Legislature(2001 - 2002)
11/08/2001 09:00 AM Senate 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 STATE LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
November 8, 2001
9:00 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 Scott Ogan
Representative John Davies
Representative Mike Chenault
Representative Hugh Fate
HOUSE MEMBERS ABSENT
Representative Joe Green, Vice-Chair
Representative Brian Porter
Representative Reggie Joule
COMMITTEE CALENDAR
Department of Natural Resources, Oil and Gas Division
Bill Van Dyke, Petroleum Manager and Tim Ryherd - Geologist
Will Nebesky - Cook Inlet gas usage and demand
Agrium, Inc.
Chris Tworek, Vice President, Supply Management
Phillips Alaska, Inc.
George Findling, Manager, External Strategies and Scott
Jepsen, Manager, Cook Inlet Asset
UNOCAL Alaska
Dan Thomas, Land Advisor
Citizens Initiative for the All-Alaskan Pipeline
Scott Heyworth, Chair
Foothills Pipeline, Ltd.
John Ellwood, President
ANGTL Co.
Richard Peterson, President/CEO
ENSTAR Natural Gas Company
Tony Izzo, President
Evergreen Resources
Mark Sexton, President/CEO
Committee meeting
ACTION NARRATIVE
TAPE 01-25, SIDE A
CHAIRMAN JOHN TORGERSON called the meeting to order at 9:00 a.m.
and gave a brief introduction.
MR. BILL VAN DYKE, Petroleum Manager, Division of Oil and Gas,
Department of Natural Resources (DNR), said he would cover the gas
reserves and production, Mike Ryherd would cover would address
exploration for gas in the Cook Inlet area, and Will Nebesky would
cover the gas supply and demand fundamentals and gas value. He
referenced a map in their 18-page packets and explained each of the
slides, which indicated Cook Inlet gas production and reserves: 217
trillion cubic feet (tcf) was net production; 201 tcf was sold and
16 tcf was used in field operations - no big changes from previous
years. Most of the gas came from the old gas field that was
discovered in the 1960's. He said there were no surprises on the
reserve side. The numbers are down a little bit from the previous
year, but that's mainly due to production. He explained:
We haven't added any significant new reserves this year
from new discoveries or new developments and with round
numbers, 200 bcf [billion cubic feet] production, the
number naturally drops year to year until we add new
reserves. That hasn't happened yet, but I expect that
picture to change over the next decade. We can start
adding some reserves to that column rather than just
subtracting production every year.
An unidentified speaker asked if this was his estimate of
recoverable reserves or total reserves.
MR. VAN DYKE replied his definition of reserves is the amount of
recoverable gas remaining to be produced. Of the remaining 2 tcf in
Cook Inlet, he said:
It's important to understand what this table is and the
assumptions that go with it and some of the caveats. The
dates are hypothetical. I don't know when certain
operations are going to shut down, when and why. I just
picked things. The dates aren't unreasonable, but they're
not based on gas supply contracts or specific reserve
estimates. The consumption numbers are based on how much
gas is being consumed today for LNG, the Agrium
operation, for field operations.
He explained his slide further. He assumed that Agrium used 55
bcf/year, LNG used 80 bcf/year, and field operations used 15
bcf/year. Assuming those three industrial uses continue, he
theorized how much gas is left for the utilities.
If all the industrial gas users and oil fields shut down in 2009,
there would be about 1 tcf of gas left for the utilities, a 17-year
supply. He noted, "That's great for the utilities, but it's pretty
harsh with respect to the industrial operations. That's scenario
one."
He walked the committee through scenarios two and three. One
scenario assumes that Agrium continues operations like it does
today until 2015 [so that] LNG is extended out to 2015. He told
members, "That scenario breaks the bank. There's literally no gas
left for the utilities. In fact, the utilities sort of quit burning
gas two years ago if you want to supply that much gas to the
industrial uses."
He said scenario four is an exploration success case in which
another tcf of reserves is added. It assumes there's going to be
discovered gas, it's going to be produced and it's going to be
produced within that time period, which is a leap of faith.
MR. TIM RYHERD, geologist, Division of Oil and Gas, Department of
Natural Resources (DNR), said he would talk about exploration for
oil and gas supplies in Cook Inlet. He also used slides with his
presentation showing where exploration activities are occurring
right now and by whom. He noted that exploration is on the
increase.
He said that basically exploration activity in the Cook Inlet was
done in the 60s and he showed a graph of the exploration wells for
oil and gas drilled by year. The gas in Cook Inlet was discovered
in the process of looking for oil. He pointed out that in the last
four or five years four exploration wells were drilled per year and
this year it looks like there will be more.
9:23 a.m.
MR. WILL NEBESKY, Commercial Analyst, Division of Oil and Gas,
Department of Natural Resources (DNR), said he was going to discuss
the composition of the demands for gas produced in Cook Inlet and
pricing relationships for gas distribution. He started with a chart
of historic patterns of gas demand in Cook Inlet and pricing
evaluation slides and then went to the outlook. Five major
components were represented. LNG, which represents about 36 percent
of the total consumption of gas in Cook Inlet, has been fairly
steady over the past five or more years. The ammonia-urea
consumption of gas represents about 24 percent of the total and
that's been fairly steady also. Next are gas utilities, essentially
the Enstar system, plus some gas consumption to direct users such
as Tesoro and that currently stands at about 13 percent of the
total and has been steady also. Power generation with Chugach
Electric Association and the Matanuska Electric Association
accounts for about 17 percent of the total demand. Together, the
gas utilities, power generation and utilities account for about 30
percent of the total. The last category shown is field operations
and other gas consumption for about 9 percent. Field operations use
of gas has come down quite a bit and flaring has been cut back.
MR. NEBESKY next showed a chart comparing gas produced in Cook
Inlet with some Lower 48 benchmarks from August '97 through August
'01. The next charts showed royalty values. He pointed out that the
values are also driven by settlement agreements that the state has
with producers, which supercede the lease. He said the balance
between demand and supply of gas is interrupted around 2003 or 2004
pending no further discoveries. If 1 tcf of gas is discovered
between now and 2004 and comes on line, that will add 4 to 5 years
of supply that is capable of meeting the demand delivery amounts.
In 2009, the imbalance between supply and demand kicks in again.
Regarding pricing relationships, he said the Regulatory Commission
of Alaska (RCA) recently approved a proposed contract agreement to
supply gas to Enstar from UNOCAL, which includes indexing the price
to the Henry Hub. He said they are seeing signals of rising prices
in Cook Inlet by virtue of those contracts.
The next chart compared gas supply and demand for various
situations in Alaska. The Prudhoe Bay Unit is recycling about 8
bcf/day. The proposed gas line [indisc.] and the state royalty
share of a major gas sale greater than 4 bcf/day would be .5
bcf/day, which is not too different from the total area-wide demand
of Cook Inlet, which is about .6 bcf/day.
TAPE 01-25, SIDE B
9:45 a.m.
REPRESENTATIVE DAVIES asked what kind of use he assumed in the last
chart.
MR. NEBESKY replied basically uses for space heating and
electricity generation. He stated, "Right now there's a modest
amount of natural gas use in Fairbanks based on a small scale local
gas distribution company effort. His estimate is based on the
potential for expanding and reaching a fairly extensive community-
wide space heating demand for Fairbanks."
REPRESENTATIVE DAVIES asked him to estimate the total demand for
Fairbanks.
MR. NEBESKY answered at least 50 percent.
SENATOR OLSON asked, regarding all the utility cost spikes in slide
17, if he foresaw legislation coming that would stabilize that
volatile market.
MR. NEBESKY replied:
In the RCA's decision, the public advocacy section made a
proposal that would involve a different kind of pricing
mechanism that would take into account local Cook Inlet
prices to a greater extent than the UNOCAL/Enstar
contract. The RCA decided against that proposal. I can't
speak for the RCA, but the volumes of gas that would be
involved in that particular supply contract would be one
piece of a bigger pie of gas supply from the Enstar
system, which would involve a variety of pricing points
and mechanisms that, banded together, would tend to
provide some stability and, over time, some of the
contracts of earlier vintage will expire and be replaced
by new ones. This is an example of a new one.
SENATOR OLSON responded, "I guess my real question is what kind of
effect will that have on production."
MR. NEBESKY said he knew it was a major incentive for UNOCAL to
explore. He noted that exploration activity in Cook Inlet was
stepped up, which he believes was due to the anticipation of higher
prices.
REPRESENTATIVE OGAN asked at what date we couldn't meet gas
demands.
MR. NEBESKY replied in 2004.
REPRESENTATIVE OGAN asked what will happen then.
MR. NEBESKY said he anticipates that the export license that
permits LNG exports will probably undergo a stringent review by the
U.S. Department of Energy. The LNG exports are licensed to continue
through 2009. In the event that LNG operations cease to export gas
additional volumes might be available for local use. He said, "If
you take the LNG component out of the total demand picture, you
drop consumption of gas in Cook Inlet from 2010 bcf/year to perhaps
130 to 140 bcf/year less."
He said the likely outcome of the forecast is continuing upward
pressure on prices, which is going to put economic pressure on the
industrial uses of gas. He added:
It's going to affect the economics of both fertilizer and
LNG production, and electric power generation and local
utility gas use for [the] state's heating will also be
affected and we are actually in the course of looking
more closely into the instate demands for gas. Currently,
we have a contractor employed with the division to
investigate instate demand uses and part of that analysis
is to examine the sensitivity of consumption to changes
in prices - something we hope to get a better sense of.
REPRESENTATIVE DAVIES asked a question about page 18, but his
question was indiscernible.
MR. NEBESKY responded that he assumed they could get the gas out of
the ground fast enough:
The gas is there as far as gross reserves, but you can't
get enough out in a given year. That's the difference.
Just one comment on the graph that's up there - the gray
area does not assume some of the production from some of
the areas that are under development today and so it's a
pretty conservative production forecast, because we know
that Marathon is developing new areas today - Anadarko,
Aurora, UNOCAL is doing some work. It was based on some
smaller pools on production soon, which will extend the
gray area on that graph outward. We really think that one
way or another, there will not be a production shortfall
in 2004 and 2005…
REPRESENTATIVE DAVIES asked what the typical utility pays for gas
now, including delivery.
MR. NEBESKY replied that the red line in cell 13 shows the average
royalty values for gas dispositions to electric utilities, "So it's
about $2.50 currently."
REPRESENTATIVE FATE said he heard Mr. Nebesky say the consumption
in Fairbanks is .045 bcf. He asked if he modeled demand given a
flat production without any other gas coming in from the North and
had he done any modeling for future demands of the rest of the
state.
MR. NEBESKY replied that effort is currently underway:
As part of the study of instate gas demand, we're
exploring the potential demand and the potential for gas
related fuel switching opportunities in communities in
the proximity of the pipeline route as well as
communities further away that could in fact utilize a
propane product generated from processing of natural gas.
We're exploring the nature of demand in smaller
communities as well as Fairbanks in and around the
Fairbanks area and the different kinds of energy options
that may be available that are tied to the major gas sale
and the gas line project. We hope to have more on that
topic before the end of the year.
CHAIRMAN TORGERSON said:
I'm not totally thrilled by RCA's decision to tie this to
the Henry Hub. For Kenai Peninsula folks, with the
industry base use of gas, and now to have it reflect
sales in the Lower 48 instead of Cook Inlet, puts our
industry potentially in jeopardy if we are a long term
high priced…. We're reminded constantly - in fact I got a
note from past Mayor [indisc.] that Agrium is our largest
employer and a great corporate citizen, as well as
Phillips. Those industries are on the line. I'm not sure
the RCA in their decision, just based upon their wording
that they want to drive prices up so it will spur
production is the proper way to work with supply and
demand curves through a regulatory agency. I can see a
prudent contract and other merits, not on the merit that
we want to drive the price up. Having said that, I
wondered if you can chart out the price using the
historical price in the 92 slide, using the Henry Hub
pricing and let us see the difference in that with Agrium
and LNG so we could see what that increase would be.
