Legislature(2001 - 2002)
02/28/2001 03:40 PM Senate RES
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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
SENATE RESOURCES COMMITTEE
February 28, 2001
3:40 p.m.
MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Rick Halford
Senator Pete Kelly
Senator Robin Taylor
Senator Kim Elton
Senator Georgianna Lincoln
MEMBERS ABSENT
Senator Drue Pearce, Vice Chair
COMMITTEE CALENDAR
Supply and demand of Future Natural Gas Market by:
Cambridge Energy Research Associates (CERA)
Mr. Ed Kelly
Mr. Demetri Karousos
ACTION NARRATIVE
TAPE 01-17, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Senate Resources Committee
meeting to order at 3:40 p.m. and announced a presentation by the
Cambridge Energy Research Associates. He thanked Commissioner
Condon for his willingness to work with the committee and make CERA
available to them.
COMMISSIONER WILSON CONDON, Department of Revenue, explained that
CERA is under contract to the State of Alaska to provide ongoing
research relating to the North American natural gas permit. He
introduced Mr. Ed Kelly, Director of Research for North American
Gas, Mr. Demetri Karousos, the Associate Director of Research for
Natural Gas and LNG, and Mr. Mark Silver, Account Representative.
MR. ED KELLY thanked the committee for allowing them to present
their views. He said CERA was begun by partners out of Kennedy
School of Government, Harvard University, as a company in 1982.
They deal in all forms of energy world-wide and began the North
American gas practice during deregulation and low gas prices in the
mid-1980s. They have approximately 195 North American gas retainer
clients from all sectors of the business and 650 retainer clients
of their services world-wide, including government entities,
legislatures, producers, pipe lines, and distribution companies.
MR. KELLY said there are several stories in the gas market about
why a pipeline project that for many years was "a rolling 20 years
in the future is now a rolling seven to nine years to potentially
12 years in the future." He said the shorter story is a potential
crisis this past winter in the U.S. Lower 48 that was averted by
basically a warm January and February. He wanted to relate why that
crisis developed, why interest in this project developed, and then
go into the longer-term market conditions and the forces of supply
and demand, price fundamentals and the environment problems this
project would face. He would then turn to his colleague Demetri
Karousos who is an expert in global liquefied natural gas (LNG)
markets.
MR. KELLY explained the following:
The story begins with this past winter when there was
some uncertainty regarding U.S. gas production and its
adequacy. This isn't the winter of 2000/2001; it was the
winter of 1999/2000. January provided concrete evidence
that something was wrong with production. The last of
January was weather that would not have caused a great
deal of demand in the U.S. Lower 48 market, but there was
a record draw on storage inventories last January 2000.
That was the first concrete indication that something was
wrong with production. In reality, production hit a 20
year low in the U.S. Lower 48 during the year 2000.
Secondly, in March, given how low storage inventories
went last March 2000, it became clear that it was going
to be hard to satisfy both power generation demand in the
summer and store enough in storage for the winter. The
power market has developed a great deal over the last
decade and has begun to burn more gas year after year.
Each year, in fact, the power generation market burns
about 1 (billion cubic feet per day) bcfd to 1.5 bcfd
more gas if the economy simply grows normally.
We have begun to rely on gas by default. You can't build
coal, you can't build nuclear plants, you cannot build
hydro-electric plants, so we've eliminated all
alternative sources of bulk power generation in the U.S.
Lower 48. So utilities and independent power generators
are relying on natural gas. We actually began to burn
natural gas in a big way in the late 1990s.
What that meant for this past fall was, in the storage
section, by October 31, 2000 storage inventories were at
a record low entering the winter. Gas is sort of the
original ant-like industry. You store enough for the
following winter. And you have to do that to make sure
that small customers and businesses have the heat that
they need through the coming winter.
October 31, whereas on average in the U.S. we would have
about 3 trillion cubic feet (tcf) of workable gas in
storage in underground, depleted fields or salt caverns,
last October we had about 2,750 bcf. That doesn't sound
like a great deal of exposure, but it is. That was a
record low entering the winter.
A couple of other things we knew - wellhead supply was
running at a 20-year low, still is running at a 20-year
low. So we entered the winter with record low in storage,
with low wellhead supply available in the U.S. Lower 48
market. A third thing we knew; we had had three warm
winters in a row and that could change at any time. At
the time, entering the winter, we estimated that a return
to normal weather, and this was a 15-year normal weather
(not a 30-year as the government measures) that took into
account the warm 1990 - we estimated the demand would
rebound by 3 - 4 bcfd in the U.S. Lower 48 on average. So
we entered the winter exposed.
What happened prior to that was that gas rose in price to
a point that demand was discouraged and destroyed in the
market place. Gas had to rise above the price of
competing fuels. That initially meant the price of
residual fuel oil which can burn in certain boiler loads
in both industries and older power generation equipment.
So gas rose above the price of residual fuel oil over the
summer as power generation markets ramped up and it
became clear that supply was down.
Over the winter, gas also rose in price above distillate
fuel oil. So again, we're standing at last October 31 and
we enter the winter exposed to a great increase in demand
in the face of record low storage inventories. In
reality, November and December 2000 were not just a 15-
year norm, were not just a 30-year norm, but they were
the coldest November and December on the population
weighted basis in the U.S. Lower 48 in 106 years of
record keeping. So demand did not rebound by 3 - 4 bcfd,
but demand rebounded by 10 - 15 bcfd for the months of
November and December, taking gas out of storage at a
very quick rate. This basically removed 600 bcf from the
Lower 48 natural gas market. So in order to assure
supplies for the remainder of winter, as the month of
December progressed and it stayed cold and it was clear
the dimensions of the crisis, gas had to continue to rise
in price so that more demand was destroyed. The demand
that was destroyed as this was occurring includes things
such as fertilizer plants shut down, aluminum plants in
the Pacific Northwest shut down, and ethane that is
normally removed from the gas stream was left in the gas
stream. In fact, so many liquids were left in the gas
stream that some local distribution companies had to call
a halt to the process, because yours and my appliances
cannot handle too many liquids in the natural gas stream.
But these liquids were more valuable left in the gas than
taken out as they normally are. In other words, all hands
were on deck as far as gas supply available and gas
demand destroyed. Gas rose above the price of distillate,
rose above the price of clean liquid fuels and it even
now is pricing very close to the price level of
distillate.
Back then in November and December, if you recall,
distillate, which is roughly equivalent to home heating
oil, was also in short supply and was pricing at about
the equivalent of $7 million per btu. So gas had to rise
well above distillate, because no one had ever really
switched from gas to distillate before. It had to rise
well above the price of distillate so it would entice
people that were not used to doing it and did not
necessarily have the immediately available equipment to
switch so that they would make the investments necessary
to switch to alternate fuel so that more demand would be
taken out of the market.
