pipeline companies could afford. Simply put, they
needed the state. But the law has changed and the producers can
own the line. And the financial strength of many of the companies
involved has grown. And the cost is much lower. No one really
needs us any more.
These are our preliminary findings and thoughts to date, and could
change as we continue with our work. Our final report will be
delivered in January, and we would be happy to give you an update
next month at your convenience.
3:39 p.m.
CHAIRMAN TORGERSON commented he hoped the department and its
consultants would be able to work through the concerns and list the
pros and cons for each of the points set forth.
There are additional suggestions in SB 158 that he would like to
have each addressed individually. One was the feasibility of
forming a public corporation and another was whether forming a port
authority is a good idea or not.
MR. PERSILY said they would address the other questions and list
the pros and cons for each and look for solutions to problems.
CHAIRMAN TORGERSON pointed out this is the third report of its kind
and none have recommended state ownership so it's doubtful that
there would be a change but some of their questions are different.
The comments about "seat at the table" were interesting but most of
the information is confidential not public. It is available to the
Department of Revenue of course but he has not been able to get
much tariff information on the oil pipeline due to the
confidentiality requirement. Tariff fluctuation of one half of a
percent could be a determinant. The shroud of confidentiality is
certainly not good for those making decisions because they must
simply accept figures given to them.
MR. PERSILY asked if this meant they needed to consider making as
small an investment as possible in order to gain access to that
confidential information.
CHAIRMAN TORGERSON said that has been suggested and perhaps the
information wouldn't be available even then but he would like to
know. He does look forward to state legislation in the upcoming
session to deal with some of the shroud.
3:45
REPRESENTATIVE GREEN said there was a strong difference of opinion
on the tariffs on the oil pipeline and subsequent litigation. For a
more open policy there would need to be some degree of ownership.
If this is a good idea and the accessibility question is not
adequately addressed, then by owning 12.5 percent the State might
be able to allow access. On the con side, the State usually does
not compete with free enterprise.
MR. PERSILY said the law does not allow owners of a project to give
any preference to themselves for capacity. If the State wants
capacity, regardless of whether it's an owner or partner in the
pipeline, it would have to bid for capacity during open season like
everyone else. Then it is committed to filling that capacity just
like anyone else. Therefore, 12.5 percent ownership could not be
translated to 12.5 percent capacity of a regulated pipeline.
CHAIRMAN TORGERSON pointed out they have discussed owning a certain
capacity in a certain location if they wanted to do a large volume
user somewhere along the route.
MR. PERSILY replied that if the State was a contract carrier it
would have to bid for capacity, it would not get it by owning 12.5
percent. You could own it without having capacity or you could pay
the capacity like any other shipper without owning it. It is his
understanding that for a contract carrier, capacity does not come
with ownership.
CHAIRMAN TORGERSON thought that was correct for going from Alaska
to Alberta but a question arises as capacity is added inter state.
REPRESENTATIVE DAVIES asked whether shared risk wasn't a valuable
element.
MR. PERSILY thought it might be but if there's so much risk that
it's desirable to dilute it, then the project probably wouldn't be
built. If they feel there is small enough risk to go ahead and
build then they might not want to share the wealth by taking in
other partners.
The State might bring more to the table without taking on risk by
working federal angles such as accelerated depreciation. Because
producers have talked about fiscal certainty, the State could
certainly bring that to the table without being a partner
3:50 p.m.
Tape 01-24, SIDE B
REPRESENTATIVE DAVIES then asked whether the discount rate would be
affected to the extent that the State shares risk and would an
investing company would be looking at this?
MR. PERSILY said this was a question for Roger Marks but the
company would be putting less of their own money at risk.
REPRESENTATIVE DAVIES said transportation costs were of concern
with the oil pipeline with companies that both transport and
distribute. Some suggest that if the State had some ownership it
could insulate itself from that concern because it would benefit in
the same way. He asked if the State could shield itself if it had
some ownership and if so, what percentage ownership would be
optimal?
MR. PERSILY replied that if the State were absorbing 100 percent of
the transportation tariffs, the only way to offset that would be to
get 100 percent of the profit on the other end owning the entire
line. If the State took all the risk at the wellhead out but only
got 12.5 percent of the pipeline profits because it owned just 12.5
percent, it would come up short.
