Legislature(2001 - 2002)
02/19/2001 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 19, 2001
3:40 p.m.
MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Kim Elton
MEMBERS ABSENT
Senator Drue Pearce, Vice Chair
Senator Rick Halford
Senator Pete Kelly
Senator Robin Taylor
Senator Georgianna Lincoln
OTHER MEMBERS PRESENT
Senator Gary Wilken
Senator Loren Leman
Senator Dave Donley
Senator Alan Austerman
Representative Joe Green
Representative Lesil McGuire
COMMITTEE CALENDAR
Comparison of Northern versus Southern Gas Pipeline Route by
Foothills Pipeline Ltd.:
Mr. John Ellwood, Vice President
Engineering & Operations
Foothills Pipeline, Ltd.
Mr. Brian Blair, Director
Engineering Northern Development
TransCanada Pipelines Limited
WITNESS REGISTER
None
ACTION NARRATIVE
TAPE 01-14, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Senate Resources Committee
meeting to order at 3:40 p.m. and announced they would hear a
presentation from Foothills Ltd. concerning the differences in
pricing of the Southern routes and the Northern routes.
MR. JOHN ELLWOOD, Vice President, Foothills Ltd., said this study
is a joint undertaking of TransCanada Pipe Lines and Foothills Pipe
Lines and it was a due diligence exercise for their companies.
MR. ELLWOOD explained that the figures he was using were pulled
together by Foothills Ltd. and its shareholders, TransCanada Pipe
Lines and West Coast Transmission. It represents the thinking of
their group of companies of how best to undertake the development
of northern gas resources. He said some consultants had input, but
none from other parties who are proposing one or the other of the
routes for their own purposes.
MR. BRIAN BLAIR, TransCanada Pipe Lines, said that first he would
review the merits of the different options and then break that into
cost estimating portions.
They had spent over 50,000 man-hours investigating the different
route options. The objective was to assess the technical,
commercial and environmental merits of each route. The companies
brought their experience and information into the study. They
engaged AXYS Environmental Group as environmental and
social/cultural consultants for each one of the routes, EBA
Engineering Consultants with their Beaufort Sea experience in
designing some of the off-shore platforms (they designed BP's
NorthStar platform), and Pegasus International Inc. (located
Houston) for the marine design portions of the plan.
MR. BLAIR explained that the alternatives they examined were the
Alaska Highway gas pipeline as a standalone project; Mackenzie
Valley pipeline and the combined alternatives of the under-the-
top(UTT) route or the over-the-top (OTT) route; and an Alaska
Highway plus MacKenzie Valley pipeline. The criteria they used in
the valuation were identifying constraints that would be labeled
critical, serious or minor for all of the routes. The definition
they used for critical was potential showstopper, based on either
known technology, current environmental conditions, socio-economic
or political conditions. A critical constraint on a route could
make it in part or in total not viable. So it's potentially an
insurmountable issue.
The next level of category was serious which is either a cost or a
schedule ladder. If something would have significant cost
implications, it would definitely affect the routing of the line,
the timing or the type of construction.
The third category was minor constraints that could be managed with
proper research, mitigation, or advanced timing and would have
minor cost impacts. For brevity, they left the minor constraints
out and are dealing with critical and serious constraints only.
MR. BLAIR said the OTT route is the shortest geographic distance,
but has very serious risks. It is 2,900 kilometers long with twin
42-inch pipelines under Prudhoe Bay and a single 48-inch line going
down the Mackenzie River with an operating pressure of 2050 psi,
initial volumes of 3.3 Bcf/d and ultimate volumes of 5.2 Bcf/d.
He said they had to make some assumptions to do comparisons and
cost estimates. The information they used was from producers in the
Prudhoe Bay area whose initial volumes were 2.5 Bcf/d ramping up to
an ultimate volume of 4 Bcf/d. They designed a pipeline for an
initial volume of 2.5 Bcf/d, which could handle a 4 Bcf/d system
with compression. "Similarly, for the Mackenzie River Delta, the
producers were talking about a .8 Bcf/d pipeline going up to a 1.2
Bcf/d."
The combined alternatives used initial volumes of 2.5 Bcf/d of
North Slope gas coming across and picking up .8 Bcf/d on the
MacKenzie Delta. This would add up to 3.3 Bcf/d going down the
line. Ultimately, that would build up to 5.2 Bcf/d. That would be
4. Bcf/d coming from Prudhoe Bay, picking up 1.2 from the Delta and
coming down as 5.2 Bcf/d.