CHAIRMAN TORGERSON said he was trying to understand what using the
Henry Hub would mean regarding what the legislature can do, if
anything.
An unidentified representative of the Department of Revenue said
Enstar's demand substantially swings between summer and winter,
"So, they are a hard customer to satisfy."
CHAIRMAN TORGERSON said that a low commodity like fertilizer would
not survive high prices, unless one could drive the commodity
market up to compensate.
10:02 - 10:11 a.m. BREAK
MR. CHRIS TWOREK, Vice President, Supply Management, Agrium, Inc.,
said the simple message behind his presentation is:
Agrium makes a significant contribution to this community
and we'd certainly like to expand and maintain that
contribution. We realize we are in the international
commodity business and it requires us to be more
efficient to find ways of expanding our production. We
realize this is a very complicated situation on how to
improve our situation here. We would like to propose
solutions and not just talk about problems. We think that
there is a partnership that can be had here among the
producers, government and ourselves to seek that solution
and that's what my presentation is about this morning.
He said he would talk about Kenai Nitrogen Operations, world
competitiveness and issues that other speakers have brought up -
the Alaska situation specifically and potential solutions. He told
members:
Agrium today is one of the world's largest fertilizer
producers. We've got 14 production facilities stretching
from Alaska down to Argentina through Canada and the
Lower 48. While we're primarily a wholesaler in the
world, we do have a retail division in the states, which
is the second largest, about 226 outlets that stretch
from California to the eastern seaboard. Our sales are
above $2 billion. While we're primary in all the nutrient
groups - phosphate, potash, sulfate - we're predominantly
a nitrogen company. Today we are the largest nitrogen
company in the world with all of our ammonia and urea.
Generally speaking, very large world scale facilities -
we really thrive on efficiency, low cost. Most of our
plants are very strategically located near key markets
and lately what we've been doing is moving from the
continental North America into the offshore. This is why
we want this facility here in Kenai and why we built the
one we did in Argentina. Also, a highly skilled force -
we've got about 5,000 employees worldwide and we've got a
very strong commitment to both safety and the
environment.
Let's just turn to the Kenai nitrogen operations. There
might be some facts that you don't quite appreciate about
this facility. This facility produces six percent of all
the nitrogen that is made in all of Canada and the U.S.
So, it's a very major facility here. You can see the
products - ammonia and urea - and we do consume that 50 -
55 bcf/y of gas. We've got 300 full-time highly skilled
employees at any point in time; we have at least 30
contractors on site, also. Our primary markets - and
here's what's very important - and you'll see this as we
get into competitive study a little later on - but, our
primary markets for ammonia are Pacific Rim,
predominantly Korea. Our urea goes to Mexico, South
America, Taiwan and Korea.
I'll talk about this a little later on, but you'll notice
that the Lower 48 and Canada are not in that marketplace.
Our competition comes from the former Soviet Union, South
America, Trinidad and the Pacific Rim. There's been many
new plants. They're slightly more efficient than what
we've got here. They've been built in the last decade.
Generally speaking, the world product prices tend to be
capped by trapped gas economics.
I do want to focus on what Kenai does contribute to the
local economy. Obviously, we're probably the largest
local employer. If not first, we are definitely second
and again we've got those 300 highly skilled employees.
We've got various donations and sponsorships because we
really do care for our communities - everything from
caring for the Kenai United Way, the Challenger Learning
Center, the Boys and Girls Club and, again, we've got
that commitment to safety and environment.
I want to focus on the chart on the right of us. We spend
something like $130 million and most of that is on gas
power and pipeline, at least $70 million. This year it's
a little bit more than that, because some multipliers are
gas contracts. You can see the wages and benefits - $25
million that our people earn here. Property tax is about
$3 million, federal taxes and, yes we do pay tax, is $18
million and other local spending $14 million.
What we've done here is we've only pointed out what we've
spent. Most economists will talk about a local multiplier
affect and depending on the category, it's anywhere from
2 - 6 times. The simplest way of thinking about it is the
wages and benefits where $25 million in this community
supports a lot of other businesses surrounded by other
activity.
Let's turn to world competitiveness. What we have to
appreciate is that nitrogen is a world-traded commodity.
It is really one of the easiest ways to monetize gas and
move it around the world. In fact, once you've built your
ammonia and urea plant, and if it's on tidewater, for
$15 - $50 per ton, you can move that commodity right
around the world very quickly. You'll see a little later
on in this presentation what that really means in terms
of world trade. The reason high gas prices in North
America caused a lot of stress on the nation in
production, a lot of it became uneconomic. North America
does produce 14 percent of the world's nitrogen. However,
when you saw some of those peak prices in previous
presentations that caused up to 50 percent of North
America production to shut in. The other thing you'll see
in the balance is that not only was U.S. industry hurt in
terms of having to shut down, but market was replaced by
imports from offshore. The other key thing, especially
concerning royalties and other multiplier affects on the
economy is that gas producers lost sales during that
period. Some of the demand destruction is still happening
in the Lower 48.
Why does that happen? Let me explain in more detail why
gas price is very key. Ammonia takes about 33 - 34 MMBTUs
per ton of gas at any point in time depending on its
price, about 75 - 90 percent of the cost of producing a
ton of ammonia. This chart displays what really happened
in the Lower 48 in the past year or so. [He continued
explaining the chart.]
He said that plants in Saudi Arabia and Malaysia can make ammonia
for about $60. One of the columns on the chart shows what a
dramatic impact a $5 gas price has. On the average, that's where
the price has been in the Lower 48, notwithstanding a $10 spike.
MR. TWOREK continued to review his slides of the international
competition, and said that the new plants being built in Indonesia
and Malaysia are in the $1 range. He reiterated the message that
their prices are based on international markets and not some higher
prices in the Lower 48. One of the reasons they are not selling to
the U.S. is the Jones Act, which requires a U.S. flagged vessel to
move between U.S. ports. Today there is no U.S. flagged vessel for
conveying ammonia. He explained:
So, even if we wanted to sell ammonia, there are other
restrictions…. It is easier for us to take ammonia out of
our other plants, ...buy it on the world market and move
it to the states than take it out of here. Urea is still
one or two sea-going barges, but there's really no other
long carriers.
MR. TWOREK said that Agrium wants to continue to move ahead and do
something positive about the business and there is expansion
opportunity. Cook Inlet is close to the Pacific Rim markets, has a
very good business climate, a very skilled work force and, today,
Agrium has world scale clients. However, if Agrium leaves it the
way it is, it's not going to be competitive. This plant is not the
most efficient plant in its circuit. It's about 10 percent
defensive in terms of efficiency just because of the year it was
built. It needs to be updated. Today they use 50 - 55 bcf and have
drawn up various expansion plans for over a five-year period and
could easily add another 30 bcf. He explained:
From the forecasts we've seen today, we'd be hard pressed
to commit another $2 - $3 MM to the plants based on those
gas outlooks. If you're going to spend that kind of
money, you expect 15 - 25 years of economic life out of
your facility. So, we do have to find a solution for
this. Also, from what you've seen [indisc.], our base of
50 - 55 means a long-term extension.
What are the benefits to Alaska if we do some of this?
Well, obviously we're going to continue that contribution
of $130 MM and grow it; we're going to increase the sales
and exports; we're going to expand the field employment
base; we've got greater community investment; as much as
I hate to pay taxes, it does increase the tax base; and
it encourages gas exploration and more importantly it
also opens up other industries to the export market.
Every time we put an Alaskan name on that molecule and
send it around the world, it opens up markets for other
products. However, unfortunately, we are in the
international commodity business. We've got to be
competitive. I'd love to be able to pay extremely high
gas prices, but you've seen the charts. It's not to be.
So, we have to figure out a path to get there.
MR. TWOREK said a possible long-term solution would be a spur from
the gas pipeline.
Coal bed methane could add another 8 - 250 tcf and if
nothing else, could augment the utility supply or be the
utility supply. Escopeta - no one is sure about that
today. There could be another 5 - 18 tcf there if they're
even half ways right. Even if they're only right by 20
percent, that's still a significant amount of additional
gas that's not in today's estimates.
He said they're trying to set up a partnership; Agrium is willing
to put up some preinvestment. It has to have the appropriate
risk/reward ratio.
What we have done in the past is bought pregas
production. We've invested in infrastructure like
pipelines. We have done exploration and drilling
partnerships. This is a way to reduce the risk for the
explorer. It is a way of putting some more cash flow on
the table to allow them to do that kind of exploration.
It's extremely helpful [indisc.].
There's other things. We've noticed that some of the
larger producers have approached the state about
potential royalty relief, something about three years for
new drilling. We would certainly be supportive of
something like that for any explorer.
The point we also like to make is we've got to be
careful. You've seen the charts where the gap between the
utility gas and the industrial gas has opened up and with
paragraph 36, that could expose industrials to a higher
royalty load than they now pay. We've got to be careful
that extra tax does not reduce the competitiveness. So,
we'd really like to see that royalties be kept at the
existing level and be based on actual contracts or at
least some volume weighted price rather than just being
exposed to the highest possible prices in the Cook Inlet.
The other thing that we talked about, and this works more
for North Slope gas, but it's the purchase of state
royalty gas for industrial purposes and obviously
supporting that North Slope spur line. All those things
and anything else that the department suggests we're
willing to work in a cooperative partnership to see if we
can come to a solution to this rather ticklish problem.
In closing, we really feel that successful partnering is
going to continue Alaska's development for all of its
sectors and really when you think about it, building in
the Cook Inlet strengthens the base for mega-projects
such as the Alaska pipeline. Anything you can do to
increase your skilled worker base, you're better off. We
have certainly seen that in some of our other situations
with these demographics and things of this nature…We
obviously want to contribute to Alaska's export position.
We want to not only maintain, but [would] like to expand
our contribution to this community.
REPRESENTATIVE DAVIES asked if coal bed methane was just in the
Inlet area.
MR. TWOREK answered yes.
CHAIRMAN TORGERSON asked how the NOLA (New Orleans) price compares
to Henry Hub.
MR. TWOREK replied that in over 20 years there hasn't been much
correlation, but over the last few years the gas price finally got
so high that it overpowered any other economic factor for ammonia
and urea.
The reason the North American industry got into a shut
down situation was they really tried hard to pass through
the NOLA price into the price of fertilizer. There was
almost a one-for-one correlation; you could take my
simple formula of the btu value times whatever their
price was, add $25 and that was essentially the NOLA
price. Even today, it's pretty much there....
CHAIRMAN TORGERSON asked him to explain paragraph 36.
MR. TWOREK said he would try; paragraph 36 is what royalties in the
state are based on. It says:
Royalties will be no less than the highest three contract
prices in the state. It basically has nothing to do with
how much volume. So, you could have a peaking utility
contract at $5 and your royalties, although you're paying
$1.20 or $1.50 would be based on the $5 rather than what
you're actually paying to your producer.
CHAIRMAN TORGERSON asked what system their international
competition uses to value royalty.
MR. TWOREK replied that it is a hodge-podge system that depends on
how sophisticated [a country's] internal economic development is.
Trinidad is the most rigorous and closest to what Agrium is used
to. There would be a bench price called at .90 - $1, then oil and
gas contracts in Trinidad would have escalators like ours. He
further explained:
If you head off into Saudi Arabia, it becomes an equation
of we have no value for the gas that was sitting in the
ground. Somebody, either under government sponsorship or
whatever, built one of these plants, and so, whatever
their well-head price is .50 - $1, their sum token
royalty is around that, but it will slide usually with
some sort of investment curve on the plant. If you put
$600 MM in the ground, you get some sort of sliding
royalty and gradually you will start picking up over time
to something that looks like ours. But it gets very messy
over there when you start digging into it, because they
really try to extend some monetization of that trapped
gas.
CHAIRMAN TORGERSON thanked him for his presentation.
10:38 a.m.
