Legislature(2003 - 2004)
06/17/2004 08:45 AM House BUD
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT MEETING
LEGISLATIVE BUDGET AND AUDIT COMMITTEE
SENATE RESOURCES STANDING COMMITTEE
June 17, 2004
8:45 a.m.
MEMBERS PRESENT
LEGISLATIVE BUDGET AND AUDIT
Representative Ralph Samuels, Chair
Representative Mike Hawker
Representative Beth Kerttula
Representative Reggie Joule
Representative Mike Chenault (via teleconference)
Senator Con Bunde
Senator Lyman Hoffman
SENATE RESOURCES
Senator Scott Ogan
Senator Tom Wagoner
Senator Fred Dyson
OTHER MEMBERS PRESENT
Senator Gretchen Guess
MEMBERS ABSENT
LEGISLATIVE BUDGET AND AUDIT
Representative Vic Kohring
Senator Gene Therriault, Vice Chair
Senator Gary Wilken
Senator Ben Stevens
SENATE RESOURCES
Senator Ben Stevens
Senator Ralph Seekins
Senator Georgianna Lincoln
Senator Kim Elton
COMMITTEE CALENDAR
Alaska Natural Gas Pipeline Issues/Pipeline Costs & Tariffs
Presentations By:
Mr. Harold Heinze, Chief Executive Officer, Alaska Natural Gas
Development Authority
Mr. Roger Marks, Petroleum Economist, Tax Division, Alaska
Department of Revenue
Mr. John Carruthers, Vice President, Northern Development,
Enbridge Pipelines, Inc.
Mr. Robin Brena, Partner, Brena, Bell & Clarkson, P.C.
Mr. Tony Palmer, Vice President, Alaska Business Development,
TransCanada Corporation
ACTION NARRATIVE
TAPE 04-9a, SIDE A [BUD TAPE][SIDE B IS NOT RECORDED]
CO-CHAIR RALPH SAMUELS called the joint meeting of the
Legislative Budget and Audit Committee and the Senate Resources
Standing Committee to order at 8:45 a.m. Senate Resource
Committee members Tom Wagoner, Fred Dyson, and Scott Ogan,
Chair, were present. Legislative Budget and Audit Committee
members Con Bunde, Lyman Hoffman, Mike Hawker, Beth Kerttula and
Reggie Joule were present. Senator Gretchen Guess and
Representative Bill Stoltze were also present.
CO-CHAIR SAMUELS announced that Mr. Heinze would present to the
committee first. He informed members that Mr. Heinze is the CEO
of the Alaska Natural Gas Development Authority (ANGDA) and has
been involved in North Slope gas issues for over 30 years. He
was ARCO's engineering manager of the Prudhoe Bay field start-up
in 1977 and was the President of ARCO-Alaska and ARCO
Transportation during the 1980s. During the Hickel
Administration, he was the commissioner of natural resources and
the state-to-gas marketer.
MR. HAROLD HEINZE, Chief Executive Officer of ANGDA, jested that
he has appeared before legislative committees many times in the
last few years but this is the first time he is appearing
without requesting any money. He told members that he is not an
expert on tariff issues; instead he will discuss cost related
issues and the elements that go into a tariff determination. He
said he would focus on the in-state issues because ANGDA's
interest is what happens within Alaska. He then gave a
PowerPoint presentation [paper copy available in committee
file], with the following explanation.
Number one, this is sort of the slide J.P. Morgan
showed you yesterday of a number of things that go
into the tariff and, in particular...the goldish color
were the ones they talked about the sensitivity and
gave you some results. I'm going to talk mainly about
the ones that are circled in red and then I think
between myself and Roger Marks, who follows me, we'll
pretty well will have covered about every arrow on the
page here by the end of the three or four
presentations. Additionally, I'm going to give you
some thoughts that we have, from our point of view, in
terms of some of the projects we're looking at in
terms of the relationship between debt-equity ratio
and the bond rate and how that might affect the
tariffs.
Here [indisc.] is the outline. I hope it's not too
daunting but I intend to go through it pretty fast and
we can come back and spend time wherever you wish.