To move those type of volumes, particularly on the
offshore, the options that we had available to us were,
if you went with a 42-inch and a high pressure, to keep
the gas moving, you'd have to add two offshore
compressors stations or you would be looking at twin
lines offshore. As we got into the study, the technical
feasibility of putting two offshore compressor stations
really became almost an insurmountable option.
So then we opted for the two pipelines. Two pipelines
also give you the added flexibility that if something was
to happen to one pipeline, you could continue to operate.
One of the issues they have is, if you did have an event
on one of the pipelines, your ability to do maintenance
on it, you could be anywhere from six months to a year to
get access into a pair of pipelines. If you're out of
service that long, that's definitely an economic impact
to the producers and the throughput.
Three years construction is what we are looking at. On
the main line portion, you could put a 48-inch pipeline
with compressor stations spaced. The three years
construction is primarily for the 48-inch pipeline down
the MacKenzie Delta area and then we matched in the three
years construction for the offshore.
When we looked at the marine portion, it became pretty
evident that there's kind of three main distinctive
regions. We looked at routing for each one of those
regions. The first one we characterized is foreshore,
where the ice in the wintertime actually freezes right to
the seabed. The idea of that was we were thinking of
being able to construct that in the wintertime off the
ice. Extending that to the next level would be the near-
shore where you would actually be characterized by land
fast ice.
MR. BLAIR explained that pack ice is continually rotating around
the Arctic Circle at about one to five kilometers a day. When it
impacts on the shore, it starts bunching up and starts trying to
push the pack ice right up on the shore. When it bunches up and
overlaps, it actually starts becoming a rubble field or a stamukhi
zone, about four to six meters in height and 47 - 50 meters deep.
When it builds up high enough, it drifts into the shore and starts
creating gouges and scouring of the sea floor.
Throughout the whole winter, the ice pack is continually moving and
building-up on to the shore. In some places it actually scours
straight up the shoreline 0.5 to 2 meters deep creating rubble
fields five to 10 meters high. The area characterized across the
whole route has bottom fast ice for the foreshore 0 to 2.0 meters
deep and ranges from 0 to 2 kilometers offshore. The stamukhi zone
is generally in the 10 to 30 meter depth, which is the high scour
area and typically ranges from 5 to 25 kilometers offshore. The
pack ice zone continually moves and there isn't any way they could
build off of that. "You can't build off the stamukhi because of the
rubble pile and as you get into the floating land fast ice, you
have a potential to build. But if you're trying to put ice roads in
and have been stable for any length of time, you continually get
cracking, which is an issue of stability and safety for ice roads."
MR. BLAIR said the pack ice zone is typically 25 to 50 kilometers
offshore. They made the last zone greater than 60 meters, because
historically most of the scours start dropping off at that depth.
The size of the rubble ranges down to about 50 to 70 meters.
Number 1170
MR. BLAIR explained that the green part of the graph is where the
ice actually freezes to the sea floor, the foreshore area. The blue
is land fast ice and this is where building could occur. The
stamukhi zone is pink and the pack ice is outside that and
continually pushes in. He pointed out that the Barrier Islands
provide a protective break for the pack ice that is pushing down
into the bay area. That is where the producers are looking to drill
offshore.
MR. BLAIR said in pack ice without a sheltered bay, you can drill
where the ice doesn't come right up against the shoreline on a
protected west side. He pointed to the chart showing where the
stamukhi zone is actually impinging almost to the shore for 25
percent of the route, precluding winter construction. He pointed to
an area where producers were exploring on the lee side where some
winter construction could occur.
MR. BLAIR said they looked at two compression stations. The first
was about one third of the way, at Camden Bay, an active seismic
area of recently as much as 5.6 on the Richter scale, a point at
which buildings start falling down. Any compression station built
in that area would have to withstand 6 on the Richter scale and be
on an island in the 30 to 60 meter depth range, like Hibernia with
a floating compressor station. The site would have to be breakable
in case a large ice mass came in and you would have to float it
away. He said they had looked at studies of these situations; the
Air Force had tried to bomb them, the Army tried to drill and blast
them, and they couldn't break them apart. The only thing you can do
is get out of the way. This is one of the challenges with offshore
compressor stations he said.
MR. BLAIR said dual pipelines would be spaced a considerable
distance apart in case a major ice feature came in. If it looked
like the first pipe would be impacted, that line could be evacuated
and the second one could be kept operating - providing some
flexibility and reliability. Hopefully, the first one would slow it
down. He explained that the pipes would be at different depths to
further balance risks.