The gas line will be different than the oil line because it will be
regulated at a rate of return. No one foresees the problems that
were encountered with the oil pipeline in terms of cost shifting.
All Alaskans interviewed wanted the State to have a seat at the
table for the gas line because they thought there would be valuable
information available and they lacked that information on the oil
line and likely were cheated on the oil tariffs.
SENATOR TORGERSON said there were also discussions about the State
owning the oil line 25 years ago and it wouldn't have been a bad
investment. He agreed that he wants a seat at the table but isn't
sure what he will learn. Older studies say that the state shouldn't
be an owner in the line, but that we should issue senior debt and
he hoped their report would look at that concept.
The barrier to the pipeline is how to manage risk - whether it
be fiscal [indisc.] from the state, whether it be
environmental laws or whatever it is. Back to what
Representative Davies said, if you have more folks to share
that risk, your exposure is less. Not that that makes it a
good deal, because I agree with you on that statement, but at
some point in time, the report said that we should consider
not owning the line, but helping control the risk by issuing
senior debt if they had cost overruns.
CHAIRMAN TORGERSON said the oil pipeline started out costing $700
million and ended up being $10 billion. "They had a little bit of
cost overrun on the pipeline, so it was a very serious problem on
how to manage that cost overrun."
MR. PERSILY said that taking senior debt on this project might be
an attractive option for the state.
CHAIRMAN TORGERSON said, "Of course, that was before Exxon was
making $5 billion per quarter. So, they can pay for this in one
year's profit."
MR. PERSILY said, "They owe us some of that."
CHAIRMAN TORGERSON said, "About all of that."
REPRESENTATIVE GREEN said the state has been historically getting
about 8 percent.
MR. PERSILY responded that 8.25 percent is the long-term assumption
for the Permanent Fund.
REPRESENTATIVE GREEN asked, "Since the state is obviously satisfied
with a much lower rate of return, would that make a difference in
making an investment in a portion of the pipeline?"
MR. PERSILY said it might, but the Permanent Fund Corporation 8.25
percent long-term [indisc.] is much lower risk than the assessed
base they are working on. The state looks at how this senior debt
would compare to other debt the state is investing in as part of
its portfolio. "It might be very attractive."
CHAIRMAN TORGERSON asked if they decide to do a state ownership,
are they considering going through AIDA.
MR. PERSILY replied that they are looking at difference in tax
laws.
If the state owned shares in a corporation, which we do
through current [indisc.] other investments, we don't have to
pay any federal income tax, but what if there were limited
liability company or a limited partnership in those projects,
would any of those projects flow to the state? Would they put
us in a taxable situation that's any different if the state
owns it or if we set up a corporation similar to what we do
with the Northern Tobacco Securities Corporation, which is a
dummy corporation to shield the state if there's any default
on the tobacco bonds. But it really is a state corporation.
So, we'll be looking at those, too.
REPRESENTATIVE DAVIES asked if they were considering possible
conflict of interest. The Alaska Railroad has the citizens'
interest in environmental regulation handled by one state agency
and the citizens' interest in efficient economic operation by
another.
MR. PERSILY replied that was certainly possible, particularly after
all the spills on the Railroad last year.
The conflict issue is not an insurmountable one, such as
federal laws that would prohibit tax exempt financing. The
conflict is more of a public policy question to the
legislature and to the governor. Is this such a concern that
you don't walk into it or do you walk into it knowing the
issues, knowing what you need to avoid with your eyes open?
CHAIRMAN TORGERSON thanked Mr. Persily for his testimony and asked
if he could have a draft of his responses ready by the end of
December or early January before he released the consultants.
MR. PERSILY agreed to do that.
4:02
MR. BILL BRITT, Director, Pipeline Coordinator, reported that in
January, the Governor signed Administrative Order #187 that set up
the Gas Pipeline Office as a division of DNR and that he assumed
the directorship of that. In July, he testified before the
committee and gave a summary of the proposals that were in play.
None of that has really changed since that time.