Where we were sitting December 31, 2000 was at a record
low storage inventory, we weren't sure there was enough
supply for the remainder of the winter in a physical
sense. Gas was pricing at about $9.30 btu at the Henry
Hub.
Over the course of January and February, those were
warmer than normal months. So that storage withdrawals
declined, slowed down, gas was able to price closer to
the level of distillate which, itself, was calming down
as crude oil declined from the mid-30s into the upper-20s
as January and February progressed. So oil products
settled down, natural gas markets settled down somewhat,
but still have stayed, and need to stay, above the price
of enough oil products so that enough demand stays out on
the market.
So we averted a physical crisis this past January and
February. We have enough gas remaining in storage and
producing to supply the remaining small home and
commercial heating load that exists in the U.S. Lower 48
markets. So in a sense, there's enough gas to make it
through the winter. The difficulty comes from getting
enough gas in storage for next year at the point.
Then, Mr. Kelly showed the committee a chart of storage inventories
over the last few years from October through October. "You can see
the build up in inventories to October and the draw down in storage
inventories over the course of the winter."
The bottom blue line is the 2000/2001 winter. He said we entered
October 31 with a record low level in inventories. When we hit
December 31, it looked like we were headed toward a low inventory
of about 500 bcf in storage. This compares to a previous record low
of 750. When that previous record low occurred, there were people
who went without gas in pockets of the East Coast. There were
operational difficulties created by a storage inventory that low.
MR. KELLY said:
It appears that we're still headed for a level below
that. We think we'll head down toward 700 bcf as of the
end of March 31, 2001. The system is more operationally
flexible and the level of imports is increasing so that
we don't think there will be physical shortage this
winter and the gas price has calmed down. Warm weather
also affects the market psychologically - affects the
trading community psychologically. Nevertheless, the
difficulty may not be the spring; it may be coming up for
the remainder of 2001 and beyond. While we expect
increased rig activity to result in increased supply this
year and we believe the supply increase this year will
be about 700 mcfd this year and increasing again next
year.
Based on a record level of gas directed drilling activity
and a record level that was reached last August, we also
expect demand to continue to increase. We think demand
will increase by about an equivalent amount. It normally
would be higher than that. Under normal economic growth,
demand for power generation would increase by 1 to 1.5
bcfd. I just gave you a U.S. wellhead supply increase
that we expect of about 700 mcfd. So a normal demand
increase would be twice what we expect U.S. wellhead
supply to increase.
Imports are increasing. We think the net import number
will go up by .5 bcfd this year with the completion of a
new pipeline out of Canada and evidence of increasing
production in Canada, and a full year's production headed
to U.S. markets in eastern Canada. Nevertheless, the
demand increase normally would be about twice the U.S.
wellhead supply increase that we expect for this year.
The slow down in the economy, however, is helping this
situation out. If you still have your job, you'll be able
to pay your gas bill easier, because the economic slow
down slows down power demand growth and that hits gas
demand growth directly. But we're still at that low in
storage and we still have to prepare for next winter
starting at a record low in inventory March 31.
Each of the last two years, we have managed to inject
into storage 1.6 tcf. That's okay when you're starting at
1 or 1.1 tcf in storage to begin with in the summer. But
this year we are starting at about 700 bcf in storage.
You add 1.6 tcf that we've been able to inject each of
the last two years, that gets you up to 2.3 tcf in
storage. That's not enough for next winter. So we need to
find some gas this summer to allow more to be injected
into storage this summer in the face of higher demand, in
the face of U.S. wellhead supply that is only beginning
and struggling to recover from its historic lows during
the years 2000.
So the supply increase needs to allow for more storage
injections; it needs to at least keep pace with and
exceed demand growth that under normal conditions is 1 to
1.5 bcfd each year and accumulating and, by the way, if
gas is to return to its historic price levels, it needs
to allow for some of that oil demand to come back to gas.
Normally, those boilers and turbines would not be burning
distillate or residual fuel oil. They would be burning
gas. So if gas is to price again below residual fuel oil,
and below distillate fuel oil, there needs to be enough
supply to allow that demand to come back into the market
place. Those are three tall orders. Allow that demand
back in the market place, exceed ongoing demand growth
and power generation, and find extra gas to put in
storage.
SENATOR TAYLOR said his fear has been with the tremendous demand
and need that Northern California, Washington, and Oregon currently
have for new generation. He asked will the utilization of natural
gas by California as it installs new generation further exacerbate
the supply (as he thought Mr. Kelly indicated it probably would.)
MR. KELLY answered that California is not alone. It is simply the
shortest power market that exists nation-wide. There are power
generation plants going on that are producing real pressures
elsewhere. California is burning all the generation it has right
now to satisfy power demand. Some of that generation is very old
equipment that is very inefficient and is creating stress on the
gas delivery infrastructure above and beyond what you would
normally expect. So the gas price in California is abnormal as a
result of burning all the old equipment that exists.
CHAIRMAN TORGERSON asked if in 1999 our rig count or exploration
was at an all-time low.
MR. KELLY answered yes, in 1998.
CHAIRMAN TORGERSON asked if we've recovered to an all-time high.
MR. KELLY answered, "An all-time high in a gas directed sense.
That's not entirely relevant, because you don't always know what
you're getting down the hole. You can try for oil or for gas, but
you can hit one or the other. In a gas directed sense, the number
of rigs drilling for gas is about 900 and that is an all-time high.
The number drilling for oil is between 200 - 300 and that is
nowhere near a high level. That's still a very low level in the
U.S. Lower 48."
Number 1267
MR. DEMETRI KAROUSOS added that, "What's fascinating about this is
that 1998 and 1999 followed two of the highest priced years ever on
record for natural gas. That meant that supply stayed flat. Gas
prices were at $2.50 - $2.75 real dollar terms in 1996 and 1997.
Then the decline started and we got through 1999 essentially by
meeting demand for storage. In 2000 we met the supply challenge by
destroying demand by backing off four to five percent out of 60
bcfd market. Those are the challenges Ed has laid out for you."
CHAIRMAN TORGERSON asked how many power plants are on the drawing
board.
MR. KELLY answered that they are measured in mega wattage. It's
about 270,000 megawatts and well above 90 percent of those would be
gas fired. There's a high mortality rate associated with that. The
power generation base in the U.S. Lower 48 is about 730,000
megawatts. "So clearly, add 270,000 in a reasonable time frame, and
you have a power market that's oversupplied for generation. But
this issue is very regional and very local in terms of which power
markets are likely to be oversupplied and which will remain in
equilibrium or undersupplied."