Number 1200
SENATOR AUSTERMAN asked how they monitored the depth of icebergs
coming in along the length of the pipeline.
MR. BLAIR answered that icebergs move at 1 to 5 kilometers per day
and would have to be continually monitored, probably by satellite.
So you would try to identify which feature would impact the
pipeline. Once it was coming in, you would be stuck with just
reacting.
For winter construction, they would have to put an ice road in
along the route about 350 miles long to maintain support for camps
and all the transportation for manpower and equipment. "Ideally,
you would have staging areas on land, but currently that's not
allowed in ANWR or Ivvavik. So everything would have to be on ice
in those areas. The unstable ice mass pretty well precludes winter
construction and pushes them into the summer construction areas.
MR. BLAIR pointed out an international offshore boundary dispute
that would have to be resolved showing the boundaries on the chart
along with Ivvavik National Park, which has essentially the same
anti-development policy as ANWR. Herschel Island Territorial Park
has a one-kilometer workboat pass where a pipeline could be put,
but there are environmental areas it would come close to. Mackenzie
Valley trough is a tectonic plate that sinks one to two millimeters
per year and has filled in with very soft sediments. So if you put
a pipeline in, it's very difficult to establish a trench or to keep
a trench stable in that area. They started to preclude that area
because of a whole series of environmental issues that started
pushing them onto shore. He noted that the North Slope, management
zone D, needed both short term and long term environmental and
socio-economic impacts mitigated before development could happen.
The consultants identified the Arctic National Wildlife Refuge as
critical for the OTT route, because it precluded the majority of
the route for doing any winter construction and any support on land
for staging areas or camps. Similarly for the Ivvavik National Park
and the Herschel Territorial Parks on the Yukon side. The Barrier
Islands are identified as possible to construct on, but are nesting
habitat for squaw duck and sea duck. In the summer time, it's also
their molting and staging area.
Using satellite photography, MR. BLAIR said, they can tell the
Barrier Islands are actually migrating from east to west - away
from Canada. They are actually eroding on the east and starting to
deposit on the west side. The sub-sea area is continually eroding
and any pipeline would have to deal with that challenge.
MR. BLAIR said the coastal erosion storm surge caught them by
surprise:
Most of the coast is permafrost area, so it's ice-rich
areas. In the August/September storm periods, it actually
melts. The warm water and the waves build up on it and it
actually collapses the banks. So you're actually losing
about one to three meters on the shoreline per year.
Also, if you think about it on the seabed portion of it,
it's actually dropping as well, about one meter every ten
years. That's for about the first half kilometer from the
shore. If you're to put a pipeline in that area and were
to bury it in the first year, in ten years you would have
lost one meter of cover. In 20 years, you've lost two
meters. So, if you buried it with two meters of cover,
you'd have an exposed pipeline.
In extreme events, in the stamukhi zone, it comes right
up to the banks. They've had events where they actually
lost 50 meters of shore in any given year. That was a
significant event. We talked quickly about the Camden Bay
seismicity, which is primarily for the compressor
station.
MR. BLAIR said that the Jones Act requires when working in U.S.
waters, one needs to use U.S. flag ships, which would be used for
lay barges and probably support vessels as well as trenching
equipment. Most of the contractors that have North Sea experience
have international flagships, which would have to be taken into
account.
MR. BLAIR said that coming out of Prudhoe Bay there is a unique
environmental feature called the Boulder Patch with arctic kelp and
all the associated fish and wildlife. This is an area the pipeline
would have to be routed around. The Barrier Islands have migratory
birds and ringed seals. Bowhead whales feed off the Herschel
Islands in the spring and in September/October there is the Alaskan
whale hunt, a key activity for the Native population there. One of
the consultants pointed out that if the activities of the two
pipelines were pushing the whales into the deeper water where they
couldn't get hunted, there could be a requirement to shut down
construction activity. So you might be losing one month out of
their two-month window for construction.
The Mackenzie Valley has two beluga whale zones - one right in the
mouth of the Delta. That is one of the reasons the pipeline was
pushed on shore. The study touched quickly on the eastern North
Slope, management zone D, where they would have to address the fish
and wildlife and preservation of natural uses. Kendall Island Bird
Sanctuary again pushes them on shore as quick as possible. There is
the Inuvialuit beluga whale hunt in the June/July period and the
consequences of that.
For winter activities, Mr. Blair said you would be looking at the
shore approaches building out to where the lay barges would start.