Number one, I just wanted to make sure we understood
ANGDA now is working on three basic things, the first
of which, of course, is as prescribed in the ballot
measure was to look at an LNG project and we are.
Secondly, we've been asked by the Administration, as
part of the broad Administration effort but separate
from the Stranded Gas Act work that's going on, to
look at ways that ANGDA as a public corporation of the
state might be helpful in moving forward any of the
highway gas line projects and there are ideas we have
there in terms of how the state might participate and
facilitate the project moving forward.
And then finally, we've been asked very specifically
to even go beyond the spur line requirement of ballot
measure 3 and look very specifically at how we might
get gas to Cook Inlet. Right now, as required in
ballot measure 3, there is a requirement that was
th
actually - we passed a couple of days ago, on June 15
to issue a report, a development plan, competency in
about 11 different items. We're frankly late on that.
We're going to do that by about mid-August. We believe
that is a reasonable timeline. In addition, we'll put
out at that same time a report on how we believe Cook
Inlet gas or North Slope gas could be brought to Cook
Inlet.
To put it in perspective for you here, I listed out a
list of the projects that I'm sort of aware of and the
price tags that are thrown out as being associated
with them. You heard yesterday from the Port Authority
with their Y-line concept that weighs in at about $26
billion. The producers have talked about a highway gas
line, very large in diameter, maybe 52 inches, down
through Canada and all the way to Chicago for about
$19 billion. We've heard from Enbridge and a little
bit from TransCanada at this point of maybe a little
more modest highway project weighing in at about $15
billion to Alberta. If you remember back, Yukon
Pacific had described an LNG project for about $12
billion out of Valdez. The one we're looking at would
be about $10.5 billion. Additionally, a number of
years ago, some Cook Inlet companies and some North
Slope companies looked at a project for 1 billion
cubic feet a day out of Cook Inlet and that was a
little under $7 billion. We are looking at a concept
of a bullet line - a small line direct from the North
Slope to Cook Inlet and that would weigh in at about
$2 to $3 billion and, additionally, we're looking at
the spur line.
ANGDA itself, as you can see by the chart, is tending
to look at the lower side and the very Alaska side of
these issues, not to say we don't try to learn from
and keep up with what's going on in the other projects
and, frankly, look for ways to interact with them
because, for instance, the concept of a spur line -
who gets the gas to where - is a very important part
of that notion.
But this is kind of the suite and even though the
focus of this hearing and the focus of everybody's
effort is very clearly at that producer project at $19
billion, it's very important that you realize all of
these other potential projects are on the table. And
the reason, simply put, is a $19 billion project that
requires the approval of a half-dozen to a dozen
entities has a chance factor of actually going forward
but it's kind of low, and so you have to have other
projects in the screen or we're going to end up sort
of hitting the wall, being stopped, and having nothing
to do at that point.
The LNG project in particular that we're looking at is
portrayed on this chart. Keeping in mind that a gas
conditioning facility and the first 530 miles of
pipeline is common to almost everybody's project. This
one happens to be a 36 inch line, which is the same
size, for instance, that Enbridge proposed for going
down the highway. But it is definitely smaller than
what the producers have talked about.
The liquefaction trains here are very large. They
reflect the latest kind of a technology that's been in
use. There is capital money included for a tanker
fleet that is a mixture of foreign flag and Jones Act.
And, again, we don't intend to own those tankers. We
would contract for them basically. But to get a feel
for the cost of service and to be comparable to other
projects that deliver to a market, we felt it was
important to include the money.
The other basic piece of ANGDA's work in looking at
the LNG project has to do with the benefits diagram
and a number of you have seen this before. In addition
to just measuring a project's return in terms of just
dollars to the State of Alaska, you have to look at
the full suite of these benefits. We have just
completed, and it is now available publicly, a
benefits model, a huge spreadsheet model that
incorporates not only the revenue side, but all the
whole economic impacts and all the other things. In
addition you'll notice in here we've included the
provision for moving gas to the coastal communities,
moving gas for LPG to the river communities of Alaska.
We think that's a very important part of it. So that
is the totality of our focus.