MR. KELLY continued to say that 1990 - 1992 monthly average demand
moves from a low in the winter of 7 - 8 bcfd up to 10 -12 bcfd in
the summer when power needs are highest. In the year 2000 gas
demand for power generation varied from approximately 11 bcfd in
January and February up to about 22 bcfd last August. This is quite
a change from the early 1990 averages and stresses the ability of
gas supply to meet that power generation demand and store enough
for the following winter. MR. KELLY continued:
Economic weakness has helped, in a perverse sense, in the
year 2001, because we don't want power demand to increase
then, based on an average economic growth for 2001 of 1.8
percent. A weak economic year hits power demand growth
very directly. If the economy had grown normally, we
would have expected that to result in an average demand
growth of 1.2 - 1.3 bcfd in a given month for power
generation and a higher summer peak in July and August.
If the economy resumes a normal pattern of economic
growth after this year, you can expect the stress on gas
supplies in North America to move upward with it. If the
remainder of the heating season is cold, we think we can
get down to about 600 bcf [in storage]. Our outlook is
for about 700 bcf under normal weather for the remainder
of the heating season.
This creates a difficulty for the remaining year 2001 and
that difficulty extends potentially into 2002, as well,
because we're likely to enter next winter with another
record low in storage inventories.
MR. KELLY said that power generation goes in patterns itself and
moves where the business opportunity is and sometimes it moves all
at once. There was a huge movement in power generation development
in the mid-1990s in Asia. "With the 1997 - 98 Asian economic
crisis, that opportunity was gone, a lot of money was lost and the
development community moved somewhere else and that somewhere else
was North America in the throes of an economic boom and growing
power demand."
It moved from 40 - 50,000 megawatts of generation proposals in 1998
to well over 200,000 megawatts in the U.S. Lower 48 in 1999 and the
number continues to increase. They do not see death notices of
power generation projects since one never announces that they are
dead. CERA thinks there will be an increasing mortality rate of
independent power projects as some markets become overbuilt and as
the gas price increases well above planning forecasts for fuel
inputs in most of the power generation plants.
SENATOR KELLY asked him to explain more about the mortality rate of
power developing.
MR. KELLY replied that developers don't need to and don't announce
a project as dead. This is true of many projects, whether it's
energy related or not. The number of plants may be high and
accumulate, but in reality an increasing percentage of them may be
dead. A lot of the proposals were based on a gas price forecast in
historic norms of around $2.50 mbtu.
MR. KELLY said the reality is that more is going in the ground.
Last year, around 30,000 megawatts of new power generation that was
gas fired actually went into service. That's 4.5 bcfd of demand if
they are all running at the same time, which never happens. This
year, they think close to 40,000 megawatts of power generation that
is gas fired will actually enter service. He continued:
Next year they expect that pace to slow somewhat. The
underlying pace the U.S. market needs to remain in
balance and to keep something like a 15 percent reserve
margin on generation is a straightforward calculation. If
you have 730 - 740,000 megawatts in the U.S. as a whole,
representing a reasonable reserve margin in most areas,
California excluded, and the economy grows 2 - 3 percent,
peak power demand grows about 75 percent of that level,
1.5 - 2 percent, you need 10 - 15,000 new megawatts each
year simply to keep the power market overall in the U.S.
Lower 48 in equilibrium. That's an invalid number in the
sense that each power market has its own power demand and
supply balance and needs associated with that. So we're
exceeding underlying need and developing some overbuilt
markets while some remain under-built. But there's strong
pressure on gas-fired generation. There's no alternative
for the underlying need.
Number 1700
SENATOR ELTON asked if the new gas fired power generation plants
would be able to go back to distillate.
MR. KELLY answered, "Not as easily." Almost none of them are
building tanks on sight, because it's a competitive free for all in
power generation development. The biggest way to disadvantage your
project is to try and permit an oil tank along with your
unregulated power generation power project. MR. KELLY continued:
Secondly, it loads capital onto your project in
comparison to those that don't. So somewhere about 90
percent of the new proposals don't have the physical
support for distillate storage.
Thirdly, the turbines are designed on gas and they don't
run quite as efficiently on a liquid fuel, even a clean
one. There are warranty implications, as well. So there
is a built-in reluctance, as well as emissions
requirements that are higher even under clean liquids
with a less efficient firing.
MR. KAROUSOS added that the older plants, usually the steam boiler
plants burn residual fuel oil, not distillate fuel oil. That's a
much cheaper fuel. Part of the story is that the competitive
pressures are increasing with the higher price in the barrel,
cleaner distillate fuels than traditional residual fuels burn. He
thought there would be an increase in dual fuel capability in 2005
- 2010.
SENATOR TAYLOR noted that California and the western states have
the smallest amount of new generation coming on line. This is where
the problem is currently being faced. The Northeast, that is losing
population, and the Midwest, have tremendous development and growth
going on in capacity. He asked for the explanation.
MR. KELLY replied, "That gets into the power market structure and
they vary." He explained:
They vary from - you have some reasonable reassurance
that your power output will enter the grid under
objective terms and conditions that are available to
everyone else. The Northeast and Texas are two of those
regions to having relatively no assurance… Also, in the
Southeast, for instance, those utilities are very
confident that they will remain in the power development
business, in general. That's relatively few independent
developments in the Southeast. In the West, the power
market is somewhat more of a hodge-podge and the
California PX was developed over the course of this time
frame. There is some ambiguities there. Mathematically,
outside the State of California, the demonstrated need
and number of days of need isn't as great in some areas
of the West.
The Midwest is a combination. It's power utility based,
but its need is for peaking generation because of the
base of coal and nuclear generation. So for most days of
the year, the Midwest is adequately supplied. One of the
most positive economic growth stories nation-wide has
been happening in the Midwest.
MR. KELLY exhibited another slide showing CERA's outlook for need
for the next five years and the outlook for generation development
for the same time. It shows the West as being in equilibrium, but
that disguises a lot of local variance. They believe Texas will be
an overbuilt power market as early as this summer.
In North America, gas is one of the most high velocity commodities
to be traded freely at a larger variety of points. There is both a
futures market and a cash market at about 60 points on the North
American gas grid which are generally major pipeline intersections.
There can also be local demands in a supply area creating a price
at a point in a supply area. In a market area or major metropolitan
area, you'll have storage designed to satisfy that demand and
you'll have infrastructure as the supply (i.e. the pipeline
capacity). This creates a price differential (basis) between the
two points and both of them are freely traded with some velocity
every day. You can also trade the differential in price forward and
derivatives. You can choose what risk you want to take and Alaska
producers, when they sell their gas in the Alberta market place,
will have a variety of risk options. It will affect the netback in
royalty payments.
MR. KELLY said, "Once the gas does hit Alberta, there will be three
major options in terms of marketing it from that point forward.
They think there will be a need to market it from that point
forward and move it physically from that point forward. The first
is to move Pacific Gas Transmission to the West Coast and Pacific
Northwest markets - the PGT line. That line is expandable and does
offer some ability to move increased volumes to the West Coast. He
continued:
The second and major option in most people's minds is to
move into the U.S. Midwest, into the Chicago area. Once
that occurs, you're basically in the larger U.S. market.