MR. GEORGE FINDLING and MR. SCOTT JEPSEN, Phillips Petroleum
testified next.
TAPE 01-26, SIDE A
MR. JEPSEN told members:
Mr. Chairman, for the record, my name is Scott Jepsen. I
am employed by Phillips as the manager for our Cook Inlet
assets. I reside in Anchorage, Alaska. Thank you for
giving Phillips an opportunity to provide its perspective
on the matters requested in the attachment to your
October 22, 2001 letter.
For clarity, my testimony is structured in question and
answer format, addressing the 10 questions asked in your
letter. These answers also provide our overall
perspective on Cook Inlet, as requested in your letter.
[TRANSMISSION DIFFICULTIES TEMPORARILY SUSPENDED MR. JEPSEN'S
TESTIMONY]
TAPE 01-27, SIDE A
11:00 a.m.
MR. DAN THOMAS, UNOCAL Land Advisor, said Cook Inlet producing
assets are climbing rapidly. Over the last 40 years there hasn't
been much exploration for gas as gas prices have been very low, but
that is changing. UNOCAL believes that the minimum long-term
requirements for Cook Inlet can be met, but there has to be higher
gas prices. He pointed out, "This is not a bad thing."
He referenced one of the committee's questions about UNOCAL's
projection for demand and supply in Cook Inlet. His slide showed
that there is about a 5 tcf demand through 2022. This large demand
will not be met with North Slope gas; there will have to be
exploration. He noted, "North Slope gas is not going to get you
here in time to meet this opening that's very imminent. This slide
clearly indicates an opening as early as 2003."
MR. THOMAS said, in response to the committee's question about coal
bed methane:
Coal bed methane was a play that UNOCAL had an owner
interest in a few years ago. We were the owner and
operator of the Pioneer Unit. It was a large coal bed
methane unit up in Matanuska Valley. We spent millions of
dollars and drilled several wells. It was not a
successful program for UNOCAL, but the gas is there, coal
is there. However, it's very expensive, the pressure is
very low; the cost to drill the wells and the technology
is just not where it was a successful program for UNOCAL.
We sold out our interest in the Unit to Evergreen
Resources wishing them the best of luck. We spoke with
several coal bed methane companies; Evergreen has
expertise; they have their own completion rigs. We hope
for above Cook Inlet and Evergreen's sake they are very
successful. But we did choose to exit the coal bed
methane area.
The committee also asked about the typical consumption by
the various users. This slide was developed using
information provided to the Department of Natural
Resources. They do a very good job of tracking and
projecting the use. I use their information here and,
again, I don't go into the detail as DNR did that this
morning.
The next slide, however, is a very important and very
telling slide. This one shows the average daily demand,
peak day demand and then the reserves that we have in
place and what reserve additions might look like and how
they might help us. If you look at this slide, the points
where the known reserves cross the peak day demand is
about in 2003. That indicates that by the year 2003,
we'll have a shortage on the very coldest day. Where I
can see that the rate the gas can be developed and
produced today is just about equal to the rate we're
consuming the gas. These old fields are declining
pressure, so we're going to have to have new resources
added or we're going to have to move into some storage.
UNOCAL this year for the first time put in place the gas
storage facility to help facilitate meeting the
customer's needs this winter. We injected gas all summer
and we're drawing gas from that field. We see additional
gas storage facilities being required in the very near
term. However, if we look out on this slide a little
further, about 2005 or 2006 is the point where the
reserves cross the average use. So this is the year where
you can't produce enough gas in the summer and put it
into storage to meet the demands of the winter.
The line here will indicate about 1 tcf addition and the
line out here is a 2 tcf addition to the current known
reserves. These are numbers that we've seen from the U.S.
G.S. and other sources as being very viable and options
and opportunities that could be in the Cook Inlet. UNOCAL
is committed to go out and explore for these, but we
can't do so and we don't believe any company can do so at
current prices. The reason UNOCAL activities in 1999 -
2000, UNOCAL has been attending the lease sales and has
been negotiating with private land owners such as CIRI,
other Native corporations and individual owners on the
Kenai Peninsula. We've acquired a significant land
position on the Kenai Peninsula.
In 2000 we sold the fertilizer plant to Agrium. [Indisc.]
was a corporate initiative worldwide to sell off business
like the fertilizer plant, placer mining and coal
divisions in other parts of the world and focus worldwide
on oil and gas.
Later in 2000, the new contract with Enstar to supply
Enstar's gas needs for the coming year - that was
presented to the Regulatory Commission last December and
for the past year we've been going through the regulatory
approval process. In 2001 we've drilled three exploratory
wells here on the Kenai Peninsula. We've also been doing
some innovative step out programs on some of the
platforms and some of the West Sac properties, but these
exploration wells that I'm talking about here are on the
Kenai Peninsula and in the Ninilchik area.
Two weeks ago the Regulatory Commission approved the
Enstar contract as you're aware of and the exploration
wells that we have entered into and the exploration wells
that we have designed and scheduled are as a result and
directly because of the Enstar contract. Had it not been
for the contract, UNOCAL would not have been drilling
these exploration wells and not be having the exploration
programs scheduled that we currently have. We anticipate
two additional exploration wells to be drilled by the end
of this year within the next couple of months. In 2002 we
have eight exploration wells scheduled on the Kenai
Peninsula. There is another well scheduled in South
Ninilchik; we will then go to Deep Creek; we have
multiple wells scheduled in the Anchor Point area and we
will be back up in the Deep Creek area. So, we are very
gradually exploring for gas on the Kenai Peninsula.
We also have an extended seismic program. The next slide
shows prices in Cook Inlet that we have seen. The bottom
line is the average utility price; this is the Department
of Revenue's average weighted price for utilities and you
see it fairly constant and fairly flat. This is the land
of old contracts dating back into the 80s and these
contracts are for gas that was discovered in the 50s and
60s. Again, it is a big bubble - the hundred years'
supply. Most studies see the tail end of that, but that's
what this slide is reflective of. Recently, UNOCAL has
gone out on the market and had to buy some spot gas
occasionally to supply our customer. We have a supply
contract to Agrium to sell them gas at a fixed price. We
bought gas at a very high price, but again this is
reflective of new current market price. We recently saw
in May of last year when Anadarko and Phillips entered
into new contracts with Enstar to supply some of their
needs that was at $2.75 price with an escalator and this
price would be the Enstar/UNOCAL price. These are skewed
a little bit. These two lines should appear out in '03.
These are what these contracts would be selling gas for
out in '03, because we're not currently selling product.
This was put on here for comparison purposes.
The reason for higher prices is that it just costs more
to do business here in Alaska. The labor costs are
higher; there's not an oil and gas supply store down at
the corner like you would find in Midland or anywhere out
in West Texas. It just costs more to get parts up here.
Milk costs more and labor costs more. There's a high risk
of doing business here. We're in a very undefined area.
Down in West Texas there's a lot of wells drilled, so,
one has a good idea of what may or may not be out there.
Our utilities have a huge swing that we don't see in
other parts of the country or that they manage
differently because they have many, many different
sources of supply. So, there's a lot of redundancy. You
don't see the eight to one swing that we enjoy here in
Alaska. I talked about the cost of doing business - we
drilled a $15 million dry hole two years ago. That was
actually a $4 million dry hole and an $11 million road to
get to the dry hole. So, it just costs more.
There are environmental issues. This is a very
environmentally sensitive area. We're going to use things
that are necessary to protect the environment when we go
out and drill these wells, but that costs money.
Very important and becoming more important is the
competition for capital with other worldwide projects.
It's tough to go down to the corporate offices in other
parts of the country and convince management that they
should spend tens or hundreds of millions of dollars in
Alaska when they're going to get a price that's
significantly lower than if it were invested in the Lower
48 or in another part of the world.
Finally, there's the royalty value uncertainty. When we
enter into contracts for lower value markets such as
industrial use where they have a flat profile, where they
don't have this swing that is very expensive to develop
deliverability to provide that market such as Enstar or
Chugach, that market is a lower value market that
competes worldwide as Mr. Tworek explained to us. Again,
that swing is flat; they use the same amount of gas day
in and day out and they use very large volumes. So, it
doesn't cost as much to provide that gas to that customer
as it does the utility. However, when the state
calculates royalties, again as Mr. Tworek indicated, the
royalty is calculated on highest prices paid to send fuel
to the area. So, the producers are exposed to paying
royalty on a high price for gas that was sold to the
utilities for that same gas being sold to the local
industrial users.
All this gets us is what UNOCAL is up to for the next
couple of years. Many people have asked if we are still
in business. Absolutely we are. UNOCAL is very much
dedicated and rededicated itself here to Alaska and to
the Cook Inlet. In 2001 we spent $8 million on the Kenai
Peninsula exploration program. In 2002 we're going to
spend $49 million and in 2003 we've budgeted and approved
in our budget $55 million. These again are for
exploration wells on the east side of Cook Inlet up and
down the road, the Sterling Highway between Kenai and
Palmer, down in Anchor Point area. The dollars you see
here are a combination of dollars that we expect to spend
on exploration wells and in an equity position of a
pipeline. We envision a pipeline being constructed from
Kenai to Anchor Point. The dollars here again are about
50 percent equity ownership. If the ownership of that
pipeline structure changes, the budget for UNOCAL would
increase by about $20 to $25 million.
This is the area again where we're looking at exploring.
This is the Ninilchik unit. We've heard some discussion
earlier that Marathon was drilling a couple of wells
there to go to number 1 and 2. These are also UNOCAL
wells. We are in a partnership arrangement with Marathon
with Marathon as the operator. We will then be going down
to Deep Creek. We submitted an application for an
exploration unit to the Department of Natural Resources
just yesterday as well as the south Ninilchik prospect.
These two prospects are 100 percent owned by UNOCAL.
MR. THOMAS indicated other prospects on a map and said they
envision a pipeline being built all the way down to Anchor
Point as a main transportation line. From Anchor Point south
will be a distribution line constructed by Enstar taking gas
to the residents of Homer. They do not focus on the North
Slope and see exploration in the Cook Inlet for the next 15 to
20 years as what is necessary to meet the needs here. There
will be a shortage before then.
UNOCAL has picked up a significant acreage position in
the Foothills. We're very interested in the area. We
would like nothing more than to see that come forward.
However, it's not going to be the near-term solution.
As far as the legislation to consider, royalty is going
to be a big factor. We would encourage this committee to
consider a royalty valuation on arms-length transactions
and make this consumer based. We're not looking at
shorting the State of Alaska on its royalties. We want to
pay the State of Alaska a very fair price on royalty
valuation. However, it would appear abundantly unfair to
require the producers to pay a higher royalty than the
price that we receive for the products. We encourage the
committee to consider investment tax credits for new gas
based industries such as the expansion project, the
Agrium facility, or investment tax credits for new gas
exploration and development in the Cook Inlet. Again,
it's one thing to take money out from a large country and
let them export it to other parts of the world, but we
believe that if a company is committed to spending tens
of hundreds of millions of dollars putting it back in
Alaska and back into the local economy, there should be
some sort of tax credit to encourage them to do so.
Finally, we would encourage you to simplify the royalty
valuation. Being able to understand and predict what the
royalty is going to be on the gas that we sell when we
enter into a contract is very important. It's hard to
estimate what the value might be of gas that's going to
be sold or transferred 10 - 15 years from now on a long-
term contract. With that, we would finally request your
support for the Kenai Homer pipeline. There's nothing in
particular that I ask for in terms of legislation, but
there is a significant proceeding that will have to be
undergone. We'll have to go through the Regulatory
Commission's approval process again for that pipeline;
we'll go with the State Pipeline Coordinator and there
will be a couple of dozen permits that will be required.
We're looking at a very aggressive program. We're looking
at if the pipeline does go forward, having gas all the
way to the south end of the Peninsula by the end of 2003.
We're looking at a two-year construction.
AN UNIDENTIFIED REPRESENTATIVE said one of his slides showed a
decline in 2009 to 2010 of daily demand and asked why the decline
would occur then and what it signifies.