It turns out that when we look at all these issues,
our business model is very clear. If we can provide
the lowest cost of service, delivery of gas, that is
good for everybody. It encourages everything good to
happen on the North Slope. It encourages everything
good to happen in Alaska in terms of our own
consumers, our own industries, everything else and,
frankly, it's good for the ultimate customer down in
the Lower 48 or across the seas.
If you take the $10.5 billion that we're looking at in
our capital cost and recognize that it's a 2 billion
cubic feet a day project, we go through a calculation
of a cost of service. This is similar to the kinds of
calculations you saw yesterday from J.P. Morgan. I've
shown two cases here. The top one is a 30-70 split on
equity to debt and a 12 percent return on equity and
an 8 percent bond rate basically on debt. And you can
see the calculation here would yield $2.51. Again, the
way you use this kind of chart notionally is then you
would add to that a wellhead value, let's say it's a
dollar - or 99 cents to keep the arithmetic easy -
getting $3.50. You could then compare that $3.50 to
your expectation of price in the market. If you
expected a $3.50 price in the market, what that would
say is that you have a project that can realize 99
cents at the wellhead and still yield a 12 percent
return on equity and pay a debt rate of 8 percent.
And the alternative, if you change the debt-equity
structure and you make some different assumptions on
what the bond rate is, that number goes down in this
case to $1.94. And again, all these calculations have
been made using a model that was developed and is
available publicly from Roger Marks in the Department
of Revenue. I've used that as the base model for all
our calculations. It is also the model that is
embedded in our benefits spreadsheet model and
everything else. And, very frankly, I would encourage
apples to apples that while people might want to look
at projects other ways, it's kind of helpful if they
do the calculation also with this model so we can get
a handle. And that's why I showed you the second
column on this. This is the producers' $19 billion
project plugged into the same model and this is the
result it yields. You'll notice it's a slightly lower
cost of service to Chicago and it has some other
characteristics that are positive. Again, we think
it's very important to explore all of those issues and
see how they fit together.
I guess I wanted to just add a little bit of a flavor
here. As ANDGA looks at this, it is our belief that
for smaller projects that are undertaken by a state
public corporation acting as a utility, we could
achieve very high debt rates and very low bond rates
on those. Now, certainly for bigger projects measuring
in the 10s and 20 billions of dollars, I think the
advice you heard probably yesterday from J.P. Morgan
is more indicative. But we still believe that
something in this range of say 70 percent debt-equity
ratio is very achievable. We believe also that the
state has also probably more modest equity
considerations than others. And I'll show you how that
comes into play towards the end of this presentation.
I did want to reflect to you a couple things that are
going on and, again, just in a general sense, say to
you this is why you need to keep revisiting this issue
because I know the legislature visited very heavily
two-three years ago the gas issue. Well, I hate to
break it to you, but the world's changed and that's
what this chart shows. Up until several years ago the
United States, because of the great excess of gas
supply to demand, had the lowest price in the world
for gas. What we've seen is that supply go away. We've
seen the price rise as you would expect and, more
importantly, we're seeing the world price of gas
converge. All those dynamics are very powerful. One of
the things in that convergence is LNG and moving gas
between various producing countries all around the
world to various marketplaces and we should see some
equilibrating of that price, very similar to what
happened to oil.
Now we don't necessarily believe a 'gas PEC' or a 'G-
PEC' will form that fulfills that same function of
supply demand price balance but it is very clear that
the five mega-major oil companies, British Gas and
maybe a couple of the Japanese trading companies, will
be the major players controlling that gas flow and
it's reasonable to expect that we will see something
happen that is not unlike what happened on oil.
Again, we have looked at our project compared to the
projects around the world. Certainly we understand
why, for instance, British Petroleum and Indonesia may
choose to develop that gas and move it as LNG to Baja,
California. Those are things that each of the
companies, each of the players in this, will make an
analysis. One of the more interesting comparisons we
would point out to you is that Shell, who does not
have any Alaska gas, is a major player in LNG, and
they chose, without any contracts or any other
commitments to develop Sakhalin - and Sakhalin is, by
comparison to our LNG project, Sakhalin is $10 billion
for 1.3 billion cubic feet a day, - and if you think
about our project as...$10.5 billion for 2 billion
cubic feet a day, you can see that we probably compare
very favorably in terms of economics. And that's what
our broad look says, is that broadly we are in the
pack. We are certainly not the highest cost. We are
certainly not the lowest cost but we can compete, we
believe, with all these projects.
