Legislature(2001 - 2002)
03/07/2001 03:42 PM Senate RES
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* first hearing in first committee of referral
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= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE RESOURCES COMMITTEE
March 7, 2001
3:42 p.m.
MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Pete Kelly
Senator Kim Elton
MEMBERS ABSENT
Senator Drue Pearce, Vice Chair
Senator Rick Halford
Senator Robin Taylor
Senator Georgianna Lincoln
COMMITTEE CALENDAR
Overview: Alaska North Slope LNG Sponsor Group by:
George Findling, Manager, External Strategies, Phillips Petroleum
Steve Alleman, Commercial Manager, Alaska North Slope LNG Project
ACTION NARRATIVE
TAPE 01-19, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Senate Resources Committee
meeting to order at 3:42 pm and announced an overview presentation
by the Alaska North Slope LNG sponsor group made up of Phillips,
BP, Foothills and Marubeni.
MR. STEVE ALLEMAN, Phillips Petroleum Co., said this group was
formed to develop an economic and commercially viable LNG project.
ARCO went out in 1997 after the Stranded Gas Act passed and began
to look for sponsors. The current sponsors are:
· Phillips Alaska - 30%
· BP Exploration Alaska - 26%
· Foothills Pipeline - 25%
· Marubeni Corporation - 19%
In August 1998 they spent $12 million on a redesigned engineering
design. After that was completed, they still didn't have a viable
project, but they had enough indication that it made sense to keep
going on it. Now they are focusing more on the commercial aspects
of this project or their Stage 2 effort that began in September
2000.
MR. ALLEMAN said that a separate entity would buy gas on the North
Slope. They would build a gas treatment facility on the North Slope
and an 800 mile pipeline to either Anderson Bay in the Port of
Valdez or to Nikiski in Cook Inlet. He stated, "At that point, we
would build a LNG manufacturing facility, the marine facilities,
the storage facilities, etc. and ship LNG to either Japan, Korea,
Taiwan, or to the Lower 48 through Baja California."
He said their market updates and inputs are perpetual and that
Marubeni, a Japanese trading company that is doing business
throughout east Asia and the world, gives Phillips continuous
feedback through their market liaison office specific to the North
Slope LNG project. Phillips and BP also have people in the field
including Tokyo, Taiwan and China.
For the LNG project to move forward two things have to happen. It
has to be commercially viable, having the right size to
sufficiently advance and develop a project, and be competitive with
other new projects. The market also has to be ready for Alaska gas.
MR. ALLEMAN said they believed that there is additional new demand
and they believe the existing LNG projects with incremental
expansion will go first. Then the most competitive new LNG projects
that can provide secure supply and can deliver when the market is
ready will be the next into the market place. "Obviously, we would
qualify under the competing LNG projects, if we can make ourselves
cost competitive at the end of the day."
MR. ALLEMAN said their first market analysis was completed in
spring of 1999. They have looked at potential around Japan, Taiwan
and Korea in their stage one and two efforts. They have looked at
emerging markets in China and India. The U.S., Mexico and West
Coast will be the focus of their Stage 2 efforts as they go
forward. Their analysis broke down the different energy uses, like
nuclear, coal vs. LNG, etc., in various countries.
MR. ALLEMAN said the market is fiercely competitive and, "We see
that there is about 60 to 80 million tons per annum (MTA) of
potential projects out there." Growth rate is subject to some
discussion, but their view is that it is 30 - 40 MTA by 2010. "So
you've got 20 - 40 MTA of growth being chased by 60 to 80 Mt of
potential projects."
MR. ALLEMAN said that there would probably be some downward
pressure on price, as Mr. Muraki also noted and that there would be
some push to go to shorter contracts and spot deliveries, which is
counterintuitive to what they are trying to accomplish with a
highly capital intensive project. Like Mr. Muraki, Mr. ALLEMAN felt
the lion's share of the projects will continue to be the longer
term LNG contracts. "For us, the smaller market entry provides
better probability."
They would also have to compete with other opportunities for Alaska
gas if they develop. One of those would be with U.S. gas demand.
If the Lower 48 pipeline happened, we would have to be
competitive in some fashion with the wellhead value they
could give for that type of project or add some other
value that wouldn't necessarily be there - such as
increasing production earlier that you could ramp up on a
gas line project.
MR. ALLEMAN reverted to explaining their stage one effort and
some of the results they came up with.