The reason for that is that the heavy industry that was
in the Midwest until the mid-80s burned a lot of gas and
created a lot of infrastructure from the Gulf Coast and
from North Texas, Kansas, and Oklahoma into the Midwest.
That industry went down, gas usage went down. It created
a lot of available pipeline space from the Gulf Coast,
North Texas, Kansas, and Oklahoma into the Midwest. So
there's a lot of gas that can move very freely from the
Midwest and from Southern Canada where the same dynamic
occurred (from the Gulf Coast, Mid Continent, to the
Midwest and Southern Canada). Those prices never vary
that much because there's a lot of free and available
space in the pipe to move the gas around.
That's why Chicago is a destination for new supply. You
have some assurance of market there and you'll get
basically a North American average price. You can also
move the gas directly into Northeastern markets via the
Trans Canada pipeline system which has a lot of space
available on it. That's sort of a third major option, but
it's likely to be a higher cost option.
MR. KELLY illustrated some of the major pricing points. He said the
Henry Hub in Southeast Louisiana is the site of delivery for the
New York Mercantile Exchange futures contract. Other prices are
generally addressed in terms of their relationship to the Henry Hub
as a plus or minus to it.
SENATOR LINCOLN asked how difficult it was to expand a line.
MR. KELLY said he didn't mean to imply it was a difficult process;
it generally isn't.
Federal regulation does not discourage additions to gas
infrastructure, because it is clean and environmentally
friendly. It is a matter of where there is existing
right-of-way. You can use it and add to it. Generally,
you have to expand right of way if you expand gas lines
in it or you can add capacity through an existing line,
itself. Gas is compressed physically and if you can
compress it within what the outer wall of the pipe can
hold, ultimately you can add to capacity in an existing
line. There is some of both available.
CHAIRMAN TORGERSON asked if he was predicting the same space would
be available on the Alliance line if an Alaskan line was hooked
into that.
MR. KELLY replied, "No, the variable there is how much Western
Canadian production can increase to fill existing capacity and
expansion capability."
MR. KELLY said if Alaska gas comes in, it would add to the build
that you need to really get gas to the market place which would
mean another pipeline - either down an existing right-of-way or a
brand new pipe.
SENATOR TAYLOR asked if the capital demand for construction of the
new pipes diminished the value of the gas to the state or is that
amortized as future gas costs.
TAPE 01-17, SIDE B
MR. KELLY answered, "If that pipe weren't built, then the Alberta
price would lower significantly with the addition of Alaskan gas
and the netback in royalty would decline significantly. So if the
pipe is built, there is a capital cost incurred to do it. But at
the same time, there is a higher price at the other end of the
pipe. Presumably, the pipe wouldn't be built unless the gain was
greater than the cost."
CHAIRMAN TORGERSON said that no matter what pipeline the state
uses, it's still going to affect the netback at wellhead.
MR. KELLY said, "It's an interesting question in terms of how the
royalty is computed. We have a mixture of one large project to
Alberta and several smaller projects to monetize the gas from
Alberta forward."
He said, "In 2001 versus 2000, with the completion of the Alliance
line and the beginning of supply increase in western Canada, we
expect the net number that hits the U.S. Midwest to increase by 500
bcfd on average. The net amount that flows east on the Trans Canada
system should decline by 400 bcfd and the net amount that flows to
the West Coast should decline by a small amount - 75 mcfd.
Additional capacity to the Midwest diverts supply and away from
other outlets.
MR. KELLY used a chart to illustrate pricing differentials to the
Henry Hub that they expect for 2000. He said they expect Alberta to
price below 50 cents below the Henry Hub and slightly less for
2001.
The differential expanded as Alliance was completed adding supply
out of Alberta. The reason had to do with the rate structure on the
Trans Canada Pipeline system, which is fairly inflexible because
it's so marginal. So you have to pay a good bit on that system
whether you move it on a short-term basis or a long-term basis.
Because the marginal molecules have to flow through the Trans
Canada system at a fairly high rate, the pricing differential in
Alberta recorded on a spot daily basis actually expanded to the
Henry Hub. "So pipeline rates do matter in an expanding market."
MR. KELLY said:
You can see the effects of new supplies on the Rockies on
the price differential as Powder River coal bed methane
supplies have expanded and net supplies in the Rockies
have expanded, pipeline capacity has not expanded out of
the Rockies for a couple of years. So the Rockies index
price has declined in relation to the Henry Hub price,
has greater volume in the same amount of pipeline
capacity exiting that region. You can also see the
effects on the southern California border, Topock, which
has exploded. Just upstream in the San Juan Basin, that
differential has expanded negatively. You would expect
that to - illustrating how the value can be had in short
pieces of pipe when the market dynamic shifts.
CHAIRMAN TORGERSON asked him to clarify the price requirements
versus proposed capacity.
SENATOR KELLY asked if the price differential was from the
perspective of the consumer to Henry Hub.
MR. KELLY replied that was wholesale, cash, physical trading. Not
really to the consumer.
SENATOR ELTON asked if there is a difference between San Juan and
Southern California because there is no transportation system that
can move gas from San Juan into Southern California.
MR. KELLY replied that, "There is no transportation system that can
move any more gas from the San Juan Basin into Southern
California."
SENATOR ELTON asked if there is an effort to increase the capacity
of the transportation systems.
MR. KELLY replied that the crisis is current and the ability to
increase capacity goes through a regulatory and permitting process
and there's generally a two-year lag.
Number 2126
SENATOR ELTON said as we talk about moving Alaska natural gas into
the market place we can assume there will be new transportation
systems that will change the market conditions by the time Alaska
gas arrives.
MR. KELLY answered, "Absolutely. There are a number of proposals to
move additional gas from the San Juan Basin into Southern
California."
CHAIRMAN TORGERSON asked what the 4 bcfd of Alaska gas would do in
this market - ballpark.
MR. KELLY answered:
It would have some effect on pricing, certainly. Keep in
mind, the overall U.S. market place is about 61 bcfd. So
4 bcfd hitting at once seven years hence…Normal rates of
economic growth of 1 to 1.5 bcfd each year - we're
looking at a 70 bcfd market. So 4 bcfd all at once into a
70 bcfd market, 6 percent supply addition, offset by some
supply flexibility that Mr. Karousos would address in the
LNG market place. Also offset with time with an ongoing
increase in power generation load. Four bcfd at once is
roughly three to four years of overall demand growth, if
the economy is growing in a healthy direction.
Supply events like this do seem large and are large, but
demand growth can absorb it. For instance, the Alliance
pipeline it was feared would lower the price in the
Chicago market place. In reality, when we looked at it,
we saw that a return to normal winter weather would more
than offset the new supply coming down the Alliance
pipeline for two or three years.
Ongoing power generation demand in the Midwest is one of
the markets that is actually in equilibrium. Proposals
don't exceed need over the next five years by that much.