MR. THOMAS replied that represents the export extension exploration
for the LNG. He pointed out, "We don't know whether Phillips will
extend their LNG export fabrication or not. There was no reason to
assume that they would or they wouldn't. It's simply a state of the
contract as it exists today."
The same Representative asked if they had decided on the size of
their line.
MR. THOMAS replied that they are working under the assumption that
the pipeline will be 16 inches, but there are wells yet to be
drilled and they are hoping to get to 20 inches. The terminus would
be at the Kenai gas field.
CHAIRMAN TORGERSON thanked him for his testimony and said they were
ready to resume testimony from Mr. Jepsen. The following is Mr.
Jepsen's written testimony, which includes the committee's
questions and Mr. Jepsen's responses:
QUESTION:
1) Provide the committee with an update on Phillips'
LNG facility activities and its Cook Inlet gas field
operations.
ANSWER:
Phillips is the operator of the Beluga River Field and
the North Cook Inlet Unit (NCIU). Phillips' interest in
the Beluga River Field is 33% and in the NCIU is 100%.
The Beluga Field primarily provides gas to the local
utility market with some sales of gas to the Agrium urea
plant. Total gross yearly production out of Beluga is
approximately 38 BCF per year. Gas from the North Cook
Inlet Unit is produced from the Tyonek Platform.
Currently, 100% of the gas from Tyonek is used to supply
the Phillips portion of the feed requirements to the
Phillips-Marathon LNG plant. The yearly production from
the NCIU is approximately 53 BCF. Phillips' plan for
these fields is to maintain deliverability within
economic constraints. Phillips also has a 50% interest in
the Moquawkie gas field, a small, one well, undeveloped,
l998 discovery on the west side of Cook Inlet near the
Beluga River Field.
The Kenai LNG plant is jointly owned by Phillips (70%)
and Marathon (30%). Total feed to the plant from Phillips
and Marathon is approximately 77 BCF per year. The plant
produces on average about 1.5 million tons per annum of
liquefied natural gas, which is sold to Japanese
utilities. Our current plans do not envision any
significant changes to the operation of the LNG facility.
QUESTION:
2) What is the expected length of time Phillips plans
to continue current levels of LNG production under the
most recent production estimates from natural gas
resources in the Cook Inlet?
ANSWER:
On April 2, 1999, Phillips and Marathon were granted a
renewal of the export license for the Kenai LNG plant for
the period: April, 2004 to March, 2009 by the U.S.
Department of Energy, Office of Fossil Fuels. For that
renewal, a thorough analysis of reserve adequacy was
conducted and substantial hearings were held. The results
of that process demonstrated that reserve capacity was
sufficient for LNG exports to continue through the
approved period. It was also found that export was
consistent with the public interest and would not result
in a local or regional gas supply shortfall on an annual
basis.
Phillips hopes to operate the Kenai LNG plant well past
2009. However, it is premature to determine whether we
will seek another extension, but if we do, there will be
adequate gas reserves to do so, as well as provide for
the state's needs.
QUESTION:
3) What, if any, expansion plans are being made in the
event that a natural gas supply is made available from
the North Slope?
ANSWER:
Phillips is focusing its ANS gas commercialization
efforts on a pipeline to the Lower 48/Canadian markets.
On the general topic of LNG, we would also note that
Phillips has been part of the Alaska North Slope LNG
Sponsor Group since its inception in 1999. A detailed
review of the Sponsor Group work was given to the Senate
Resources committee in April 2001. That review indicated
that the Nikiski area and a pipeline from Prudhoe Bay
would provide a technically feasible and permittable LNG
plant site/route configuration. However, a cost
competitive, economically viable Alaska LNG project has
yet to be identified.
QUESTION:
4) Do you plan to apply for an extension of your LNG
export authorization past 2009 if North Slope gas is not
available? Is your answer different if North Slope gas
were available?
ANSWER:
As mentioned in my previous answer, Phillips would like
to extend the operation of its LNG operation past 2009,
if the dedicated gas supply available to Phillips and
Marathon in Cook Inlet allows us to do so. However, we do
not see that an export license extension is necessarily
contingent on ANS gas being available in the Cook Inlet
area.
QUESTION:
5) What is your assessment of the Japanese LNG market?
ANSWER:
The East Asian LNG market is fiercely competitive and
likely to continue to be so throughout the remainder of
the decade. In round numbers, we see about 60 to 75
million metric tons per year of potential new LNG supply
chasing after 20 to 40 million metric tons per year of
new LNG demand through 2010. As a result, recently we
have seen prices for new contracts trending downward and
pressure for shorter contract periods.
This reinforces the difficulties that an Alaskan LNG
project faces in the East Asian market over the next
decade. While the market for new LNG is expected to grow,
there is an over abundance of lower cost supply and in
smaller increments compared to new LNG that would be
delivered from Alaska.
That said, Phillips will continue to monitor and evaluate
this situation for possible opportunities for Alaskan
LNG.
QUESTION:
6) What is your current assessment of proven developed
gas reserves, proven undeveloped gas and unproven
probable gas reserves in the Cook Inlet? What is your
current assessment of undiscovered gas resources in the
Cook Inlet?
ANSWER:
For competitive reasons, Phillips does not increase its
internal assessment of reserves for fields or basins.
However, we can cite several published reports that
provide estimates of Cook Inlet reserves. Schlumberger-
Geoquest performed a study for Phillips/Marathon in
support of the LNG export license renewal effort. The
Schlumberger-Geoquest report estimated that, as of
1/1/98, total remaining proven reserves in Cook Inlet
stood at 3.3 TCF (cited in the application to Amend
Authorization to Export Liquefied Natural Gas, Department
of Energy, Office of Fossil Energy). Adjusting for
estimated production volumes since then, 1/1/2001 proven
reserves stood at around 2.7 TCF. The USGS has also
estimated probable reserves at 1 TCF and possible
reserves at 1.4 TCF (as reported in "A Review of Cook
Inlet Natural Gas Supply and Demand", Northern Economics,
2001, p.8).
With regard to Phillips' assessment of undiscovered gas
resources in Cook Inlet, one has to first step back a bit
from the numbers. While the estimate of proven reserves
is fairly precise, the assessment of possible new
potential reserves is less precise. The only real
significance of the USGS estimate is that it indicates we
probably have not found everything there is to be found
in Cook Inlet. The only way to know for sure is through
drilling. Because of the historic overabundance of gas in
Cook Inlet, drilling activity targeted at gas has not
been as high as it might have been. The supply and demand
relationship is starting to turn now, with the extreme
supply overabundance relative to demand dropping to a
level more çomparable to the Lower 48. While some see
this as a matter of concern, it is premature to think
that the market will not react and fill in the supply
opportunities as they arise. From an exploration and
production point of view, this is really a time for
optimism, not pessimism. Let me explain.
By 1970, gas reserves in Cook Inlet stood at about 8
trillion cubic feet (TCF) and production was about 145
billion cubic feet per year: thus the Reserves to
Production ratio (R to P ratio) was about 55 years. As
would be expected with such a high ratio, there was
little incentive to explore for gas, since it would
either be a long time before revenues would be realized
for the additional, discovered gas or the gas would have
to be sold at inordinately low prices.
Over time, the known Cook Inlet reserves have been slowly
consumed. As indicated above, reserves are about 2.7 TCP.
Consumption is about 215 bet/yr and the R to P ratio is
just under 13 years. Theoretically, this would suggest
that developed reserves will be exhausted in about 2014.
However, in reality, this is a very normal situation in
the natural resource industry. For example, the R to P
ratio of the Lower 48 is about 7 years and it has roughly
been at 7-10 years, with a slight decline, for the last
20 years. New resources have been added at about the same
level as consumption. The market for gas and the
increased demand spurs exploration and development.
In the past, the overabundance of gas supply in Cook
Inlet has served as a disincentive for exploration.
However, for the first time in about 30 years, a company
that finds new gas can actually sell at least some of its
potential production at a price that may yield acceptable
rates of return.
In fact, Phillips believes we are beginning to see the
early signs of a new phase of exploration and discovery.
We have seen public announcements showing that gas
activity has begun to pick up. Phillips and Anadarko had
success in finding gas in the Moquawkie Field. We also
note the public announcement that Nikolai Creek No. 3 has
been successfully recompleted and that Northstar Energy
Group proposes a well to tap the North Fork gas field.
Marathon and Unocal are actively exploring throughout the
Kenai Peninsula. There is clearly a renewal of interest
in gas exploration and production in the Cook Inlet area
and the results of that effort are beginning to be seen.
Exploration for oil is also on an 'upswing'. Forest Oil
has made an oil discovery at Redoubt Shoal and Phillips
is drilling an oil exploration well near Anchor Point.
While these oil fields may not add significant gas
reserves, they do provide infrastructure that could lower
the economic hurdles for additional exploration and
development.
On the price side, Enstar has shown willingness in its
more recent contracts to tie gas prices to widely
accepted gas indices such as Henry Hub. While Cook Inlet
is not connected to the Lower 48, receiving Lower 48
prices or better for Cook Inlet gas makes it easier to
evaluate gas plays in Cook Inlet relative to other
options available to potential investors.
Beyond these basic observations, there are other reasons
for prudent optimism. First, seismic technology has
progressed and should significantly improve exploration
chance factors. Second, there are more players, some new,
in the picture. Besides the historical players such as
Unocal, Marathon, Chevron and Phillips, companies such as
Northstar Energy, Forest Oil, Anadarko, Aurora,
Crosstimbers, Pelican Hill and Escopeta are investing in
the Inlet. Clearly, there are players making it more
likely that wells will be drilled and discoveries made.
In looking at Cook Inlet as typical of any large,
prolific resource basin, there are a couple of
characteristics that are common to all of these types of
basins. First, there is invariably a distribution of
field sizes in basins that have been well explored.
Second, there are normally cycles of discoveries based
upon technology or play concepts.
I want to first take the topic of field size
distribution. We know that, typically, naturally
occurring phenomena like hydrocarbon accumulations are
distributed in what is technically defined as a log
normal distribution. Simplistically, there should be a
few giant fields and an ever-increasing number of smaller
fields. In Cook Inlet, almost all of the currently known
reserves are contained in what industry would consider
large or giant gas fields. These are fields with more
than 1 TCF of initial reserves. These fields have long
been regarded as 'accidental discoveries' made while
exploring for oil. There has also been a sprinkling of
relatively small discoveries in the 50 BCF or less range,
which are an inevitable result of the exploration wells
that have been drilled. What are undiscovered are the
expected field sizes in between. As the incentive to
explore for gas in Cook Inlet increases, there is a high
likelihood that explorers will start to find these
middle-sized fields. With higher prices and increased
infrastructure, many of these fields could be economic
and in aggregate could contain relatively large amounts
of gas.
Discovery cycles are also a common characteristic of
basins like Cook Inlet. Typically, a number of
discoveries are initially made in a basin based upon a
particular geologic concept, often followed by a period
of few discoveries. Almost invariably, there is a new
with the peak gas demand of consumers. While such peak
facilities are common elsewhere, due to high
deliverability, there has been little incentive for them
in Cook Inlet.
In public forums, we often hear the concern that the Cook
Inlet is running out of gas. It strikes us that this
assertion basically ignores the role that exploration is
very likely to play in Cook Inlet. As long as the
industry has incentive to drill, we believe the next five
to ten years will yield much about the potential of the
basin.
QUESTION:
7) What are your current exploration plans within and
outside known producing fields in the Cook Inlet? What is
your proposed Cook Inlet drilling budget for the next
five years?
ANSWER:
As I mentioned in my response to the last question,
Phillips is drilling an oil exploration well near Anchor
Point. For proprietary reasons, Phillips does not release
its specific exploration plans or strategies. In general,
however, we will look at any Cook Inlet drilling
opportunity on a case by case basis and determine if it
competes with Phillips' worldwide opportunities,
including those on the North Slope.