By the end of winter, you would be off the ice and starting land
activities. You would have winter construction building out to
about a 10-meter depth and then the lay barges would take over for
the offshore.
Down in the Mackenzie Valley, there is an evolving regulatory
process with the Canadian government and some unresolved land
claims in the southern Northwest Territories and at the top of the
Mackenzie Valley.
MR. BLAIR showed the committee the gouge density and the number of
gouges per square kilometer at the different depths. In the 20 to
30 meter zone (stamukhi) you get the highest frequency of gouges
per square kilometer dropping off in the 50 to 60 meter zone. The
maximum gouge depth is where the big ice features come in. The
Arctic pack ice pushes them deeper and deeper until they either
ground-out and continue along that ridge from east to west or they
may break up and start pushing in.
From the standpoint of a pipeline, you're looking at
burying not just below where the ice field is, but the
ice field works like a bulldozer pushing and compressing
the ice. If you have a pipeline sitting on the bottom, if
the ice keel actually impacted on the pipeline, it could
buckle it. So you want it down below, so if your ice
pushes in, your pipeline can actually flex in a trench.
So it will start to flex versus actually buckling it. One
of the things you'll have to do is build a wider trench
and that's what the Northstar project and BP did.
MR. BLAIR said that you could backfill the trench with select
material, which Northstar did, so the pipeline would not get
locked in. The shallow areas where there are continual sea-bed
movements is a problem. Even select fill gets eroded out and
filled back in eventually starting to freeze the pipeline in
place.
For the stamukhi zone, if you were to construct in the
30-year area, you would need to have at least three to
four meters of cover - five and a half meters of actual
trench depth. Width-wise, you would have to go about
eight to 10 meters wide. So you're excavating an area
about as wide as this room and half again as high to put
your pipe in. Of course, if you're thinking about doing
that, you're about 60 meters up, you're in water that's
continually moving and the technique you use is actually
called a suction hopper dredger which is like a vacuum
cleaner on the bottom. So you're 30 meters up trying to
vacuum over the same area continually until you get that
kind of depth. You take about a foot at each pass with
the suction dredger.
For perspective, one pipeline actually goes from a wellhead to a
loading facility. It's a two-kilometer line and they buried it
below any of the area of ice scours so they could actually lay it
straight on the bottom. The only time you get the trenching
activity is when you are going from the land out deep enough so
that you pass the shoreline influences. Getting a quote for 500
kilometers of trenching isn't reliable, because nobody does more
than 10 kilometers of trenching.
Number 1900
CHAIRMAN TORGERSON asked what they do with the material.
MR. BLAIR replied that normally at the end of the day, you would
fill up your suction hopper dredger and take it to an area where
you need fill material. In this case, they would probably backfill
the trench with it. It would be very fine material causing
siltation, so the area would have to be contained from adverse
environmental impacts.
Pegasus did some work for them and said that in any of the areas
the width and depth of the trench is really a potential
showstopper. The amount of suction hoppers needed for trenching and
backfilling aren't available and then that turns the project into a
critical timeline period. You would be limited to a 1.0 to 1.5
point five meter trench in the 60-meter zone, which they found was
most cost effective.
MR. BLAIR continued saying that the next item was the restricted
open ice windows. With a lay barge, you have to figure out how much
time you actually have in the wintertime to construct. Over the
years they have a good satellite base and one can see where the ice
starts to break up along the route and starts to form again. He
showed the committee a graph of open water days. He added that
there are areas along the route that are never completely free of
ice. During storm events, the rubble fields will move in and out
and that has to be worked around. Another impact is that there are
about 90 days of open water where the pack ice actually recedes.
Counter to that is the larger fetch, which is the time the wind can
actually build the waves up. So you end up with higher waves. Waves
over one meter in an ice area start to impact on the ability of
support tugs that move ice away from the lay barges and their
anchor lines. The ice will start fouling the anchor lines, so you
have to continually move the it away. If the swells get to two to
three meters and more frequent, you actually have to start shutting
down the lay barge activities. He summarized that there is a high
degree of uncertainty about what year you're going to get the high
open water season. On the probability chart of years 1970 to 1998,
it comes out to a 50 percent chance of having 40 days available for
construction. That takes into account the mobilization and getting
the equipment up into the area around Pt. Barrow from Seattle.