Our market focus was that we needed a smaller market
entry project. We needed to be able to get our foot in
the market place and grow with the market and certainly
expand, if we possibly can at the end of the day. But it
needed to be smaller than the 14 - 15 MTD they were
initially looking at from the feedback they were getting
from the market place. We didn't just cut it in half,
something a commercial guy like me would do, but the
engineers went back and totally redesigned our project to
defer our costs where they could (I'll show some examples
in a minute), to minimize our preinvestment and to help
improve our net present value economics at the end of the
day. So we walked with a better economic view with our
smaller market entry project than we had initially. We're
still not there yet, but we're looking better than we did
walking into that.
What that does is it improves your market entry
probability for your LNG; its obviously significantly
reduces the capital costs. Instead of talking $12 - $15
billion, we were talking $6 - $7 billion, but yet it was
still expandable to a 14 MTA project. So our mandate
walking into this was to become economically sufficient
at the 7 - 8 MTA range, even if we can never get into the
market with a 14 at the end of the day. So we have a
stand-alone project at that point. That's been our goal
going forward from there.
With their larger project, they are looking at needing a steady
addition of LNG sales over several years. With a small project, if
they can get in and out with two to three years of ramp up, they
feel they would be in better shape and actually have to seek
smaller volumes after the first year.
Their engineers spent $12 million on a very in-depth analysis in
five categories:
· System integration and smaller project design
· Pipeline route/LNG plant and marine terminal site
· Pipeline design and construction
· LNG plant/marine terminal design
· Gas treatment plant
MR. ALLEMAN explained that they were using three different themes:
· Significant external input from experts
· Workshops incorporate both internal and external experts
· Both route/sites advanced - if they did work on one, they did
work on the other (Nikiski and Valdez)
He said they would present a lot of their findings at LNG 13, which
is held in South Korea, an industry-wide conference that happens
every three years.
MR. ALLEMAN summarized their effort saying they had 26 outside
contractors and consultants; stage one was completed on time and
under budget and exceeded their engineering design expectations.
He said he is often asked about the pipeline route and LNG plant
sites and if they are still looking at two sites.
For us the pacing item going into this is to develop a
cost competitive project at either location. If neither
site works and neither project is doable at the end of
the day, and certainly we've developed the engineering
work and design work for both locations, why do we keep
looking at two sites? There are potential advantages to
both. At Anderson Bay, certainly you have the existing
TAPS pipeline corridor and may reduce your permitting
time. From the Nikiski side of it, we have existing
markets that are there; we have growth opportunities.
Existing markets include the instate gas market where 70
- 75 percent of the people live along the pipeline
corridor. And we have existing infrastructure such as the
existing Kenai plant that's there that we could share
some synergies with.
MR. ALLEMAN said they did a very in-depth analysis of permitting in
stage one. Phillips and BP have Alaskan expertise within their
companies with permitting. Foothills has world-wide permitting
expertise. They have visited the JPO and the RCA and he has gone
with them to Washington D.C. to talk to the Department of Energy
and the Department of Commerce. After all this analysis, their
conclusion is that both Nikiski and Anderson Bay can be permitted
at the end of the day. If that permitting can be done within their
current market timing needs, they could get the project done by the
end of the decade. "It's also our opinion that any existing
Anderson Bay permits will also require extensive work and costs to
perfect, at the end of the day."
MR. ALLEMAN added that the Nikiski route does not run through
Denali National Park.
Number 1300
MR. ALLEMAN recapped that they were very happy with the work they
had done in stage one, but they still weren't economically viable
and nor were the cost competitive with other new projects. However,
they saw other opportunities on the horizon. There was a chance of
a Lower 48 project happening and they saw some potential synergies
there, so they moved on to stage two, which they started in
September 2000. It is mostly focused on the commercial aspects.
They have a 12 - 15 month time period and a budget of about $3
million. They have considered the value of a public entity and they
are looking at risks: the impacts and potential mitigation
strategies. They are looking at how their projects "stack up" to
all the others around the world. They have a permitting analysis
effort ongoing. They have spent over $300,000 finishing up the
Environmental Assessment for the Nikiski Route, since that had not
had as much work done to it. When they finish with permitting at
the end of this stage, they intend to have a go-forward strategy
for working with the various agencies to move the project forward
crisply from either location.
MR. ALLEMAN continued saying that they are working on optimization.
The $6.8 billion project is now a $6.5 billion project including
the ships. They "knocked off" $400 million mostly in design work
they continue to do on the gas treatment facility. Another part of
the savings came from the pipeline and more from the shared cost of
the jetty at Nikiski. Without ships, they are talking about $4.9
billion and are still trying to identify other savings. They will
be looking at shared costs with the Lower 48 pipeline. They "took a
hard look" at public entity valuation, primarily to see if there
was some way for a public and a private entity to work together to
have a more economic project at the end of the day. They see no
compelling advantage right now to joint public private projects.