QUESTION:
8) What is your current assessment of South-central
demand for gas over the next ten to twenty years. If you
have pessimistic, optimistic and base cases, please
generally describe each case.
ANSWER:
The area utilities and the University of Alaska at
Anchorage generally provide demand forecasts for the
South central area on an ongoing basis. In general, we do
not see any significant variances around their forecasts
at this time that would influence our business
strategies.
QUESTION:
9) We have heard that deliverability, the ability to meet
peak winter demand, may be a problem soon. Please discuss
whether you see deliverability constraints in the next
ten years. Please discus what can be done to reduce any
deliverability problem.
ANSWER:
Gas demand in the Cook Inlet is very seasonal. For a
period of a few days to perhaps several weeks in the
winter, consumption peaks perhaps 30 - 40 percent higher
than for the rest of the year. However, meeting those
demands is not so much a function of reserves as a
function of the capacity of wells and delivery
facilities. To meet the peak winter demand, investments
must be made that are underutilized at other times of the
year. For example, in the Lower 48, Canada and Europe,
investments have been made for peak shaving, facilities
specifically designed to supply gas during seasonal high
demand. Common types of peak shaving are underground
storage in converted reservoirs, LNG storage and facility
capacity expansions such as additional compression.
Typically, these investments are made by the utilities,
which have the ultimate responsibility to meet the peak
gas demand of consumers. While such peak shaving
facilities are common elsewhere, due to high
deliverability, there has been little incentive for them
in Cook Inlet.
Phillips believes that the tension of not over-investing,
yet still meeting peak demands is something that the
marketplace can and will ultimately solve through a
variety of strategies. As a practical matter, as has been
illustrated in numerous markets around the world,
investments by the producers to increase peak
deliverability must be balanced with development of true
peaking facilities. Further, we understand Enstar has
agreements in place with Unocal and Marathon to divert
gas supplies to meet local peak requirements, should the
need arise. In addition, Phillips is committed to working
in support of Enstar's efforts to ensure that the needs
of the community during critical periods are met.
QUESTION:
10) Finally, do you have any recommended state
legislation the committee should consider to advance
development of natural gas related industry within the
state?
ANSWER:
Clearly, more frequent and wider lease sales and
expedited permitting is an excellent policy. In addition,
State support of increased federal lease sales in the
potentia1ly gas prospective lower Cook Inlet would also
be appropriate.
Mr. Chairman this concludes my testimony. Thank you for
the opportunity to present Phillips' views on Cook Inlet
gas. I would be happy to answer any questions you may
have.
CHAIRMAN TORGERSON thanked him for his testimony and said there
were no questions at the time. He announced that Mr. Scott
Heyworth, Chairman for the Citizens Initiative For the All-Alaska
Pipeline, would give the committee an update on how the signature
gathering is going and answer the question of what he expects this
committee or the legislature to do.
11:28 a.m.
MR. SCOTT HEYWORTH said:
Good Morning Mr. Chairman and members of the Committee. I
was pleased to accept your invitation to attend these
hearings and testify before you today.
1 am happy to report that the Citizens Initiative for the
All-Alaska Gasline has just gone over the 50% mark of its
goal of 37,500 registered Alaskan voter signatures. While
it is a bit chilly outside these days, it is not
discouraging Alaskan voters from signing it. As you know,
we must obtain 28,700 valid signatures by January 14,
2002 to be on the November 5, 2002 general ballot. We
have almost 60 petitioners currently working across the
State, mostly volunteers, who just believe in the
Initiative and what it will do for Alaska. He said he
needs to get about 265 signatures a day to reach his
goal.
Also, in your packet you will find an article from
Pacific Maritime Magazine, dated October 2001. You will
notice strong demand for both new LNG tankers and
receiving facilities being built in both Asia and U.S
West Coast LNG markets, OUR NATURAL GAS MARKETS!!!
As the article points out, demand for LNG is obviously
increasing, not declining anytime soon.
In the front of your packets, you will find the
certification letter and ballot language agreed on by my
group, the Attorney General's office and Lt. Gov. Fran
Ulmer. Following it, please find a copy of my Anchorage
only poll results. I agree with your comments, Mr.
Chairman, in the Juneau Empire last week that you feel
this Initiative will pass by 70 percent approval, as
validated by many state-wide polls.
Mr. Chairman, I would like to share with your Committee
some of the structure of this Initiative. This Initiative
creates a State of Alaska Gas Authority that ensures an
All-Alaska Gasline will at least be an option in
developing North Slope Natural Gas.
Mr. Chairman, turning to your packet again you will find
the complete Initiative language. I now wish to bring the
Committee's attention to page 12, section 41.41.400,
which reads:
Credit of state not pledged:
a) Obligations issued under the provisions of this
chapter do not constitute a debt, liability, or
obligation of the state or of a political subdivision of
the state or a pledge of the faith and credit of the
state or of a political subdivision of the state but are
payable solely from the revenue or assets of the
authority. Each obligation issued under this chapter must
contain on its face a statement that the authority is not
obligated to pay it or the interest on it except from the
revenue or assets of the authority and that neither the
faith and credit nor the taxing power of the state or of
a political subdivision of the state is pledged to the
payment of the principal of or the interest on the
obligation.
(b) Expenses incurred by title authority in carrying out
the provision of this chapter are payable from funds
provided under this chapter, and liability may not be
incurred by the authority in excess of these funds.
MR. HEYWORTH continued:
This wording is the key to understanding that this
Authority will not be encumbered by past deficiencies in
past state ventures, such as the Delta barley project. He
said, "I wanted to read you this section, which I
consider to be the integrity of the Initiative itself.
The importance of this is that it is a stand-alone
project. Creditors cannot access the Alaska General Fund
or the Permanent Fund. To obtain the financing of this
project, it will have to be economically sound on its own
merits. In addition, the Committee should be aware that
the model we used for the Initiative language is quite
similar to SB 221 introduced and sponsored by Senator
Robin Taylor last session. The legislative drafters of
that bill included language on bonding and financing.
While I do not profess to be an expert on all
technicalities concerning bonds and finance, I think the
drafters made it fairly clear as to how bonds and notes
of the authority are issued for financing. See page 6,
Section 41.41.300.
The Initiative also states on page 4, Section 41.41.100
that the Authority's operating budget is subject to the
Executive Budget Act, which allows for Legislative
oversight. Succeeding sections allow for more oversight
and public inclusion. Our concept of the structure of the
Authority is that the Board of Directors, appointed by
the Governor with approval of the Legislature, will
oversee development of the project, similar to the
Permanent Fund Board, but that we expect all project
construction, maintenance, and operations to be provided
by the private sector.
The Initiative also calls for a spur line to bring our
gas to South-central as an integral part of the project.
I also believe an LNG project could provide shipments of
Alaska natural gas to the Alaskan Interior, coastal, and
river communities with LNG barges or spur lines. By
moving gas to South-central, this project will ensure
that gas will continue to arrive in [indisc.] and
Nikiski.
Mr. Chairman, you also asked me to comment on the
Legislature's involvement with this Initiative. As you
may know, Alaska law provides that any initiative for the
general ballot must allow for a full session of the
Legislature to assess, review and even pass
"substantially similar" legislation. Senator Taylor's SB
221for instance, is "substantially similar". I would
,
encourage the legislature in the upcoming session to
closely look at this legislation in order to expedite
this project and save Alaska approximately one year in
order to get our gas to market as soon as possible. I
would hope the legislature would move quickly to
appropriate the funds necessary for development of the
project plan as called for in Section 41.41.900,
DEVELOPMENT OF PROJECT PLAN, page 13. Completion of this
project development plan would put Alaska into the
position to seek long-term sales contracts for our gas.
In closing, Mr. Chairman and Committee members, I know
from personally gathering over 500 signatures myself,
statewide polls…[END OF TAPE]
TAPE 01-27, SIDE B
MR. HEYWORTH continued:
…and from the reports of my petitioners all over Alaska
that the response of Alaskan voters to this petition in
the last 7 weeks allows me to state with assurance that
this is the gas line project that Alaskans wish to see
developed. Finally, for the record, I am not opposed to
any gas project that brings Alaska gas to market.
However, we do not want to wait on a Canadian highway
project that may never happen before we explore
developing the very gas pipeline project that Alaskan
voters clearly want. I look forward to working with all
of you in this exciting endeavor.
CHAIRMAN TORGERSON asked Mr. Heyworth to tell them what interaction
he had with Yukon Pacific (YPC) or the Port Authority.
MR. HEYWORTH said Jeff Lowenfels of YPC helped him understand the
route issues.
CHAIRMAN TORGERSON said rumor on the street is that YPC might be
for sale and he wanted to know if part of his discussion was that
the Authority might purchase assets.
MR. HEYWORTH said that was right and they pledged to sell the
permits. It's in the suggested legislation under the word,
"pledge".
CHAIRMAN TORGERSON asked what other discussions he has had with
Senator Taylor.
MR. HEYWORTH said Senator Taylor introduced SB 221 on the last day
of session and he used a lot of his language, "because it's good
stuff." It's quite similar to the initiative. He stated:
All the initiative is showing, in my personal opinion, is
the shining will of the people to their elected
legislators that this is the way they'd like to go and
Senator Taylor's bill covers so much stuff that's in our
initiative. In fact, the legislature could make it
tighter, because as you know I couldn't get through the
Attorney General's office if I had appropriations in
there, for instance...
CHAIRMAN TORGERSON asked what he thought would be needed to jump
start this.
MR. HEYWORTH replied that the project plan was on page 13 and he
thought it would cost $1 - $2 million.
REPRESENTATIVE DAVIES asked if he agreed with Roger Marks'
projections.
MR. HEYWORTH responded that he would be satisfied if the initiative
suggested doing a best interest finding to look at LNG, because he
didn't agree with Roger Marks.
CHAIRMAN TORGERSON said they were in the process of going out with
an RFP now for the committee's own staff economists. He said that
not many people agreed with Mr. Marks' inputs, although they agreed
that the final product is correct.
CHAIRMAN TORGERSON announced a short break.
TAPE 01-28, SIDE A
12:30 p.m.
MR. JOHN ELLWOOD, Executive Vice President, Foothills Pipe Lines,
Ltd., offered the following testimony:
Mr. Chairman, thank you for the invitation to appear
before your committee and to report on the progress of
the ANNGTC/Foothills (ANGTS) Alaska Highway Pipeline
project.
Foothills appeared before your committee on July 18,
August 15 and September 19, 2001. During the earlier
appearances, we spoke to issues of the ANGTS advantages,
Alaska benefits, pipeline access, status of the pipeline
and the various permits. The later appearance focused on
our position regarding he federal legislation proposed by
the Alaska producer group.
Since that, U.S. Senate hearings on Alaska natural gas
were held in Washington and the Alaska Highway Natural
Gas Policy Council forwarded its recommendations to the
Governor. Foothills appreciates the efforts of policy
makers involved in both of these proceedings.
Mr. Chairman, I would like at this time to express our
appreciation to you and to the committee for your words
and contribution to the U.S. Senate Energy Committee
hearings.
Today I would propose to report progress by Foothills on
three fronts:
· The Alaska Northwest Natural Gas Transportation Company
(ANNGTC) partnership.
· Foothills commercial proposal.
· Work on the pipeline right-of-way.
We are aware of a lingering concern regarding the so-
called withdrawn partners issue and alleged liabilities
associated with that issue. When I appeared before your
committee in July of this year, I indicated that
Foothills had undertaken discussions to reenlist the
Withdrawn Partners of the ANNGTC. In our testimony before
the U.S. Senate Energy Committee on October 2, 2001,
Foothills said:
"In the initial stages of the Alaska Highway Project,
numerous U.S. energy companies were partners in the
Alaska Partnership. However, during the decade of the
1980s and the 1990s when the producers of Alaska natural
gas were unwilling to commit that gas to Lower 48 markets
because of low energy prices, all of the U.S. partners
withdrew from the Alaska Partnership. Foothills and
TransCanada as the two remaining partners have offered to
the current holders of the withdrawn partner interests an
opportunity to rejoin the Alaska Partnership. The
negotiations with these companies have been productive
and are ongoing."