There's a need for new build. Power demand growth is very
strong there and the economy has been fairly healthy
there.
Number 1900
MR. KAROUSOS said:
We like to talk about marginal production and incremental
supply and the distinction is that marginal supply is the
last mcf that's called on to meet demand on a daily
basis. Incremental supply means when a new project is
coming on, where is that supply coming from. Something
like 70 - 80 percent of incremental supply into the U.S.
has come from Canadian supply. That supply, once it came
on, typically led to the pipeline infrastructure
delivering at very high utilization rates which means
that even though it was new supply, it was running base
load and the marginal (or high cost) supply. Therefore,
that supply that's brought on to meet that last supply
continues to be the U.S. Gulf Coast. This is a dynamic we
think will continue for the next five - 15 or 20 years.
The high cost supply will adjust and take the swing.
That's important to know, because it really suggests
whether there's a volume risk in addition to a price risk
associated with an Alaskan project. And we think the
answer is flatly no, that there isn't a volume risk
associated with serving the North American market. Within
a year or two years, that kind of supply adjustment takes
place among the traditional higher cost producers. That's
without getting into some of the new supply that we'd be
serving the market like LNG, serving primarily the U.S.
East Coast. Over time it creates a flexible supply
potential that can on a fairly quick notice move to a
higher value market should prices fall to levels that
aren't attractive. The flexibility of this market place
is only increasing in terms of demand flexibility and in
terms of supply flexibility.
CHAIRMAN TORGERSON asked if he understood correctly that there
would be stagnant growth for a couple of years before there would
be an increase or dip in price.
MR. KELLY stated, "We know the gas is available immediately which
is one distinction in Alaska versus other supply efforts."
SENATOR TAYLOR asked what crystal ball they were using to say that
Alaska gas would come on line seven years hence.
MR. KELLY replied that was their most optimistic scenario in which
things would have to start fast and now.
SENATOR ELTON said that he was struck by how few of the projects
have financing or are under construction. He wanted to know if he
was wrong in assuming if Alaska gas hits the market place, it will
be easier for power generators to get financing because of an
increased supply and, therefore, the number of generating plants
might increase.
MR. KELLY answered that he, "wouldn't oversell that personally, but
I think that's legitimate in the sense it would increase the
confidence in the long term supply of availability of natural gas."
SENATOR ELTON asked if it didn't necessarily drive expansion.
MR. KELLY said he didn't think it would have that kind of price
effect immediately. He showed the committee a chart of the regional
power markets illustrating that the power transmission system is
not designed to move bulk power among the local utilities.
Region by region, the clearest evidence of overbuild is
clearly in the Northeast where even the actual
construction is greater than projected need for new power
generation given a normal reserve margin of 15 - 20
percent range over peak power demand for the next five
years.
In the South, it looks like a market where build may be
in equilibrium if a reasonable percentage of project
proposals shift to be financed and under construction.
That's a large region stretching from west Texas to
Virginia and disguises variants between an overbuild in
Texas and continuing need for new construction in Florida
and parts of the Carolinas.
In the West, there's obviously huge variants disguised,
as well, between need for continuing build in California
and power surplus on most days of most years in much of
the rest of the West.
The Midwest is a market which might be able to use a few
more proposals, because given the mortality rate on power
generation proposals, we might need some more proposals
turn to new construction in the Midwest. The character of
power generation build in the Midwest is very different
because of the coal and nuclear generation base. They
tend to be peaking which is a combustion turbine base
generation plant.
MR. KELLY said that producers have to look at the market beginning
seven years hence and make a belief fundamentally that the netback
to the wellhead provides an attractive rate of return on their
investment in the pipe based on the market dynamic starting at
least seven years from now.
Demand pressure is strong. In the U.S. gas market place,
it's now at 22 trillion cubic feet (tcf). We know in an
22 tcfd world, that varies from 11 - 20 bcfd in a given
month. It's easy to get to 30 tcf as far as demand
potential for natural gas in the U.S. goes. All you have
to do is assume normal rates of economic growth and
assume gas's current share of new power generation
development and you can make some reasonable assumptions
and get to 30 tcf of demand. This is kind of a shining
goal on the hill held by much of the industry. What has
to happen on the ground in terms of working day to day
operations, however, is a real challenge in that
environment. Rather than demand for power generation
varying from 11 - 21 bcfd in a 30 tcf world, it would
vary from 21 - 40 or 45 bcfd and would seriously stress
the ability to store gas for each winter.
Rather than proven reserves of about 200 tcf in the U.S.
and Canada and in order to support 30 tcf of annual
demand in the U.S. proven reserves would need to increase
reserve additions over the course of the decade 2000 -
2010 by more than the proven reserve level.
MR. KELLY continued:
This implies an annual reserve addition that rather than
just replacing production of 21 - 22 tcf, we would need
an annual reserve addition level of close to 35 tcf in
the U.S. and Canada. So this represents a larger industry
and much larger production effort than we have now. The
potential is easy to see out there.
That also implies a movement to the frontiers and there
are a variety of frontiers, not just Alaska. One of them
is eastern Canada and LNG. Supply addition include the
deep water Gulf, the Rocky Mountains, and western Canada
in addition to Arctic gas.
The range of frontier production we would expect from
Atlantic Canada by 2010 varies from 1.5 bcfd to 2.5 bcfd
off-shore Nova Scotia, a new producing province that is
producing about .5 bcfd.
SENATOR LINCOLN asked what would have to happen in the nation that
would drive the need down.
MR. KELLY answered that within the decade there could be a
resurgence of coal-based generation and there are clean coal
technologies that are thoroughly exciting. Coal is economic with
the current price of natural gas, but it takes a while to get
permitted and built. If this happened, it could take a larger share
of new generation than it does now and that would take some of the
market growth directly off the top. Any economic weakness or any
increase in the efficiency or conservation driven by high real
energy costs would slow down the rate of growth.
SENATOR LINCOLN asked, even with new coal generation, would there
be a gradual decline or a significant decline.
MR. KELLY replied that there would be a slow-down in the rate of
growth. They accounted for some of that in their outlook. "The
earliest they foresee reaching a 30 tcf market, in the most
optimistic of supply scenarios, is 2012, as a company."
SENATOR LINCOLN asked if they took into account the new more
efficient power plants.
MR. KELLY answered, "Yes."
MR. KAROUSOS added that they have conservative assessments of what
fuels will actually meet new generation as opposed to new capacity.
Coal is already built into their 2012 timetable and captures 40 -
50 percent of new generation with expansion of current facilities
(brown field facilities). Gas accounts for 12 - 13 percent of the
power market today. Their assumptions do not have gas suddenly
jumping to 40 - 50 percent of the power market. But even small
increases in the large power market have a big impact in the gas
market. "That's what we're seeing with these numbers."