Right now we are working with Foothills and the producer
consortiums. With Foothills we are working on advancing their
right-of-way applications. With the producers, it continues to
be permitting for various aspects of their feasibility
studies. Just as an aside, I am frequently asked about Yukon
Pacific's conditional right-of-way and that's being
administered in the Joint Pipeline Office as an existing
lease. Should they choose to prove that up to an unconditional
lease or otherwise move that forward aggressively, it might
[indisc.] to hear, but for the time being it's in the Joint
Pipeline Office.
Again, by way of background, we were provided with general
funding by LBA in July. We signed reimbursement memoranda of
understanding with Foothills in July and with the producers in
August. Our funding is through the ending of this calendar
year and we are setting up discussion right now with our three
funding sources for November and early December to discuss
what happens in the second half of this year.
Staff at this point consists of nine folks. Four designated
agencies have four additional people who have been hired and
will report this month. The three remaining designated
agencies are presently recruiting [indisc.] and that
recruiting in some instances is proving to be fairly
challenging. We have two assistant attorney generals assigned
to assist us. We have liaisons from BLM and MMS. We are
performing work with six other divisions of DNR - Mining, Land
and Water for land title work, Land Records Information for
land status work, the Office of History and Archaeology for
permitting support, DGGS for research, Oil and Gas for
technical assistance and the State Pipeline Coordinator's
Office continues to provide us with administrative support.
We're presently in the Atwood Building. We'll be moving toward
the end of the year. The letter of interest has gone out,
there have been I think around a half dozen expressions of
interest and formal proposals will be received and evaluated
next week.
The work planning with Foothills is probably the most intense
effort that we have ongoing. In July, I received from
Foothills a reconstituted application, which was a resubmittal
of those aspects of the tons of papers we received previously
that Foothills considered to be applicable to the existing
project and applications. We've met and identified high
priority items. Some of those are ongoing. A larger discussion
is over the process itself that will take place and those
things are now occurring about every other week in order to
try and pin this stuff down and keep it moving.
Doing ancillary stuff, we're working on our directory, numbers
and types of permits, not only for the state, but for the feds
and we will soon be moving to Canadians - [indisc] and private
land owners as well. Critical issues associated with each -
we're flow charting out these permits and beginning the
process of synchronizing them. We're outreaching federal
government in attempting to organize them since they are
having difficulties in organizing themselves. We've made
contact with the EPA, FAA, Coast Guard, Fish and Wildlife
Service, DOT, National Marine Fisheries, FERC, the FCC and the
Corps of Engineers and are getting information from each. I
expect Canada to be next. Probably toward the end of the year
and early next year I plan to travel to Calgary and Ottawa and
begin to make exactly the same sorts of contacts.
The next step is to begin working with local governments,
native corporations, travel counsels. We need to do work with
the [indisc] and the Railroad Corporation, both of which we
believe have land along the right-of-way. The University may
as well; that's now being checked. Legislative session is
coming up and I expect there to be probably more than one bill
relating to gas pipelines. So, I'm expecting that to take some
time. And in the next year I hope to begin a reasonably
serious outreach program.
CHAIRMAN TORGERSON asked what was going on with YPC. He heard they
had downsized their office.
MR. BRITT replied that he was meeting tomorrow with the Right-of-
way Chief of the Joint Pipeline Office to get a briefing on that.
They have submitted a request for about 17 minor realignments of
their rights-of-way, which is now being processed. He hasn't heard
that this is setting off anything large, such as a large deep
evaluation over any serious reconsideration.
CHAIRMAN TORGERSON asked him to email anything he finds out about
that. He asked where they are at in the Foothills process.
MR. BRITT replied that Foothills submitted a multi-volume
collection of exhibits that had been submitted previously that they
thought was applicable to the question that are asked in a right-
of-way lease application form. He is beginning the review.
CHAIRMAN TORGERSON asked what they were, stream crossing perhaps.
MR. BRITT replied that some of it is engineering work, a lot of it
is like an engineering design criteria handbook. The Federal Grant
of Right-of-way under Stipulation 161 required in the neighborhood
of 30 separate plans for a whole variety of topics from resources
in Alaska to locations and excavations - a broad variety of topics.
Some of those plans were mothballed.
CHAIRMAN TORGERSON asked if they were reviewing the engineering
studies to see what needed to be repeated.