Last month we followed-up our testimony with a letter
expanding on the reenlistment process. Earlier this month
we testified before the Committee on Energy and Natural
Resources regarding our efforts to reconstitute the
Alaska Northwest Natural Gas Transportation Company
(Alaska Partnership) by reenlisting the withdrawn
partners. We are writing today on behalf of TransCanada
and Foothills and with the authorization of the withdrawn
partners - Duke, El Paso, Enron, PG&E Corporation, Sempra
and Williams specifically with respect to the
reenlistment process. We are pleased to report that
continued progress has been made on the critical issues,
including the key principles for reenlistment by any
withdrawn partner who so elects in the Alaska Partnership
for the purpose of constructing the Alaska Natural Gas
Transportation System (ANGTS).
We have already scheduled further meetings so that we
continue to work on the details for reconstituting the
Alaska Partnership. It is anticipated that all parties
will have signed a Memorandum of Understanding within the
next month. TransCanada, Foothills and the withdrawn
partners are committed to eliminating commercial barriers
to construction of the ANGTS and in so doing would be
prepared to release contingent claims against the Alaska
Partnership related to previous investments in the ANGTS
as part of a commercial arrangement to ensure a market
viable project.
Our negotiations with the withdrawn partners are
approaching the final stages and we are confident of
meeting our timeline for the successful conclusion of an
agreement.
Commercial Proposal
A commercial agreement with the Alaska producers is an
important prerequisite to any pipeline project. Achieving
such an agreement has been delayed in part because of the
withdrawn partnership issue overhanging the project and
because the Alaska North Slope producers are focused on
completing their project feasibility study. In October
evidence before the U.S. Senate Energy Committee we said:
'An important first step towards commercial viability of
an Alaska gas pipeline is a commercial agreement between
the producers and potential shippers who, in turn, enter
into transportation contracts with the owners and
operators of the transportation system. In this regard,
the Alaska Partnership has pursued discussions with the
producers for the last several months. After several
discussions with the producers over the last year, it has
been agreed that we will develop a commercial proposal to
present to the producers before the end of the year.'
The above referenced October testimony also stated:
'The next step on our critical path will be to prepare,
present to and negotiate with the producers of Alaska
North Slope natural gas a comprehensive commercial
proposal for a pipeline project. Based on the progress we
have made since the Energy Committee hearings, we are
confident that such a proposal will be presented to the
producers before the end of the year. As companies with
longstanding interest in building and owning an Alaska
natural gas pipeline, we have every incentive to reach a
commercial arrangement with the producers to develop a
viable project. We believe that such an arrangement will
be achieved on a timely basis, consistent with the energy
needs of the nation.'
With regards to the negotiations with the North Slope
Producers, we remain confident that we will reach a
commercial arrangement to develop a viable project.
Pipeline Right-of-Way
The Alaska Natural Gas Transportation System from Prudhoe
to Alberta is approximately 1,750 miles long. Access to
land is becoming a difficult challenge for all North
American pipeline projects. Public lands constitute the
majority of the property through which the pipeline will
pass. Foothills is well advanced along the road of
securing the pipeline right-of-way. More than 400 miles
of right-of-way on federal lands has been acquired.
Currently, we are making progress on securing the 200
miles of right-of-way on state lands with the Gas
Pipeline Office. Work is under way to assess the
information that was previously submitted in an earlier
application and a process to move forward has been
identified. With the state right-of-way lease expected to
be in hand by 2003, over 90% of the right-of-way for the
project will have been acquired or reserved.
Let's summarize the progress of the Alaska Highway
Pipeline project.
1. The United States and Canada have determined that the
ANNGTC/Foothills (ANGTS) Alaska Highway Pipeline project
is: (a) necessary, (b) in the public interest, and (c)
should be granted a unique fast track status.
2. Foothills and TransCanada have offered to the current
holders of the withdrawn partner interests an opportunity
to rejoin the Alaska Partnership. Negotiations have been
productive and we are well on our way to reassembling the
Alaska Partnership.
3. A commercial arrangement between a coalition of North
American pipeline companies and [Alaska] natural gas
producer group is the next key milestone. We are working
towards that end. A commercial arrangement will allow the
project to move to the next phase of the project - the
countdown to construction phase. A substantial amount of
this work has already been completed and more is
currently being done on spec to further expedite this
stage of the project.
4. As I indicated, we have made substantial progress in
the area of pipeline right-of-way.
5. In moving forward, we will comply with the technical
and environmental conditions established by President
Carter when he approved our project. In doing so, we
intend to work with interested stakeholders. Over the
coming months we will take steps to establish a
consultation process that will enable interested Alaskans
to become involved in the project.
6. We are committed to maximizing Alaska benefits
consistent with prudent economic efficiencies. The
Governor's Policy Council has made reasonable
recommendations in this regard.
Ultimately the final decision to construct a pipeline
will rest with the gas producers. We remain confident
that the long-term demand for and the price of natural
gas in the North American markets will support his
project.
12:45 p.m.
CHAIRMAN TORGERSON said some of Foothills' partners sell gas in
their own markets and asked if they are approaching this as a
pipeline company or as a potential partner in the marketing of gas.
MR. ELLWOOD answered that the companies that are pure pipeliners,
such as Foothills, and those who have a marketing arm are treated
as two different businesses. "The pipeline part of this wouldn't
necessarily be buying the gas."
CHAIRMAN TORGERSON asked if he wanted to comment on Senator
Murkowski's proposed legislation.
MR. ELLWOOD replied, "Our position is that no new legislation is
needed. The existing legislation, ANGTA, provides everything that
is needed here…"
CHAIRMAN TORGERSON asked if the partners are owners in the Canadian
portion of the pipeline or just the Alaskan part.
MR. ELLWOOD answered that they are working on restructuring just
the Alaska partnership.
CHAIRMAN TORGERSON asked if the Canadian side would be Foothills.
MR. ELLWOOD replied that was correct and Foothills would soon be
half owned by Duke.
CHAIRMAN TORGERSON asked an indiscernible question.
MR. ELLWOOD answer is that three to five entities will step up to
do that. There is some inexpensive expandability of existing
pipeline network in Canada, particularly on the Alliance Pipeline.
There is presently some unused capacity on the Nova TransCanada
System.
There is the capability of expanding the Foothills PG&E
systems and the capability to move southwest gas down the
west coast system. There's also the possibility that a
smaller, but new bullet line or greenfield project could
be built. It wouldn't have to carry all the gas coming
from Alaska. Again, depending on the timing of when the
volumes from here build up, it may be economic; it may be
preferable to build another new, but smaller pipe to one
or more markets.
CHAIRMAN TORGERSON asked if they were thinking about twin 30s or
one large pipe.
MR. ELLWOOD replied that they hadn't given much consideration to
twin pipes. They think this line will be a 42 or 48 inch pipe.
REPRESENTATIVE DAVIES said he raised the issue of risk sharing and
asked if they are contemplating the possibility of sharing the
market risk with the producers.
MR. ELLWOOD replied that he didn't think that would be a useful
thing for the pipeline company to do. He saw a marketing function
where that risk might be taken up.
CHAIRMAN TORGERSON asked if they had a timeline for the resolution
of the withdrawn partner issue.
MR. ELLWOOD replied that there is no drop-dead date but, "We're all
working very diligently to get this thing done."
He was confident that it would be done in the month of November.
All the companies are supportive of the project.
CHAIRMAN TORGERSON asked if any of the agreements needed the
approval of a board of directors.
MR. ELLWOOD replied that in most of the cases it is a management
decision, which helps their timeline somewhat.
REPRESENTATIVE DAVIES asked him to comment on Mr. Heyworth's
initiative.
MR. ELLWOOD replied that he didn't know much about it. He wished
them well. There is a lot of LNG capacity world wide chasing about
a third or half as much market.
REPRESENTATIVE FATE asked if he felt there was some exclusivity
with ANGTA or if there would be more competition for constructing
the line allowed under it.
MR. ELLWOOD replied that they are confident that it will come to
fruition next year.
It seems to us that things are coalescing around a
highway route. There's less and less debate about what is
the most viable route. The question now comes how do we
pull together a consortium, a group of companies that can
make this deal happen. Part of that is to bring in the
U.S. pipeline marketing entities and we're doing that.
And the other half of that is to bring the producers on
and strike some suitable arrangement with them -
something that's satisfactory for both sides of this
equation. That is just beginning, but I am encouraged
that we are under way now.
REPRESENTATIVE DAVIES asked him about the probability of this
project coming together.
MR. ELLWOOD replied:
If we put this commercial proposal in front of the
producers towards the end of this year, my understanding
is that their studies are going to be completed at about
the same time…I would hope we could get around a table
and into some serious negotiation in the early part of
next year. My expectation would be that those
negotiations are going to be challenging and that we will
probably be at that for some months before we whittle
down to what an agreement might be. By the end of next
year we should be in a position to drop the flag and
that's when things really start to happen - when the
major money starts to be spent to get something done.
REPRESENTATIVE OGAN asked if the position of the assets by Duke was
motivated by bullishness on this project or whether it just
happened because it came along with the package.
MR. ELLWOOD said he couldn't answer that; only Duke could. They
hadn't announced any spin offs, so he thought they wanted to keep
all of them.
REPRESENTATIVE OGAN asked what percentage of West Coast assets that
are now Duke's were involved in this gas pipeline project.
MR. ELLWOOD said he thought the percentage was very small.
CHAIRMAN TORGERSON thanked him for his presentation and announced
they would hear from Mr. Peterson next.
1:00
MR. RICHARD PETERSON, President and CEO, Alaska Natural Gas-to-
Liquids (ANGTL) Co., said:
I have long been a proponent of GTLs as one solution for
Alaska's stranded natural gas. Coal based GTLs is one
answer for reducing U.S. dependence on foreign crude
imports. I want to say that there's a lot of other people
over the last five or six years that I have run into who
are interested in the GTL program around the country, but
they want to see some interest from the federal and state
governments. Typically, all you hear about is the LNG or
a gas pipeline.
I want to talk about the national energy policy. If the
U.S. really wants a policy that reduces dependence on
foreign crude, we think they can look at the example of
South Africa. South Africa pioneered GTLs in the 50s and
expanded the program in the 70s when OPEC fortified the
U.S. in order to reduce its imports of foreign crude.
Today with advances in GTL technology, the U.S. can build
more efficient gasification and GTL plants for far less
than what it costs in South Africa. I would like to point
out that the U.S. has enough coal reserves in 38 states
across the nation to make over 10 million barrels a day
of synthetic motor fuels for over 200 years.
I think most people don't know, but the United States has
about 25 percent of the world's proven reserves of coal.
It's a significant amount of energy. Also, the Alaska
North Slope contains enough natural gas to make upwards
of 1 million barrels a day of synthetic fuels that can be
transported down the existing pipeline to Valdez for
shipment to the Lower 48. What else is of importance
about that point is that GTLs as a batching program can
also improve the economics of a gas line with more assets
built in Alaska and more jobs for Americans.
GTLs from Alaska can start the process today educating
Americans with the possibility of GTLs. Coal based GTLs
can produce not only the cleanest motor fuels, but they
can also produce some of the cleanest electricity known
to man - a reliable, affordable, environmentally sound
energy for America's future and if you have gas to
liquids, I think you have a solution that President Bush
would be looking for. If this Bush thing can happen
today, we truly believe that Alaska can start the process
and show the rest of the nation how GTLs can work,
whether it's on the North Slope or in Cook Inlet.
He said for a year and a half ANGTL has been looking at other
potential gas to liquid options in Alaska and they focused on Cook
Inlet. Various producers told them that there was no demand and
that's the reason they're not exploring. Based on preliminary
engineering studies, he thought they could build a plant in the
$250 million range. Gas availability limited the size of the plant.