MR. KAROUSOS said that another vulnerability for long-term demand
growth is confidence in gas supply on the part of large industrial
players who are considering their investment options. "They will
seek a home overseas, if the growing consensus is that gas can't be
supplied in the U.S. below $4 - $5 Mmbtu."
He added that supply additions, particularly those that are
communicated in advance, lead to demand creation, primarily as a
perception of supply availability and economic growth.
CHAIRMAN TORGERSON asked if supply was more important than price.
MR. KELLY answered that supply is evidenced through price.
MR. KAROUSOS said that the degree to which higher prices are
realized in the short term has implications to the long term.
MR. KELLY said, "Given there is a need, the market is supply
constrained right now. The market would be larger if there were
historically normal relationships between supply and demand for
natural gas right now." There are risks to any venture that aren't
peculiar to just Alaska. They think that a cooperative stance
between the Alaskan and Canadian government will help. "The need
for downstream capacity is a big unknown."
He said that transporting the liquids can support the economics of
a pipeline, itself, because you're moving more in the btu's per
given unit of space if the liquids are included in the pipeline.
He said, "It adds to the cost somewhat of a new pipeline, however."
MR. KELLY concluded that they believe the producers will be the
drivers of this project, if it is worth it to them. He turned the
presentation over to Mr. Karousos who dealt with the LNG market
place.
Number 900
MR. KAROUSOS said that the LNG industry is enjoying a renaissance
right now in terms of renewed interest on the part of consumers,
producers, and new third party players. He said that:
Three driving forces are focusing attention on the LNG
industry. First, a real shrinking of the cost structure
along the LNG value chain has reinvigorated the potential
of LNG to serve new markets, particularly North America,
where LNG was considered uneconomic for the last 20
years. Primarily, those cost declines have occurred in
the capital-intensive liquefaction phase and in the
capital intensive shipping segment.
Next, the renewed interest is partly exciting markets
because of the increase in available suppliers and all
the new players in the market. The LNG industry has been
characterized as being a club of relatively small, fairly
sophisticated players and that club is expanding largely
by the day. Four new suppliers just came on to the scene
in 1999 - 2000, one named Cutter, Amont LNG, and in the
Atlantic Basin for the first time in almost 20 years,
Nigerian LNG and Trinidad.
The list of new players is mushrooming every day - from
Angola, Venezuela, Norway, Egypt (four projects proposed)
- expansions at all the current facilities that we're
talking about - the Persian Gulf supply eager to jump off
and really increase market share, as well as expansion in
the largest supply basin of the Pacific Rim. This is
where a lot of supply is looking for a new market.
MR. KAROUSOS said that there is a willingness to take merchant risk
in LNG investment, meaning to build new liquefaction capability
with some of the capacity not contracted. There is new investment
in merchant shipping that isn't part of a contract project
proposal. All that suggests a real change in traditional project
oriented thinking - things like pricing relationships, terms of new
contracts and new contract renewals, and it really begs the
question of a spot market developing in the LNG industry over the
next 10 - 20 years. This would probably happen earlier in the
Atlantic Basin, which is serving well established pipeline gas
markets primarily and, then, in the Pacific Basin.
Specific regional questions are being asked primarily due to cost
decline in the LNG industry. In North America the question is: Will
high prices and tight current supply and imbalances make LNG an
attractive option and will that continue?
"They have seen two responses - an acceleration in the supply
developments in the Atlantic Basin and the expansions plans at new
suppliers in Nigeria and Trinidad with new suppliers really
chomping at the bits in Venezuela, Egypt, potentially Norway, and
potentially Angola by the end of the decade."
MR. KAROUSOS said that they are seeing supply development take
place and an acceleration in reopening of shuttered LNG facilities
that have lain dormant for 20 years in North America.
A second reaction has been a reignited interest in Greenfield (new)
import facilities into North American, primarily, and Mexican
markets. Asia accounts for 75 percent of the global LNG market. The
LNG market total is about 13 bcfd, a fifth of the U.S. market. For
those countries where LNG is a major source of supply, it meets
roughly .5 - 1.0 percent of U.S. supply. It meets 100 percent of
supply in Japan, which accounts for 65 percent of the LNG market.
The Pacific Basin is an area of focus and is obviously the relevant
focus for Alaskan LNG potential. They think there is a very strong
demand potential in Asia driven by both existing countries of
Japan, Korea, and Taiwan and by new market potential. China,
particularly the southern part, and India which have been receiving
a lot of attention for their challenges in reforming the power
market will be the linchpin of LNG imports.
With that potential demand opportunity in Asia are
significant challenges posed by the multiplicity of
supply projects targeting this area that raise the
question of who will achieve that market, under what
terms. The traditional contract in Asia is already under
review. Newer contracts have tended to be more favorable
to consumers, which is showing a greater shift of the
negotiating leverage from the producer community to the
consumer community. There is the question of oil, which
is the current index for LNG delivered into Asia, whether
it will remain the sole index or whether it will be the
appropriate index use. This is highly relevant not just
because of the new demand, but because the existing 20
year contracts are starting to reach contract renewal
time over the next few years, particularly starting in
2004 in Japan and lasting through 2015.
MR. KAROUSOS showed the committee a map of where the LNG production
takes place.
Indonesia is the world's largest LNG producer and serves
primarily Japan, Korea, and Taiwan. The second largest
producer is the original producer (in the world) in
Algeria. But, by far all the large production facilities
are in the Asia/Pacific region and over time there will
be a gradual shift in the axis of supply to the Atlantic
Basin, because of the potential for market growth there.
Most of the facilities are traditionally in the tropic
area.
LNG is the gas monetization strategy. Typically, where
there are no pipeline options and one area of the world
that is eager to increase it's market share and may do so
strategically, and therefore accepting a lower price for
its natural gas, is the Persian Gulf, which is sitting on
hundreds and hundreds of thousands of reserves.
SENATOR LINCOLN asked if the areas where LNG projects are approved,
but not under development, are relatively new approvals or have
they been sitting there for a long time.
MR. KAROUSOS answered they were the Pangu project in Indonesia,
Yemen LNG, and Venezuela. LNG projects sometimes have 20 - 25 year
histories of when reserves were developed and identified. Nigeria
is an example of a project that took 25 years to be realized. He
explained that the approval process is a little bit of a misnomer.
It's easy to get projects approved, but the real issue is when does
the market develop for that LNG and when does the contract get
signed that leads to its development.
TAPE 01-18, SIDE A
SENATOR LINCOLN asked how they determined which areas would be
developed in 2005 - 2010.
MR. KAROUSOS answered that the considerations they use to sequence
potential supply additions are as follows:
· Geography which plays a critical role in LNG development,
because transportation of it is more expensive than
transportation of gas. Every 2,000 nautical miles adds 40 - 50
cents to the cost structure and, therefore, is a subtraction
from the potential netback to any LNG project.