That doesn't mean that a public project couldn't go forward and
have tax savings and it doesn't mean that a private project
couldn't go forward with financing and still work toward a
profitable project; but the two combined, generally speaking, the
benefits that would be passed on by the public entity to the
private entity would be taxed. So that somewhat negates itself.
Even with the public borrowing rates they might see, those would
most likely be offset by the reduction of interest and depreciation
that could be claimed.
He commented on market engagement saying that:
We live in the market. We still have our representatives
working there, both through our individual companies and
through our market liaison office. Our marketing tack at
this point is talking to the market about our progress.
We don't have anything to sell them until we have a fully
defined cost competitive project at the end of the day
and until we have figured out a way to be competitive
with other green field projects around the world. So,
when we go to the market we do update them on what we've
been doing. Every market that we would plan to contact in
East Asia received a letter from us when we came up with
our market entry, our smaller project that was hand
carried to the markets. We had that kind of discussion
with them. When I go over to Tokyo, we sit down with some
of the bigger players and have discussions, but it's
discussions long the line of "here's what we're working
on and here's what we're headed toward."
This is a very sophisticated market place. They
understand very well what it means to be cost competitive
and they are very cognizant of what the pieces are for us
to become cost competitive at the end of the day.
Certainly, we'll continue to work on our other market
analysis efforts that I talked about: the competitiveness
with other projects and the non traditional markets in
the U.S. and Mexico.
Turning to economics, MR. ALLEMAN said:
For us, the key is to be cost competitive with other East
Asian LNG projects. I can't say it enough. It's the most
important piece for us for making it happen and it has to
happen in a sufficient economic rate of return. Our
project in our eyes is not yet cost competitive and it's
not economic on a cost of capital basis as we look at it
for the expected risks that we would have to take for
this large of a project. So we still have work to do on
it. We haven't walked away from it by any stretch of the
imagination. We're still trying to optimize. We're still
trying to be innovative.
MR. ALLEMAN said they trying to come up with meaningful fiscal
modifications. He said that project economic assumptions must be
saleable. He showed the committee a graph of the $6.5 billion Capex
case. Their gas treatment plant gets about $1 billion. The big
issue for them is the 800-mile pipeline, for about $2.4 billion,
and compression. Their LNG facilities at Nikiski will cost $1.6
billion and about $1.8 at Anderson Bay. The difference is that
Anderson Bay is a very mountainous region versus Nikiski, which is
very flat and easy to access. The Anderson Bay number does not
include any cost for a spur line to the Anchorage Bowl or any
permitting that might be required to build that spur line there.
Shipping is about $1.6 billion of the total.
MR. ALLEMAN showed the committee a list of three projects and their
estimated costs to see how they compare. He said he didn't know
what the front end development costs for the projects are. Most of
the costs have to do with oil production and not with the LNG
production.
Number 1700
SENATOR ELTON said a previous presentation projected the cost of an
LNG carrier to be $120 - $150 million. Mr. ALLEMAN had budgeted
$6.5 billion including ships and $4.9 without ships, which works
out to significantly more than $120 - $150 million per ship. He
asked what he was missing or were they disagreeing with the earlier
numbers.
MR. ALLEMAN answered that the $1.6 billion is for 8 ships and they
are using about $200 [million per ship], which they think is
conservative. He thought the price of ships would move up as theirs
is more LNT coming into the market place as competition increases.
SENATOR ELTON asked how many ships they were talking about.
MR. ALLEMAN answered they were talking about 7 - 8 million tons,
about one ship per million tons.
He added that the reason Nikiski is a bigger project is because of
the process called extended "inflash." They can flash the gas off
the end of the system and actually make more LNG, because it's auto
refrigerant. It's like spraying a paint can, but they need to have
some place to put it. So there has to be some other sales market.
It has to be either an in-state market or to some other facility.
Nikiski is the only place they have the infrastructure in place to
do that. So that's the only place they feel they can make more LNG
at the end of the day.
SENATOR ELTON asked what happened with the synergy of an Alcan
route and how much money would they save if there was simply a
valve, so the only thing the LNG project would be responsible for
would be a pipeline from Fairbanks or where the gas starts moving
east down the Alcan.
MR. ALLEMAN answered that right now they are looking at what a
shared cost would look like. The Lower 48 project is still looking
at what their pipeline would look like at the end of the day. Even
if they didn't have the capital cost for that pipeline, they would
still have to pay a toll.