MR. BLAIR said they looked at storing equipment over the winter and
a winter harbor site. Currently, there isn't any place they could
over-winter the equipment. Even if the lay barges were over-
wintered, they would have to be ice-proofed. Currently, all
contractors, like Crowley Marine, move their equipment out at the
end of the season and back in at the beginning. The cost of doing
that versus establishing a winter harbor and winterizing all the
equipment balanced out. He said they are left with a 50 percent
chance of having 39 days for construction (taking into account
mobilization, demobilization, ice days, storm and wait days). There
is a 70 percent chance of having 30 construction days.
MR. BLAIR continued the analysis and said, "If you mobilized all
the equipment up there and hit a year like this year, where the ice
either doesn't allow you to get past Pt. Barrow or doesn't move out
enough that you can do any significant construction, you could be
delayed one year. If you are delayed one year on construction,
that's typically another 10 to 50 percent added to the cost."
The construction days required per line is 150 to 200 days and
three or four pipeline [indisc.] to do that over a three-year
period. They would need three to four lay barges and currently
there's only one or two that are capable of doing the construction.
So they would have to build some lay barges and some icebergers and
tugs for support. Equipment would need to be built for the
trenching and backfilling. However, a delay of one or two years is
like actually buying all the equipment yourself. From a contractors
standpoint, if you're delayed a year, you've probably bought the
equipment as far as the cost goes, but it's not yours. So you might
as well buy it and sell it at the end. You would also need to have
lay barge capability for maintenance. If Foothills designed their
own lay barge, they would probably use dynamic positioning and
those are expensive and haven't been proven in arctic environments.
MR. BLAIR said the conclusions the consultants came up with for the
OTT route was the foreshore route was not viable, primarily because
you couldn't have any support off the land. The nearshore route was
probably not viable because you get into the Barrier Islands and
Herschel Island, sensitive wildlife, ice scour, etc. Additionally,
there is restricted summer access with 25 percent of the route
being very steep with pack ice right next to it. In the summer time
you couldn't get in, if something happened to your pipeline. It's
not safe for the ships to try to use a lay barge to get any vessel
close to shore with the waves. If there were construction in the
summer time, you would have to do the maintenance in the winter
time. A ruptured pipeline in the summer would have to wait six
months for repairs.
They found that the offshore was probably viable with routing
modifications around the Boulder Patch and environmental areas.
Already short season windows of about 40 days could be reduced if
bowhead whales were pushed out of their feeding area.
MR. BLAIR said that despite all the information, there were
significant data gaps. Significant technical design work would be
required with a trench to make sure the pipe would flex instead of
buckle. A deep wide trench to avoid ice scour, even at 60 meters
might need to be wider and deeper. The biggest concerns were highly
unpredictable and uncontrollable weather risks, a short open-water
season and limited access for maintenance. If there were an event
on the pipeline, you wouldn't be able to repair it in the
wintertime, because there are two to four meters of pack ice that
is continually moving. They looked at monitoring using submarines,
but found that diesel submarines don't have the span, so they would
need a nuclear submarine to do leak detection.
MR. BLAIR said the UTT route is 2970 kilometers long and similar to
the OTT route. They kept the same operating pressure of 2050 psi.
Currently, most of the operating pipelines are in the 1000 to 1440
psi. rate. The highest operating line rate now is Alliance at 1760
psi. The study used 2050 psi because they are pushing the
technology, but not so far outside the bounds of being able to get
creditable cost estimates from the venders and suppliers.
TAPE 14, SIDE B
MR. BLAIR said this route follows the Alaska Highway under ANWR,
through the Yukon Flats Wildlife Refuge and ties into the MacKenzie
Delta. It would be a 42-inch pipeline and a 30-inch pipeline tied
in at Inuvik. A 48-inch pipe would be needed for the combined flows
of 2.5 Bcf and .8 Bcf, 3.3 Bcf initially and going to 5.2 Bcf. They
assumed a five-year buildup from the initial volumes to the
ultimate volumes. Over a five-year period, compression would be
added in equal increments to build up to 4 Bcf. They estimated
three years of construction, primarily because of the 48-inch
pipeline challenge in the south. They have access for moving
manpower and equipment up the Highway for over the top and from the
sea. On one side, all the equipment would move into Hay River and
come up the Mackenzie River, which is open two months (mid-July to
mid-September). But they would be stuck with a 700-kilometer
stretch where there is a little bit of access to the Dempster
Highway. The rest of it is essentially a bit of a logistics
challenge. He noted that instead of a two-lane road, they would
need to have a multilane highway for transportation back and forth
and passing. Therefore, the footprint, from an environmental
standpoint, would need to be bigger. So there are more short term
and long term environmental impacts such as opening up a brand new
corridor where the Porcupine Caribou herd migrates.