· Supply diversification and security concerns are major drivers
so that sometimes higher cost supplies are developed to
maintain diversification. They expect China to use that
strategy, not offering all its LNG to just one player. Japan
has consistently supported the Australian LNG supply
development on this basis.
· Associated gas pressures transforms LNG development, because
in some cases in some parts of the world, oil development
which sometimes yields lots of natural gas development brings
natural gas in a place where there's absolutely no market for
it. In some cases it's reinjected and in other cases it's
flared. Flaring is increasingly a problem and not accepted by
the host countries.
· The gas sometimes has a negative value. When doing a netback
analysis, you can almost assign a $0 value to the gas, itself,
in the desirability to see that project come to fruition. A
good example of this is the kind of pressures facing west
African producers in Angola and Nigeria.
· How wet the gas is or how many liquids are in the gas stream
is another consideration for all gas projects.
· Alternative gas monetization strategies come into play and the
decision of host countries to see all of their resources being
channeled into one [indisc.] This represents the competition
brought to LNG from gas to liquids (GTL) development.
SENATOR ELTON said he thought one of the supply considerations
would be internal to a single producer. For instance, a North Slope
producer might not want to compete North Slope LNG with LNG they
are producing elsewhere.
MR. KAROUSOS answered because of the capital intensity of the LNG
projects, there are often consortia of producers who cannot dictate
single handedly which projects will go forward and which won't. In
many of the projects, the host country has a large equity stake in
the liquefaction facility and has a driving say in what projects go
forward or who is an important constituent to pay attention to.
There are also capital allocation decisions that every producer
must make including decisions on which kinds of properties to
invest in (oil vs. gas or natural gas that has a pipeline access to
market vs. natural gas that has to be monetized through LNG or
GTL). Their decisions are constrained by the fact that most of
these projects have multiple players. "The ultimate consideration
is what supply is competitive."
MR. KAROUSOS said that LNG has a fairly simple cost structure and
that:
First the gas is developed, then it's gathered, then it's
liquefied, shipped to market, vaporized at the market
place and either consumed on-site in a very local power
plant or entered into the pipeline grid. The parts of the
chain that have really shrunken the most over the past 5
-10 years have really been the liquefaction phase and the
shipping phase.
Liquefaction has seen up to a 30 - 40 percent cost
decline and part of that has been maturation of the LNG
business, which is only 20 - 30 years old. There's been a
tremendous amount of experience gained among the
contractors, the EPC players (engineers, procurement, and
construction firms). There's a greater number of those
players who have experience or just competition in that
sector. That accounts for a significant amount of the
cost decline.
There has also been an adjustment in philosophy of
design, not so much an engineering or technological
breakthrough. This has simply been the realization that
LNG, particularly as supplies increase, the reliability
question becomes somewhat less critical. It doesn't need
to have the same kind of gold plating and duplication of
parts. The real best of practice LNG plants that have
come on stream have been in the Atlantic Basin which are
serving slightly different markets that have pipeline gas
access. This has reduced best practice, green field costs
associated with just the pure liquefaction part of the
business to the .90 - $1.10 range.
Shipping has undergone cost declines partly as a shift
away from the traditional Asian market.
MR. KAROUSOS noted that his graph showed the cost of building a
ship going from the $260 million range down to $225 - $250 million
in the mid-90s down to $150 million for the last two ships that
were chartered. These are the largest tankers that have been built,
135,000 cubic meters. The union call declines have been more
significant. Part of this has been accomplished because new
development has been outside the Asian arena and is not dominated
by the traditional Asian model of relying on the construction to
take place in favored terms.
A consistent characterization of the Japanese LNG
contracting negotiations was that to bring in the supply
to the Japanese market, the ship building had to be done
by the Japanese players and while LNG tankers aren't as
simple as oil tankers, they're hardly a technological
marvel, and multiple players can build these ships and
that is being done today by the Spanish, by the Koreans,
by others.
MR. KAROUSOS said they expect the cost of LNG tankers to average
$150 - $200 million over the next 5 - 6 years.
CHAIRMAN TORGERSON asked if it was safe to assume that pipelines
had gone down also.
MR. KAROUSOS replied yes.
MR. KELLY interjected that there's a right-of-way associated with
pipelines that hasn't gotten any cheaper.
SENATOR ELTON said that none of the LNG tankers are built in the
U.S, so none of them can serve between Alaska and the West Coast.
MR. KAROUSOS replied that the U.S. currently imports LNG.
SENATOR ELTON said it was because of the Jones Act restrictions.
MR. KELLY added that even if the U.S. did build tankers, the West
Coast would not let them in.
MR. KAROUSOS said because of the underlying fundamentals and the
underlying supply pressures of North America, we might want to
consider that LNG import capacity to North America may be the short
commodity by the end of the decade and green field activity may
take hold. El Paso has just announced intentions to build six
import facilities targeting North America and the Caribbean. There
are clever ways around citing facilities.
Number 1200
SENATOR ELTON noted that northern Baja is connected into the
southern California power structure and it's also a way around the
Jones Act.
MR. KAROUSOS said the next chart summarized how the playing field
has changed for LNG. They chose a theoretical Caribbean supply and
assumed a minimum acceptable netback for LNG for natural gas
reserves that don't face the associated gas flaring pressures. A
typical industry standard is 50 - 60 cents netback to the producer,
.90 - $1.10 for green field (new) projects, shipping for 40 - 70
cents (roughly 2,000 nautical miles), and regasification at the
facilities that have been mothballed and are fully depreciated and
have been fully paid for by consumers through pipeline tariffs that
have been passed through to utility bills, and therefore have lower
regasification costs. A new facility would call for 20 - 30 cents
per Mmbtu. An average range in the market place is $2.30 which
really makes LNG attractive.
MR. KAROUSOS said:
In our view, the markets both at Lake Charles which is
very much an Henry Hub kind of price and Elba Island,
Cove Point, and Everett, if you just look at the spot
price, LNG base load supply probably has higher value
than just a pure spot price at that market delivery. But
if you just look at the spot price, it obviously leads to
a much higher netback to producers. This really explains
why there's three trains under construction after only a
year of operation at both the players in Nigeria and
Trinidad and why there's so much interest in the Atlantic
Basin on top of the European growth story which we really
think takes off after 2010. So the range associated with
that netback is an important consideration because it
speaks to the structure of the market, who is taking
capacity in the market place.
Let me be clear about this. When the producers take a
position in the import facility as BP has done at Cove
Point, for example, and as Shell has done through Coral
(ph) in Cove Point, then that producer has paid for that
tariff rate and faces the market directly. When instead
the producer is negotiating with the marketer who's taken
that vaporization capacity, they are dealing with a
marketer who is savvy and will try to capture as much
rent as possible from the market price in that market.
That's, hence, the range that we show of where the
competitive bounds of how much may be split between the
producer interest and the marketers who have taken
capacity positions.