They proposed to sell gas on an impact basis determined by revenues
received from the sale of the products in the U.S. market. A GTL
plant produces excess hydrogen and nitrogen, the two primary feed
stocks for the fertilizer plant. GTL plants can export these
products to the fertilizer plant for incremental fertilizer and
urea production exponentially lowering the overall cost to the
fertilizer plant and its ability to pay higher than current market
values for natural gas while still competing in their export
market. He explained:
In the scenario of a gas shortage in the Cook Inlet area
with gas prices well above $2 - we believe if you
subscribe to that position, then the most ideal thing
that we've seen on the market is to do what is called an
integrated coal gasification combined cycle electric
generation gas to liquid plant. It's a mouthful, but the
DOE has sponsored several programs in the mid-1990s and
these programs are very successful in the Lower 48 -
taking coal gas and refining it and running the gas to
produce electricity. When you add on a GTL complex or
module to that use, it increases the overall efficiency
of the process and creates a well-balanced program. It is
a fact that DOE is actually looking at some of these
programs now. We'd like to point out that these programs
have basically been in existence for 50 years in South
Africa, so it's not an issue of do they work. It's what's
the total economics.
In our proposal we look at upgrading the existing City of
Anchorage MLP and Chugach generation plants in one
location so that we get a higher base load amount of
electricity being generated and using the latest fuel
efficient combined cycle generators fueled by coal from a
gasification facility and a small portion of natural gas.
This gasification facility would now sell the same gas
that would be needed for the FT [Fischer Tropsch -
synthetic fuel] technology to produce healthy clean
fuels. The combination of these technologies improves the
process, extends the life of existing natural gas
reserves in the Cook Inlet area, benefiting the people in
the area giving them another choice of using natural gas
such as Enstar.
MR. PETERSON said they proposed to target about 200 - 300 megawatts
of combined cycle power and that's the base load of both Chugach
and MLP. They could pick up some additional loads since they are
connected to the Railbelt. He said:
As you can well imagine, this creates some sort of
consternation with the existing electric generators in
that they would wonder where the generation would come
into play. Our proposal is to work with them, but we can
also produce what they call power for electricity. Again,
this process would produce between 8,000 and 12,000
barrels a day of ultra clean fuels and share the proposed
background coal export facilities or utilize the existing
[indisc.] to Anchorage facilities if a crude oil line is
built across the Inlet. As some of you know, Forest Oil
has discovered additional amounts of oil and now it's
looking like they are going to build a pipeline across
the Inlet and eliminate the tankering from Drift River to
the [indisc.] facilities. If that happens, then this
might be an advantage for use of these facilities for
export down the west side of the Inlet - if we get a GTL
plant that's built on that side.
We're working closely with Polar Star both in Alaska and
South Africa on GTL programs and hope to move forward on
a GTL program in Cook Inlet shortly. But, I would say
that a gas based GTL program and a coal based GTL program
are mutually exclusive. There isn't enough demand for
these products in the Alaska area and things that would
justify going ahead with both projects. The thing that we
find most frustrating over the last year in conversations
with people who produce this gas is how much gas is
available? What industries are going to be there? Can we
do a viable project? If we do a coal gasification
project, it will have a tremendous benefit for existing
gas users. It should reduce gas prices, reduce demand,
reduce load. But if we're wrong and another 3 - 20 bcf of
gas is found, the gas price in Cook Inlet is going to be
so low that it would make no sense to be producing
electricity from a syn-gas base. So, we're at this point
of - okay guys, try to tell us what's going on.
From the producers' point of view we understand they
would like to get higher prices, but at $3 we see the LNG
plant out of business, we see the fertilizer plant being
out of business. So, we're wondering just where is the
industrial load in the Kenai going to be and what can we
do to work around that. I guess one of the things I've
found talking to various producers, the issues come up of
what is royalty going to be. If we start selling to a GTL
plant and we're also selling electric generation and
we're also selling to Enstar, what is our royalty going
to be? I think these are big issues for the commercial
side of this equation. These questions are going to have
to be addressed because there's too much risk on the
producer's side to want to deal with a commercial project
such as ours not knowing what they're going to have to
pay on a royalty.
I'd say the other thing that we've been told is that the
state needs to do something about the time lag date to go
from buying a lease to physically getting production on
line. Without being specific, that's just a general
comment that we've heard.
From our point as a potential developer of a project in
the Cook Inlet area that needs natural gas, we would like
to have natural gas to do that. We'd like to see anything
the legislature can do to encourage exploration, to speed
up the exploration drilling production process, to look
at ways that from an industrial point of view, the
producer is not penalized for selling to us or promote
buying gas at a flat level base that's year in and year
out, day in and day out when there's other peak day
markets and so on. That's basically all I wanted to say
today…It's my strong feeling that if the nation and
Alaska truly want a national energy program, it's going
to reduce its dependence on foreign crude. I realize
that's a double edged sword for Alaska, because reducing
dependence on foreign crude can also mean reducing the
price of crude in general and sales of crude oil is what
this state lives on. We truly believe if we're going to
have an impact, gas to liquids is going to play a major
role and a gas based GTL plant is going to set the stage
for a coal base. And when we talk about coal based, we
talk about the huge potential of the country. We also
would like to point out that half the coal reserves in
the United States are in Alaska.
CHAIRMAN TORGERSON asked if he had discussions with Chugach
Electric on his proposal and what were their comments.
MR. PETERSON replied that he had and they're betting that there
will be a lot of natural gas found in Cook Inlet and that the gas
price is going to come dramatically down from what they are paying
today.
CHAIRMAN TORGERSON asked if it was Forrest Oil who announced a year
ago that the committee was interested in a GTL plant here.
MR. PETERSON replied yes.
CHAIRMAN TORGERSON asked if they had been talking with ANGTL then
or did that happen later.
MR. PETERSON replied that the announcement that Forest Oil made was
at a Senate hearing last September and the GTL plant they were
talking about was on the North Slope. Forest Oil is extremely
bullish on gas to be found in the Cook Inlet area. They believe
that a large amount of natural gas will be found and that there
really isn't a market to take these large quantities. GTL is just
one option for that and because of the success of GTLs in South
Africa, they thought this would be a good place to get involved in
the U.S.
CHAIRMAN TORGERSON thanked him for his testimony and announced a
short break so that Tony Izzo could give Enstar's overview on Cook
Inlet reserves.
1:29 p.m.
MR. TONY IZZO, President, Enstar Natural Gas Company, said he would
give Enstar's perspective on projected gas usage as well as
Southcentral demand and deliverability. Enstar is a local
distribution company based in Anchorage serving the Mat-Su Valley,
Soldotna and Kenai. They started operation over 40 years ago and
serve over 106,000 customers with some of the lowest gas rates in
the country and the highest residential usage in the country. He
provided members with a snapshot of rates around the country:
Anchorage is the lowest at.40 per cubic foot; San Diego is at the
other end at $1.91.
MR. IZZO said Enstar's future plans include expansion of its system
to Ninilchik, Anchor Point and Homer in the next year or two.
Enstar owns and operates 2,700 miles of distribution and
transmission pipeline operating at pressures of 1,000/psi with line
diameters up to 20 inches. On projected gas usage, he said a little
perspective helps. Enstar represents about 13 percent of the Cook
Inlet consumption in any given year. They transport a good amount
of the power generation and he showed the committee a chart of
their projections.
Gas is purchased under long-term contracts with Marathon, Chevron,
ML&P and Phillips and is indexed to changes in the price of crude
oil. They don't make money on the commodity itself; they make money
on the delivery. Their supply contracts are negotiated and go to
the RCA for approval and move up over time based on the prices of
oil and supply costs are passed through to customers. They have no
take or pay liability, which means that if they don't take what
they project to take from a producer, they're not required to pay
anything, which might occur during a warmer than normal winter.
Enstar has two new supply contracts with Moquawkie (Anadarko &
Phillips) deliveries starting in 1/1/02 and Unocal starting in
1/1/04. They are currently talking with producers about future
supply. In the near term (2001 - 2008), it may become difficult to
meet winter peak demands without new discoveries or development of
peaking facilities, like LNG vaporization and underground storage.
Industrial usage reduction may be needed to meet winter peak
demand. Enstar, like others in the area, are very concerned about
the economy of the community they serve and are pro-active. They
have entered into new supply contracts at higher prices in an
effort to spur exploration and increase reserves. Their new
contract with Unocal contemplates that gas storage will be
developed.
In the medium term (2009 - 2019) peak and daily deliverability
become more difficult if approximately 2 tcf of additional reserves
are not added and industrial use continues at the present rate
after 2009. Along with that, the federal LNG license could be at
risk. He showed the committee a chart called, "Estimated
Deliverability Timeline Assuming that Industrial Use is Reduced by
Half in 2010."
Average demand intersects known reserves around 2006.
TAPE 01-28, SIDE B
1:39 p.m.
MR. IZZO pointed out that the chart, prepared in March 2001, shows
there could be problems with peak demand in the year 2003. He is
more optimistic than these numbers since he has seen Marathon and
UNOCAL's drilling programs and didn't think there would be issues
with average or peak demand until closer to the end of the decade.
Long-term deliverability (after 2019) will most likely not be met
in Cook Inlet unless 2 tcf of reserves are added and industrial use
is discontinued after 2009. He noted, "After 2020, significant new
reserves of North Slope gas is necessary."
He summarized that Enstar believes that the reserves of the Inlet
are sufficient to meet residential and commercial needs in the near
term and he is optimistic that new reserves and/or storage will
improve near-term deliverability during peak demand. They are
optimistic about future growth that is under way in Ninilchik,
Anchor Point and Homer. "Enstar supports an in-state route for
North Slope gas to ensure access to reliable low cost energy for
future generations of Alaskans."
He said their primary concern is to keep homes warm and if they
were pushed to the point of choosing, they would favor curtailing
industrial use. He urged them to do anything possible to avoid
that.
REPRESENTATIVE OGAN asked if there was a 20-inch gas line from
Beluga into Anchorage.
MR. IZZO replied there is.
REPRESENTATIVE OGAN asked how big the line was from Anchorage to
Kenai.
MR. IZZO replied that they have twin 12-inch lines that run
parallel to each other across the Turnagain Arm.
REPRESENTATIVE OGAN asked how much capacity was in the lines, as
Beluga was getting to be a real mature field. He asked, if coal bed
methane comes on line in the Matanuska Valley, will they have
enough capacity to supply industrial users in Kenai.
MR. IZZO replied:
Yes, we believe we do. If you were to average out through
the year what our delivery is through our system, it's
128 mcf/d. We have endured some extreme periods, have
tested that system up higher than 250 mcf/d and have had
no problems. We know for instance that we could survive
without one or the other of those lines. So, if we had
maintenance to perform on the lines across the Turnagain
from the Kenai, most days of the year, 99 percent of the
year, we could survive with the Beluga line and the same
would exist in reverse. If the Beluga line were down, we
have enough capacity on the Kenai twin 12 inch lines that
we could support our system throughout the Mat-Su Valley
as well as Anchorage.
CHAIRMAN TORGERSON asked if the UNOCAL contract was capped at 450
bcf.
MR. IZZO replied:
The contract provides them with the first option to
provide additional supply. So, it is possible they could
fill up the undesignated requirement in 2006 and provide
much more in '07, as well as a layer going forward. The
result of their drilling program would determine the
actual specifics. What we see here is just what the
contractual commitments are. The 450 bcf cap anticipates
potential. So, if additional reserves are discovered, we
certainly have an opening in the market and we'd be very
pleased to fill it.
CHAIRMAN TORGERSON asked why go to the RCA if they have a contract
to supply 20 years of gas.
MR. IZZO replied that applies in the undesignated areas.
CHAIRMAN TORGERSON said they don't show anything after '07.
MR. IZZO replied if the drilling results were to provide additional
reserves, there's a provision in the contract where they can fill
up on designated needs.