SENATOR ELTON clarified that as an owner of the gas, they would be
paying a toll whether it's going down the Alcan or going to a valve
near Fairbanks.
MR. ALLEMAN answered that this is a separate entity project that
buys gas on the North Slope from the producers.
SENATOR ELTON said that he was seeing tolls as transportation costs
and that cost is there regardless of whether that gas ends up on
the coast or in the Lower 48 market.
MR. GEORGE FINDLING, Phillips Petroleum, said the project they
developed is called a stand-alone and those are the cost estimates
they have. "If you assume there is a Lower 48 pipeline, and make
the assumption that follows the southern route, and what we
actually install is the pipeline from Fairbanks south, the pipeline
that goes from Prudhoe to Fairbanks needs to be big enough to
handle both the gas to the Lower 48 and to our project. If the
Lower 48 project builds that pipeline, basically what we experience
is a toll that we have to pay to move that gas through that now-
larger system capacity. So there's a cost burden for that distance.
It's either a capital cost to us or a toll, if we have a sharing
arrangement.
CHAIRMAN TORGERSON asked if they anticipated being identifiably
different between the Phillips that owns the pipeline going to the
Lower 48 and the Phillips that might want to send LNG somewhere.
MR. FINDLING said he wasn't sure how to answer that. They are
visualizing a unique commercial structure for the sponsor group
where they buy the gas at the wellhead and then pay for the
facilities, make LNG, and sell it in the market place. "Since
Phillips sits in the sponsor group in that role, we have another
role later on as a wellhead seller."
CHAIRMAN TORGERSON asked if they anticipate their current partners
being the same partners in the LNG project.
MR. ALLEMAN answered that is the structure and the assumption they
are working under right now.
CHAIRMAN TORGERSON said he wanted to go over the permitting again
and asked if they got the go-ahead, how long would it take before
either project could come together.
MR. ALLEMAN answered that he didn't recall the total time, but it
could happen before the end of the decade for either project. There
is a difference in timing between the Anderson Bay and the Nikiski
route that is built into this. The base case is 12 - 18 months
longer to do the Nikiski route than to do the alternate route. It
could be longer or shorter than that. "There is no exact science to
permitting."
CHAIRMAN TORGERSON asked about the LNG fundamentals slide under the
expansion and if he was talking about the Nikiski plant.
MR. ALLEMAN said he was talking about expansions on his list of
blue. The Northwest shelf would be an expansion project.
CHAIRMAN TORGERSON asked about the list of competitive projects and
if he had included shipping costs.
MR. ALLEMAN answered that it didn't include shipping costs. The
averages were what the Oil and Gas Journal put out. It said that
the $400 million per million tons was moved down to the $250
million range per million tons. Their personal look was somewhere
from $100 - $250 million range. That would include the LNG plant,
the marine terminal, but would not include the ships. In their
case, it would include an 800-mile pipeline. Other projects do have
pipelines involved.
CHAIRMAN TORGERSON noted that the fertilizer plant was missing.
MR. ALLEMAN replied that they have looked at in-state gas sales as
just assumptions of increments of $100 million per day, $200
million per day, etc. added into the market. They haven't tried to
identify specific locations. They realize there is a need in south
central Alaska for growth gas and a need for gas for the other
facilities down the road.
CHAIRMAN TORGERSON asked if anyone had approached him to be a
partner.
MR. ALLEMAN answered no.
Number 2240
SENATOR ELTON asked how much he anticipated local markets being.
MR. ALLEMAN answered about 10 percent of the gas would find a local
market.
CHAIRMAN TORGERSON asked if he knew of any other investment
incentives that were being offered by any other gas producing
nations that would make a project look more favorable.
MR. ALLEMAN answered that he wasn't aware of anything.
CHAIRMAN TORGERSON asked if Japan was still financing projects
around the world and building LNG boats and operating them.
MR. ALLEMAN replied there was the XM Bank issue and they may have
more opportunity to give favorable financing in certain situations.
MR. FINDLING added that you have to be a little cautious about low-
interest financing from foreign countries. Sometimes they will give
a low interest rate, but they want to be paid back in their
currency, not in dollars. That shifts the currency risk, which
makes a big difference in the cost of the loan.
CHAIRMAN TORGERSON said Japan used to front-end-load whole projects
instead of financing them. Mitsubishi was a 70 percent financer of
the Unocal plant, for instance. He wanted to know if there were any
incentives like that going on in the world. He heard there might be
in an Australian LNG plant.