MR. KAROUSOS said that all the port facilities are on the East
Coast and Gulf Coast. There are some new facilities in Mexico and
they think that each of them is feasible. Mexico has a very strong
gas demand potential. So even if they can overcome the
constitutional challenge of opening up the upstream in Mexico which
is currently a monopoly by Pemex; and, if they were bringing
capital draw in of foreign investors by some compromise in the
current constitutional limits to doing so, that supply would not in
any short order, serve the U.S. markets. It would desperately be
needed in Mexico and that's why LNG imports into Mexico are not
attractive even despite the known reserve base in this country.
Both the Northern Baja and the Bahamas are U.S. LNG projects in
sheep's clothing, because they will primarily go to serve U.S.
markets.
MR. KELLY said that the North American gas market is so unrelated,
that Mexico's needs directly affect Alaska's netback - and Mexico
appears set to increase its imports from the United States
substantially over the next five years.
CHAIRMAN TORGERSON recapped that there's a large demand growth in
Asia, but he wanted to know if there was enough supply and
construction to take care of that demand or are there other
opportunities for LNG facilities to meet that demand growth.
MR. KAROUSOS answered:
There's a lot of potential supply chasing markets in Asia
and the Asia Pacific Basin. Facilities under construction
meet some anticipated demand. They don't meet all the
demand that we think will come on line. The potential
supply more than overweighs the potential demand in Asia.
A real wild card is the Persian Gulf and the willingness
of the Persian Gulf to develop its LNG potential at
market with merchant risk and the willingness of East
Asian producers, who are using LNG partly to diversify
their oil dependency from the Persian Gulf, whether
they're willing to sign up new contracts.
There are Persian Gulf contracts into Japan and Korea.
How much they are willing to increase - that is a key
question for Alaska which represents a different kind of
diversification play and a stable political
diversification play from the Southeast Asian sources of
supply (i.e. Indonesia, Malaysia, Brunei). What is it's
competitive position vis-à-vis Australia, which is the
other stable political regime that is really competing.
There is a slight distance advantage that Alaska LNG has
over Australia. LNG into Japan advantage is eroded. When
looking at Korea or China it swings into Australia's
favor.
When you look at the overall cost structure, because most
of that supply is fairly close to the liquefaction
facilities, there aren't hundreds of miles of pipe that
need to bring that gas just to be liquefied. That's a
significant amount of capital that lends an advantage in
terms of cost competitiveness to Australia.
MR. KAROUSOS said the Persian Gulf producers would be affected if
their primary market of India doesn't materialize soon. This is a
very strong risk in CERA's outlook.
CHAIRMAN TORGERSON recapped that Japan was investing in facilities
as a financier to guarantee supply, he assumed. He asked if they
weren't planning on doing it that much any more.
MR. KAROUSOS answered that the power industry is in various stages
of deregulation, as is the gas business, and the challenges that
all utilities face when their market is under threat is a
retrenchment in a willingness to spend capital on new supply and a
reluctance to sign up new longer term contracts, particularly at
the traditional contract terms. This is not a unique situation to
Japan. It is partly why California utilities did not build any
power plants.
There is a real uncertainty in Japan as to whether major capital
will be expended and depend on a fairly certain market that will be
available to absorb that supply or some regulatory structure such
that new supply contracts are disposed of to suppliers who have
captured the market. That kind of uncertainty is never good for new
supply contracts being signed in the traditional manner.
SENATOR TAYLOR said he thought the only thing that would bring this
to a head was if one of our producers actually walked into this
building with a signed contract with someone. He asked what CERA
saw the market forces doing to producers in Alaska to drive the
decision to enter into a contract of a sufficient magnitude that
would justify the capital expenditures necessary for a pipeline up
here.
MR. KELLY answered that for a pipeline, they simply would have to
have confidence in the price, an attractive netback. That's all
there is. They would have to sign a contract before the pipe is
financed. In LNG it may require more of a downstream contract.
MR. KAROUSOS added, "Most certainly a downstream contract." He
continued to say that it would have to be a strong diversification
play on the part of the market to have it happen. There are a lot
of competitive pressures to seeing that realized.
SENATOR TAYLOR said as long as there is long term confidence in
price, someone should develop the pipeline.
CHAIRMAN TORGERSON asked, "What in the short term would be
indicators that may solidify a price in the long term? One is the
summer weather, delineating the fields around the world that are
being drilled right now. Delineate a couple of those."
MR. KELLY answered:
There are a couple of key things they will know about in
the next six months. We will know what 900 - 1,000 gas
directed rigs really does to the Lower 48 supply. We will
have undergone the usual lag time between drilling
activity and new supply. And if the U.S. doesn't start to
show clear indication of a rebound in production, then
there's sort of an [indisc.] going on, because we're
close to rig capacity in the U.S. It would take time to
add a whole lot of rigs. That's probably the leading
indicator.
Number two would be if the economy picks up again and
demand pressure resumes again. The price, therefore,
stays above distillate fuel oil for a full year. I think
that would do a lot for longer term confidence in price
in the U.S. market place.
SENATOR TAYLOR asked if they, "had given any thought or analysis to
advising the state whether we should be the ones moving forward to
take that risk at this point in time and to build that pipeline
ourselves."
MR. KELLY answered if the producing community doesn't believe the
netback is attractive in their own capital allocation process, he
would think long and hard before doing it.
SENATOR TAYLOR said his concern was the constraints upon the
producers may be driven by forces that are totally proprietary to
them and the state will never have any information on it.
MR. KAROUSOS said that broadly speaking there has been a push to
the frontiers and this is partly in recognition that the price
story is real and enduring and it's been led by the majors. They
have been moving out of the traditional basins, abandoning them to
the independents.
MR. KELLY said the seriousness of the money spent by the consortium
indicates that they are obviously looking at it.
SENATOR TAYLOR said in retrospect he was wondering if we would have
been better advised to have built the oil pipeline ourselves than
to rely on the utilization of capital provided by the majors with
capital provided by the majors. "Are we getting a good deal today
with the charge back being charged against us for the
transportation of our oil down that pipeline that they own? Should
the people of Alaska, themselves, own that transportation system or
be seated at the table so we know what's being charged and whether
or not we're getting a square deal out of it?"
MR. KELLY said he thought the technical challenges were much less
today for a natural gas pipeline. The uncertainties are much less
than 20 years ago. The structure of the natural gas business is
different from the structure of the oil business 25 - 30 years ago.
These companies are not very aggressive in participation downstream
unlike oil counterparts.
MR. KELLY said the state should consider table stakes and that
would get them better information.
MR. KAROUSOS said that you often see national or state bodies take
a position so they can get information.
CHAIRMAN TORGERSON said that was on a lot of people's minds. He
thanked everyone for their participation and adjourned the meeting
at 6:00 p.m.
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