MR. BRITT replied that they need to critique them and determine
whether they are adequate and if they are not, why. Perhaps they
are out of date or more information is needed or the world has
changed.
CHAIRMAN TORGERSON asked why they have more attorneys than
engineers.
MR. BRITT replied that attorneys are easier to find.
CHAIRMAN TORGERSON thanked Mr. Britt for his testimony and asked
him to keep the committee informed.
4:09 - 4:19 - BREAK
MR. JOHN LARSON, Geologist, U.S. Minerals Management Service (MMS),
said they have two off shore leases sales in Cook Inlet scheduled
for 2004 and 2006. Existing reserves in the Cook Inlet region have
been explored and are 2.564 TCF of gas, about a 12 year reserve if
gas in the area. There are about 6.6 years of oil reserves.
Further, exploration shows that the Cook Inlet Basin has
significant untapped natural gas resources.
Very few structures in the perspective OCS lease acreages involve
tertiary age formations that are so productive in the Upper Cook
Inlet. There are potential oil traps that can be seen on data, but
they don't have reservoir characteristics. Hypothetical coal bed
methane resources depend on the tertiary formations in Upper Cook
Inlet. He had projections done by the U.S. Geological survey that
he presented in a slide to the committee.
REPRESENTATIVE GREEN asked how they estimated their calculations.
MR. LARSON said they tried to use mean levels for their
calculations.
REPRESENTATIVE GREEN said that they seemed to be specific numbers,
but were still guesstimates.
MR. LARSON concluded that the Cook Inlet basin has significant
untapped natural gas resources and the MMS is proposing two gas
lease sales in the area in 2004 and 2006.
CHAIRMAN TORGERSON asked what their responsibilities were for the
state. Do they just guess at the resources from oil and gas numbers
or do they do research.
MR. LARSON replied that the estimates on his slides were generated
by the U.S. Geological survey, which has done some research.
CHAIRMAN TORGERSON asked about Phillips' drilling.
MR. LARSON replied that their target depth as a vertical concern is
not that deep. "It's just that they're having to drill from on
shore a long distance off shore in order to get to it."
REPRESENTATIVE GREEN asked if the estimates were primary reservoirs
or were they oil associated.
MR. RANCE WALL, Regional Supervisor, MMS, replied that his
estimates were the oil and gas plays they had analyzed in the
northern part of the basin. It consisted of an interlude of a lot
of oil; those have very little associated gas with them. There is a
gas play in an interval above that which is nearly all gas. In that
case, one wouldn't think about using the gas for oil
pressurization.
REPRESENTATIVES GREEN asked if the gas would be available soon
after development.
MR. LARSON said that was correct. "Some of the deeper oil would
have associated gas with it dissolved in the oil."
REPRESENTATIVE DAVIES said he thought the Inlet resources would be
all used up in 17 years.
CHAIRMAN TORGERSON asked how close their Cook Inlet estimates were
in the past.
MR. WALL responded that they started out being a lot bigger than
they are now.
CHAIRMAN TOGERSON asked if they were sure that the 10 holes that
were drilled in the OCS area were uneconomic so the chances of
leasing in Shellikof Straits are probably slim.
MR. WALL responded that was correct. He also said the Five-year
plan is not official, it's just proposed.
REPRESENTATIVE DAVIES asked if there were any estimates that might
significantly alter the numbers.
MR. WALL responded that it depended on what decisions were made on
what to offer as they go through the NEPA process. One of the key
issues will be what the State wants them to do.
CHAIRMAN TORGERSON said the tri-borough commission (Kodiak,
[indisc] and the Kenai Borough) met in the early 90s on how they
wanted to see development go forward. He thought that most of that
information would be the same, like restrictions in the fishing
areas and that kind of thing.
SENATOR OLSON asked if there were known reserves on federal lands.
MR. WALL responded that he thought there were, but they don't do
assessments for that area. He suspected there would be potential in
some areas if they were offered.
CHAIRMAN TORGERSON said he thought they did the work for BLM.
MR. WALL responded that they work with them.
CHAIRMAN TORGERSON asked if there were any further questions and
there were none. He adjourned the meeting at 4:45 p.m.
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