The one critical constraint that was found for the UTT route was
the Yukon Flats Delta. He originally thought they could go through
it, but consultants talked with the Refuge manager who said one of
the first requirements to build a pipeline through there is that
there has to be an existing infrastructure within the Yukon Flats
area - and there is none. So a natural gas pipeline would have to
feed a community. The next requirement is you have to prove there
is no alternative viable route and there is an alternative route -
following the existing utility corridor. He said they looked at
routing the line following the Highway and coming around and "by
the time you actually do that, you're better off just following the
Highway."
One of the most serious UTT problem is opening up a brand new
corridor with transportation and supply logistics in what is
primarily the Porcupine caribou migratory corridor. The Gwich'in
communities rely very heavily on the caribou for a subsistence
lifestyle. Add to that the evolving regulatory process with the
Canadian government going down the Mackenzie Valley. They would
need a detailed protection plan for protected areas, primarily
because of developing new corridors. Branching off the Mackenzie
Valley corridor and the TAPS, many areas need a lot of base line
environmental information and similar protection plans. Unresolved
land claims in the bottom of the Mackenzie and significant data
gaps through the 440-kilometer corridor make it more complicated.
One of the reasons this route was abandoned earlier was they found
some ice-rich areas that would present stability problems, if they
thawed. So they would have to reroute the pipe or build it up on
pilings like the TAPS.
The conclusion for the UTT route is that it's probably not viable
because of the Yukon Flats restriction and significant data gaps in
the 700-kilometer corridor.
Number 2150
The Alaska Highway Gas Pipeline Project is 2820 kilometers long
following the Highway down through Alaska to the Yukon and into
B.C. He pointed out that they used the same terminus for all of the
routes, at Gordondale, for equitable comparison.
MR. BLAIR said that the Alaska Highway project would be a 42-inch
pipeline, building up compression from 2.5 Bcf to 4 Bcf and two
years construction. The construction time is shorter because both
summer and winter construction seasons could be used and all the
supply logistics are off the Highway, a distinct advantage. He
explained, if a contractor has continual access so he can get
another piece of equipment for whatever reason, he knows he can get
it in off the Highway. But if he is bringing all his material in in
a two month window, like on the Mackenzie, he would bring in more
equipment than was needed, in case something broke. You're stuck
otherwise. If you bring all your equipment in the summer time, you
have to pay for it, from the contractors' standpoint, to be on
standby for the time you're not using it.
There were no critical constraints identified for the Alaska
Highway. Unresolved land claims in the Yukon were one serious
constraint. The conclusion they had was that the Alaska Highway Gas
Pipeline Project was a viable route and had winter and summer
construction seasons.
MR. BLAIR explained that the Mackenzie Valley pipeline route was
1700 kilometers long going from Inuvik to Gordondale. They kept the
same operating pressure of 2050 psi with initial volume of 0.8
Bcf/d to 1.2 Bcf/d and it would take two years to build. He noted
if the volumes go up on any of the routes that the costs and
requirements will go up proportionately. Consultants for the
Mackenzie Valley identified no critical constraints. On the serious
side there were the evolving regulatory process, detailed
protection plans and unresolved land claims. The conclusion was
that the Mackenzie Valley was a viable route, but was primarily
winter construction. The only parts that wouldn't be winter
construction would be the compressor stations.
The first thing they did for the cost estimates was make a Key
Milestone Gantt Chart or a detailed schedule of all the activities
from conception through permitting, EIS, design, procurement of
materials, through construction, preconditioning, conditioning and
operations of the lines. They chose a low-risk option for their
comparison. They assumed permits and regulatory approvals were in
place before committing to material orders. For the OTT and UTT,
that worked out to a nine or 10-year timeline; on the Mackenzie
Valley an eight to nine year timeline and on the Alaska Highway
Project six to seven years. Mr. Blair said that any one of the
timelines could be advanced by taking some calculated risks.
CHAIRMAN TORGERSON asked if the two-year construction time assumed
the materials were already on site.
Number 1900
MR. BLAIR responded that the two years was actual construction
time. Infrastructure would have to be built, which would take about
one year for all the projects. This is when the camps and stockpile
sites are built while the pipe was being fabricated.
He explained that for their cost estimates, they built crews for
each of the sections taking into account variables in terrain,
weather conditions, etc. They got budget cost estimates from the
pipe venders and built on their historical database. Cash flows
were worked out, indirect costs, operating and maintenance costs
were added for the different routes.