CHAIRMAN TORGERSON asked if Enstar would go for the lowest price
gas if they aren't bound to a contract with UNOCAL.
MR. IZZO replied that additional contracts would have to be
approved through the RCA. Their goal has always been to obtain the
lowest price they can, but it was determined that it was going to
take a higher price to spur some exploration for additional
reserves.
CHAIRMAN TORGERSON said the Henry Hub had the potential of taking
the state in some drastic price swings. He appreciated Mr. Izzo's
willingness to help them figure things out.
CHAIRMAN TORGERSON announced a short break.
2:09 p.m.
MR. MARK SEXTON, President and CEO, Evergreen Resources, Inc., said
Dennis Carlton, Senior Vice President, Exploration and Operations,
and John Catigala, Alaska Project Manager, were with him. Mr.
Sexton gave an overview of their company, which is a public
independent oil and gas company traded on the New York Stock
Exchange with the symbol of EVG. He said:
Our operations involve extraction of natural gas from
coal seams in coal beds primarily from our leases in the
Raton Basin in Southern Colorado. There are certainly
other coal bed methane operations in the Lower 48, some
larger than ours and some not as extensive as Evergreen.
But none have been executed with more care for the
environment, we believe, nor for the communities in which
we operate. On that point, the Colorado Oil and Gas
Conservation Commission recognized us for excellence in
three of the last five years - in 96 and 2000 as
outstanding operator specifically cited for community
relations and in 97 as an outstanding operator
specifically citing production enhancement. Closer to
home in May of this year, Governor Tony Knowles gave
Evergreen the Environmental Stewardship Award at the
annual Interstate Oil and Gas Compact meeting that was
held in Anchorage. We've added quite a few jobs to
express regions bringing prosperity and vitality where
previously the southern Colorado economy was stagnating
and notoriously so.
In the following discussion you'll hear the term coal bed
methane. Please keep in mind that coal bed methane is
just really another word for natural gas. They're almost
chemically identical except in this case it's just
natural gas that comes from coal seams directly. A lot of
natural gas that you think of as natural gas was actually
sourced from coal seams that migrated into more
conventional sandstone type reservoirs.
MR. SEXTON showed the committee graphs of the coal content in coal
methane and their prospects in Alaska.
Evergreen plans to drill 6 - 10 wells next year in the Unit and to
complete a disposal well. He said it's important to differentiate
between resources and reserves. Resources are simply estimates of
the amount of the physical gas in place without regard to what
would be economically extracted. Reserves are resources in place
that are proven to be economic through existing wells at existing
prices with existing technology. So, there is a huge difference
between reserves, which are tied to economics and resources, which
are simply estimates of in place supply.
He said that it is well documented that groups of wells do better
than single wells producing in isolation. Once they get results
from exploratory wells, they would know how fast development of
this resource would go forward. Coal bed methane would alleviate
the need for a natural gas pipeline from the North Slope and that
gas could be rerouted to other markets. He said:
Natural gas in the Cook Inlet will provide a steady and
long-lived source for jobs and provide the most efficient
use of capital in that area. It's probably the most
secure and reliable way of providing Cook Inlet with a
long-term supply of natural gas, which is the nature of
coal bed methane. It is very long-lived, typically 20 -
30 years of reserves. As far as our current assessment of
what's going on, we're going to have to rely on
statistics published by the Alaska Division of Oil and
Gas and the Conservation Commission. In the case of coal
bed methane, our own studies suggest that coal bed
methane does have the potential to replace the decline in
gas production of reserves in the Inlet if economic. Our
estimates are that we can get probably 1 tcf in the
Pioneer Unit area alone. More gas on the order of several
tens of trillion cubic feet are possible. Again, the
long-lived natural gas suggests it could be a long steady
course. I do know, however, that the six prior attempts
to produce coal bed methane gas in the Cook Inlet were
not successful and after reviewing those histories, we're
not surprised that those wells did not produce gas. As I
indicated earlier, through our own experience, we know
that very slight variations in [indisc.], completion
techniques, production practices have a huge and profound
impact on the success or failure of a coal bed methane
well.
MR. SEXTON said they use their own companies and aggressively use
local people and contractors to get their work done. For
exploration plans, they also have shallow gas lease applications
pending with the state that were applied for in February 2000. Once
those leases are granted by the end of this year, Evergreen will
negotiate with the successful lessees and unitize the acreage. If
unitization could be accomplished next year, permitting and
exploration activity could also begin that year and they would be
drilling wells in 2003 and beyond. Their next year's budget is
roughly $5 million. If successful, they hope to accelerate as in
the Raton Basin - slowly and prudently to make sure they are doing
it right. They are spending over $75 million in the Raton Basin
this year, but their investment actually exceeds a quarter billion
in drilling and almost a quarter billion in acquisition.
Evergreen's demand has grown by 2 bcf per year and believes that
trend will continue. As delivering peak volumes on the coldest
winter day becomes more difficult, they use short-term solutions
like additional compression, recompletion of existing and drilling
new wells in established fields to increase peak recoveries. The
real long-term solution is to develop new gas supplies with long-
term life, such as coal bed methane.
MR. SEXTON said there is legislation that could advance the
development of coal bed natural gas. He couldn't stress the word,
"if" enough.
I am confident that if coal gas is produced in Alaska,
then Evergreen is the company to do it. We have the
technical expertise to do it and the state of the art
equipment required to make coal bed methane a technical
success. We have a very integrated group that works well
together to do all this with the highest level of quality
assurance and quality control…Coal bed methane is
different from other types of gas development that's
occurred in the state. We can get it; we can get in and
out very quickly, drill wells, be in and out within a
couple of days and fracture simulate in a day.
Doing this development requires streamlining the
permitting and regulatory processes. I'm sure in the
upcoming session bills may be proposed that attempt to
fill in the regulatory gas gap. We ask that you consider
this and to hear Evergreen's opinions on them, because it
will profoundly affect our ability to go forward.
Probably Evergreen's greatest challenge to developing coal bed
methane in Alaska, MR. SEXTON said, is dealing with the issue of
gaining surface access for subsurface mineral development. For this
reason they believe legislation must be passed that encourages the
surface owner to cooperate with gas companies that want to develop
natural gas on their land rather than allowing the surface owner to
discourage this development. He said that coal bed methane
development is an environmentally friendly process inherently and
they are proud of their track record in this area.
MR. SEXTON'S concluding remarks were:
First and foremost our goal is to secure a long-term
supply of secure natural gas for Alaska just as we have
for the citizens of Colorado. We specifically target
Alaska because of its favorable business climate, its
experience and sophistication with oil and gas matters in
development and, of course, we believe coal bed methane
resource is highly prospective there, particularly around
Anchorage.
Second, coal bed methane is a long-lived resource
naturally and provides us the opportunity to make a long-
term investment in Alaska. That's not just a lot of gas;
that's a lot of jobs. We've grown from just a few jobs in
southern Colorado to directly or indirectly employ
several hundred people in the Raton Basin. Just as our
activities there have resulted in long-term jobs and
growth and prosperity, so too could our investment with
you in Alaska…
Thirdly, we support Alaska's efforts to build a natural
gas pipeline to the Lower 48 and hope that Cook Inlet has
sufficient gas to allow us to transport some of our own
gas into that market. Above all else, we want to be
contributing citizens in Alaska. We want to provide jobs;
we think we can; we think we can provide environmentally
responsible development that result in a long-term clean
energy source, which this state needs and particularly
the Anchorage area requires. We've done exactly that in
the Raton Basin; we're proud of our track record and look
forward with great anticipation to replicating that
success here with you.
CHAIRMAN TORGERSON thanked him and said this was his first exposure
to Evergreen.
2:39 p.m.
REPRESENTATIVE OGAN said he was concerned about the conflicts
between the surface owners and the subsurface owner (state). He
asked him to describe ways that he had worked through that issue in
Colorado.
MR. SEXTON said the first thing they do is talk to people:
We don't tell people the way it is; we tell people this
is what our program is; this is what we'd like to do.
This is how it might benefit you. What do you want? And
we find out that people generally have very strong ideas
about what they want…
TAPE 01-29, SIDE A
MR. SEXTON said their wells are small with very small footprints.
Their well pads are 200 x 125 ft. They also do visual and sound
mitigation; but mostly they talk to people in the local communities
and let them see it's not really a big deal.
SENATOR OLSON asked how successful he thought a coal bed methane
source of energy would be for people in western Alaska where energy
prices are expensive.
MR. SEXTON replied:
Probably one of the better examples of that is the Red
Dog mine area, an area where they're importing diesel
fuel about three months out of the year and have to stock
pile it. We're examining the potential of a shallow gas
play up in that area, which probably wouldn't be coal
methane, but shale-type sand development. As an example
there, even with the economies of scale they have, it
still costs them with the diesel fuel they have to
import, the equivalent of paying $10 - $12 per mcf. The
residents of Fairbanks are having to take liquefied
natural gas costing on the order of $7 mcf. Coal bed
methane is fairly economic at $3 - $4. If we can get a
large enough area, get the process going and keep the
economy in scale going, the reality is a coal bed methane
play is the potentially perfect solution for these people
that can't otherwise get energy.
They could in fact with a little bit of help and effort -
a few pilot projects to show that it's economic - this
has the potential to supply natural gas to a lot of areas
which simply would not be available, where it's hard
enough to get the diesel and fuel oil brought in. We'd be
very interested in working with the state outside of the
easy to access areas and to look at areas where there's a
critical need in the outer communities for energy and see
if we could work with the state to establish a viable
coal bed methane project. If it works, you've got a 30-
year supply of gas to help these people out.
SENATOR OLSON asked if they were looking at extensive pipelines
reaching across the tundra for long distances or at a different
well site for each community.
MR. SEXTON replied that each community could be serviced with a
very few wells. He explained:
A typical coal bed methane well produces 100 - 500 mcf/d.
This is about the amount of gas that a 1 megawatt
generator requires. Even if you could not get a pipeline
system through there, if you got a few wells in a cluster
and brought them to a central point, you could generate
power and supply to power people, but could also supply
the gas to people. You don't need a whole lot of wells
drilled to supply a community…
SENATOR OLSON asked a question about reserves.
MR. SEXTON replied that there is some potential on the Yukon Flats
east of Fairbanks. There are huge deposits of bituminous coal.
The great thing about coal bed methane is if you do it
right, it's very environmentally friendly…. No
petrochemical burns cleaner than pure methane. It is the
simplest form of hydrocarbon and it's the environmental
solution. Water disposal is the issue and where the water
doesn't meet the surface use requirement, we simply
reinject it into deeper formations where the water
quality obviously isn't very good.
SENATOR OLSON said the Yukon Kuskokwim Flats are quite far away.
MR. SEXTON said he didn't know about that area, coal bed methane as
a process can be done just about anywhere as long as you can get it
out economically. The only way to know that for sure is to drill a
few wells.
MR. SEXTON thanked the committee for the opportunity to speak with
them.
CHAIRMAN TORGERSON thanked him and announced that concluded the
public testimony portion of the meeting.
2:50 - 2:58 p.m. BREAK
CHAIRMAN TORGERSON announced that they would begin the committee
meeting portion of the schedule. He said that Williams Petroleum
offered to meet with this committee in Tulsa in early December and
show members how gas is traded on the open market. He also
announced that the Premier of Alberta appointed Mark Glady to the
International Committee, which now includes Alaska and Alberta, and
they are trying to get B.C. to join. The first meeting is set for
December 6 in the Yukon and will be very informal.
He informed the committee that the Legislative Council approved
$300,000 to hire an in-house economist, either an individual or a
firm. He is in the process of getting an RFP ready to go and the
goal is to complete the hiring by mid-December.
CHAIRMAN TORGERSON said that he didn't think there would be a lot
of new information to go over in regards to the producers'
application, but there are on-going studies that should be released
close to mid-December, primarily one that compares pipeline
ownership around the world, including ones that are financed by
government. He left the date of the next meeting open and adjourned
this meeting at 3:13 p.m.
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