MR. FINDLING said buyers first want to see a cost competitive
project and then they look at special ways to make the project
work.
CHAIRMAN TORGERSON asked if his stage two timeline was the same as
the consortium on having answers to all the questions.
MR. ALLEMAN answered, "The LNG project plans to finish this block
of work by November of this year."
TAPE 19, SIDE B
Number 2400
MR. FINDLING pointed out that the extent to which they have
information available, they can get it to the committee before that
end date. He hadn't seen a schedule of plans.
MR. ALLEMAN said they made some of their own assumptions enabling
them to structure what pipeline size and cost would be and
establish tariffs based on other projects, like the Alliance
pipeline.
CHAIRMAN TORGERSON asked if they believe they are just as
competitive or more competitive than the pipeline to the Lower 48
California market.
MR. ALLEMAN answered that he wouldn't say they're as competitive as
the pipeline. They just see it as another potential market.
CHAIRMAN TORGERSON asked him to clarify, "to achieve meaningful
fiscal modifications, particularly federal."
MR. ALLEMAN explained they would certainly have discussions with
the State of Alaska. There are also some larger opportunities on,
for instance, accelerated depreciation and those types of issues
that would involve discussions with the federal government.
SENATOR ELTON said one chart indicated they had 60 - 80 MTA of
potential projects for some 20 - 40 MTA of growth and it seems when
they throw in the U.S. market with their expectation of a much
higher demand, that would take some of the risk out of an LNG
project, if they have the ability to deliver to Baja, California.
MR. ALLEMAN responded that he didn't know if Baja reduced the risk.
There will be more demand in the U.S. market, but it all gets back
to the overall economics of it, like what is the sustainable price
going to be into the Lower 48 and what other gas is going to come
on within the U.S. and other imports.
MR. FINDLING added that they were framing the concept of market
optionality, where you have optional markets for your gas. This is
a good thing, but the question they struggle with is how to
quantify the benefits of it. They sense that they don't want to
foreclose any market optionality right now. They want to create it
and the value will make its appearance, if it has some.
SENATOR ELTON asked if part of their stage two analysis looked at
those optional markets.
MR. FINDLING answered that they didn't have an explicit goal of
trying to quantify market optionality in stage two, but he thought
it was a topic in the backs of people's minds.
CHAIRMAN TORGERSON asked what size Nikiski is now.
MR. ALLEMAN answered that it is 1.2 MTA.
CHAIRMAN TORGERSON asked if the smallest they were looking at now
was 7 - 8 MTA.
MR. ALLEMAN explained that the Nikiski plant was about the smallest
in the world.
CHAIRMAN TORGERSON asked if that plant was expandable.
MR. FINDLING answered there was some expansion potential up to the
.3 or .4 range, but it would require bringing in another train or
trains.
CHAIRMAN TORGERSON said in either location, they are basically
looking at a new facility.
MR. ALLEMAN responded that there are shared costs that they have
already identified, like the jetty, some storage sharing and the
existing plant.
CHAIRMAN TORGERSON asked if he thought either project could be
expanded to 14 MTA.
MR. ALLEMAN said that was correct.
SENATOR ELTON asked if the 7 MTA an increment in Nikiski included
the 1.2 MTA coming from it currently.
MR. FINDLING responded that their figures do not assume the
projects are mixed at this point. The existing Nikiski plant is
Nikiski. The other project assumes a brand new facility on a brand
new location. So they are talking about an increment to Nikiski.
CHAIRMAN TORGERSON asked if they need gas in Nikiski soon.
MR. FINDLING answered:
We are in pretty good shape through 2009, which is the
time period for our export license. The question they are
getting is about the Cook Inlet gas situation. We don't
really see any reason to sort of push a panic button
here. You have to make an assumption that the Cook Inlet
Basin is somehow different from other resource basins. In
the 70's there were enough reserves to produce for 60
years. It's the so-called reserves to production ratio.
These days in Cook Inlet we're at a reserves to
production ratio of about 12 years.
MR. FINDLING explained when reserves come down in resource basins,
exploration starts and pretty soon more resources are found. "We
don't see anything that says that's going to be different in Cook
Inlet." The U.S. ratio as a whole in the gas market is eight years.
There's a longer period of reserves in Cook Inlet right now than in
the Lower 48.
CHAIRMAN TORGERSON asked what the committee could do to help.
MR. ALLEMAN said he appreciated the offer, but for them, it's
staying the course and trying to find the synergy that works for
them "at the end of the day."
CHAIRMAN TORGERSON adjourned the meeting at 4:40 p.m.
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