MR. BLAIR said the pipe would have to be moved in in the
summertime, but would have it sitting there until it could be
installed in the wintertime.
When you're looking at actually buying your equipment in
advance, you're paying a higher interest during
construction for having acquired either that piece of
equipment early until you actually use it. So it's a
higher financing cost. That actually does play a big role
in the pipeline. But it gives significant advantage to
any of the routes that have similar weather like the
Alaska Highway Pipeline route where you're able to move
equipment and manpower just in time and in advance of
when you actually need it than having to deal with the
weather windows to bring it in.
MR. BLAIR said they would look at on-site fabrication shops for
things like joining two twelve-meter pipes to get a 24-meter pipe.
Fewer joints in field construction means higher productivity. He
said they had modularized compressor and chilling stations in a
southern area, some of it for the Anchorage facilities that are
there.
The objective is minimizing the amount of hookups you need in the
field. Data and control communications would have to be installed
if there wasn't any. Most of the activities need a one-year advance
ramp-up time. Crew size dictates the size of the camp and at -40
degrees, you need to run your equipment 24 hours a day. So you have
to know how much equipment and fuel you actually need to do that.
Down south, you just run it when you need it. In the northern
environment, the length of the construction season has to be taken
into consideration.
Permafrost, buoyancy control and trenching need a lot of research
and development and the productivity rates are different than if
you trench through unfrozen grounds. The study touched on the cost
of stranded construction equipment, which is brought in, but only
gets used during the winter. The indirect costs of business,
financing, community, social and economic are typical for any
project. They have based their estimates on grade E steel, but are
doing some R&D on different grade. So if you go to a higher grade
of steel strength, you can actually reduce your roll thickness and
save money on steel costs and welding time.
MR. BLAIR said they would actually have to prove the chilled gas
decompression theory as with permafrost directional drilling.
Colville River did one directional drill, but it was a small
diameter. So they have to do a lot of R&D to confirm information
and that is built into the cost estimates for things like insurance
and interest during construction and operating costs like salaries,
wages, transportation, materials, accommodations, utilities,
property taxes, overhaul. Fuel gas is not included typically except
for the actual [indisc.] calculations.
He pointed out that their pipeline designs assumed a 2050 psi
output, but that estimate was based on the figures from a year and
half ago when gas was $1.50 - $3.00 range. "If you're projecting
gas in the $4.00 - $5.00 range and are burning it in the compressor
stations and looking at the lowest operating costs of your
facilities over the whole life of the pipe, then you've got
maintenance on your compressors, plus the cost of fuel gas, if
you're having a very compression intensive design. What you may opt
for is a larger diameter line, which usually has a higher capital
cost initially, but over the life of the pipe, you're burning less
fuel gas. So when you're putting a higher price on the fuel gas,
you have to run a more efficient system."
MR. BLAIR said the "apples to apples" cost they came up with was
Alaska North Slope route for 2.5 to 4.0 Bcf/d and Delta 0.8 to 1.2
Bcf; a combined total of 3.3 Bcf to 5.2 Bcf/d. The Alaska Highway
gas project (standalone) starts off with $7.6 billion U.S. adding
up to $9.7 billion using two percent per year escalation. The
Mackenzie Valley starts at $2.7 billion going up to $3.1 billion.
The combined OTT route goes from $11.6 billion to $13.0 billion,
the UTT routs goes from $10.0 to $12.5 billion. The Alaska Highway
and Mackenzie Valley goes from $10.3 billion to $12.8 billion. He
said the ultimate costs are essentially the same for all the
projects. The initial costs are a little bit higher for the OTT
route because of the second line, but the buildup is less, because
there is less compression.
MR. BLAIR said that even though they cost the same to install, when
you balance off the risks associated with each one of the projects,
they found the OTT and UTT have "showstopper" environmental and
technical challenges and other "serious" or cost-adding
environmental challenges greater than the other options.
The conclusion was the Mackenzie Valley was the shortest,
least cost route for the Delta gas that could be advanced
on its own timeline, and had minimal technical and
environmental risks. The Alaska Highway Pipeline project
being linked to the existing utility corridor and
transportation route was the quickest least-cost route
for ANS gas, with minimal environmental and technical
risks.
MR. ELLWOOD said this was the most comprehensive study and
assessment of these alternatives that is out there today.
SENATOR WILKEN asked how much money his consortium had invested in
this year and a half study.
MR. ELLWOOD replied about $6 million U.S. and 50,000 man-hours.
SENATOR ELTON asked if they shared this information with the over-
the-top and the Mackenzie Valley people and what was their
reaction.
MR. ELLWOOD replied that they had shared it last week with the
North Slope producers, the government in Ottawa, and the government
in the Northwest Territories. They have shared it with some first
nations. There were lots of questions from some groups. It is
contrary to the popular belief that the Alaska Highway route was
going to be $2 billion more expensive than anything else.
REPRESENTATIVE GREEN said there were some indications that maybe
instead of 2.5 Bcf/d, it might go to 4 - 6 Bcf/d and asked if they
saw any significant changes in costs with a higher throughput.
MR. BLAIR answered that he thought they would find that they would
all go up in price accordingly.
SENATOR AUSTERMAN asked if there was any discussion of not doing
the Mackenzie and just doing the Highway.
MR. ELLWOOD replied that there was a fair amount of discussion
about which one might go first. People in the Mackenzie are very
motivated. Everyone he has talked to thinks that gas will be needed
from both basins in a very short period of time. "The price can be
kept reasonable by adding new sources, but the demand will grow so
rapidly that we will need both sources about as quickly as we can
go."
CHAIRMAN TORGERSON asked what they were doing for in-state usage
and getting gas to Cook Inlet or any other in-state processing.
MR. ELLWOOD answered that they saw no problem with providing in
some way for in-state use of the gas. Clearly, it was going to go
past Fairbanks and that could be the first place. They need to have
a base and get started.
CHAIRMAN TORGERSON asked when he would have something to share with
the committee.
MR. ELLWOOD replied that he is reluctant to commit more resources
at this time, but he would do his best to get some information
together and to the committee before the end of session.
CHAIRMAN TORGERSON asked if the LNG sponsor group would have
numbers similar to theirs.
MR. ELLWOOD answered that he couldn't speak for the sponsor group,
although Foothills was a member of it. They brought their pipeline
expertise to the group and thought they would see similar thinking.
CHAIRMAN TORGERSON asked if Foothills could be ready for a
permitted project by January 2002.
MR. ELLWOOD said they have a lot of the permits already, but the
main piece missing is the state right-of-way and their application
has been in abeyance for a number of years. They are talking with
state officials about what it would take to reactivate it.
CHAIRMAN TORGERSON asked if the right-of-way had been permitted for
the Mackenzie route.
MR. ELLWOOD answered that it wasn't; the only route that is
permitted is the Alaska Highway project.
CHAIRMAN TORGERSON asked if although it's [Mackenzie] a shorter
route, it would take longer.
MR. ELLWOOD replied that was right. Exploration and development in
the Mackenzie Valley has been on hold for a number of years and
it's just been started again. Quite a bit of work needs to be done.
CHAIRMAN TORGERSON asked if the Mackenzie route would be easier
because it's all Canadian.
MR. ELLWOOD answered that he didn't know that having an
international project added any significant difficulties.
REPRESENTATIVE GREEN asked when they are in the over $10 billion
price, would Foothills want partners.
MR. ELLWOOD answered that they are always open to bringing in new
partners who might "add something to the mix that we don't already
bring ourselves."
CHAIRMAN TORGERSON asked what kind of debt to equity ratio they
tried to keep.
MR. ELLWOOD answered that they try to keep about 30 percent equity
and 70 percent debt.
SENATOR ELTON asked if Foothills would be interested in a spur to
Anchorage or would they react to what someone else came to them
with. He asked whom he meant when he said "we."
Number 600
MR. ELLWOOD replied that he meant "we" in the context of the
industry.
SENATOR ELTON said he anticipated that Foothills would not be doing
the Mackenzie Valley route; that someone else would do it and tie
in. He asked if that was true.
MR. ELLWOOD said that was right. Their shareholders, TransCanada
and West Coast, have a separate joint venture that is working on
advancing the Mackenzie Valley route. Foothills Ltd. is the joint
venture for the Alaska Highway.
SENATOR ELTON asked if they are looking at financing the cost of
$12 million, minus the cost of the Mackenzie Valley.
MR. ELLWOOD responded that they are looking at $7.6 billion
initially for the Alaska Highway project.
CHAIRMAN TORGERSON asked why they are studying the over-the-top
route.
MR. ELLWOOD replied that they are finished with it.
CHAIRMAN TORGERSON thanked them for talking with the committee and
adjourned the meeting at 5:05 p.m.
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