Also there are some distance advantages we enjoy to
the West Coast and some of those may be difficult to
capture if we act exactly like the mega-major oil
companies. The great part of being ANGDA is as this
public corporation of the state, we don't have to act
like the mega-majors, we can look for other ways to
compete in the marketplace with them that are
different than their strategies. And again, we don't
have a portfolio of projects. We have basically one
project and we have to find a way to make it work.
On the LNG scene, there's also some very good news.
What we've seen is a dramatic decrease in the unit
cost to build these plants and liquefy the natural
gas. And again, I've identified the source of this
chart. I left BP's identity on it. It was presented in
Washington, D.C. about six, seven months ago. So I
mean it's very recent information. It's very real.
Almost everybody has observed this trend. One of the
things we will do by August is validate the trend and
validate whether it is applicable to our situation
here in Alaska. This makes the difference, this chart,
between an LNG plant that costs $2 billion, $3 billion
or $4 billion. I've taken the conservative approach of
using only $3 billion right now but potentially if I
took this chart at its face value we could write down
$2 billion for that. Those kinds of cost savings
dramatically alter your economics.
Additionally, the world trade right now in terms of
LNG tankers with all the number of tankers being built
in a wide variety of places around the world, there's
a very definite trend downward and how that translates
for us, how the Jones Act issues get worked, is going
to be a subject of our report. We're very cognizant of
those issues. But this is a very favorable trend and,
again, this is from the Department of Energy so I have
every reason to believe the U.S. Government's got this
one right.
I wanted to take a minute and talk a little bit about
pipelining costs and the reason is that everything
you've heard over the last several days involves
anywhere from $2, $3, $4 billion on up to $8, $10, $12
billion worth of pipeline and underlying those costs
are cost estimates. And what I did was I pulled
together here a whole series of estimates and actual
costs covering a fairly wide spectrum of people's
opinions on cost. For instance, the last time the
legislature looked at this about three years ago, the
detailed cost estimates that were made - tariff
calculations and all that, were based on the concept
of $140[,000] per inch diameter mile. In other words,
what you do is you take the billions of dollars of
cost, you divide by how many miles that pipeline is
and by how many inches in diameter it is. It's a way
of kind of equating different size pipelines,
different lengths, and everything to one number. It's
not certainly a requirement of science that they all
be exactly the same but generally, in an estimating
sense, one would expect them to be very similar. And
in the past the number that was used was $140,000 per
inch diameter mile. Well the producers, after spending
$125 million, have published a number, which is
$115,000 per inch diameter miles, and somebody forgot
to say thank you to them because they just saved 25
percent of the cost of the pipeline. That's a
significant reduction. Again, that makes a lot of
difference in these numbers.
Now, at this point do we have any of the information
that allows us to know if that's just a result of
somebody else doing the estimate? And I will tell you
as an engineer sometimes that happens. People estimate
things different. Or, is there some legitimate thing
that we can understand? Is it better trenching
techniques or something? Is it a technological
innovation? Does it have something to do with the
metallurgy of the pipe or whatever? Maybe there is
some difference there.
The other part of it is that the actual experience in
the Lower 48, the last big pipelines that were built
in Canada, and these are big, long distance, large
diameter pipelines, came out on comparative cost to be
a factor of three or four lower than even the
$115,000. And it seems to me that again, my
engineering instincts tell me that I need to
understand why building a pipeline in Alaska is three
or four times more costly than building it in the
Lower 48. These issues are not trivial because as a
legislature you're going to be asked to make decisions
- multi-billion dollar decisions. And what that
pipeline number is has some real significance in which
way that decision may be affected or altered or looked
at. So again, we're hopeful that over time, available
to the public and for some level of scrutiny is some
of the background that kind of goes with these
numbers.
The other issue I wanted to broadly flag to you is
that with the array of projects on the table, I think
it's kind of good to go back to basics and that's why
I included this table, which just kind of shows for a
whole bunch of different pipe sizes the implied
nominal capacity and, more importantly, the implied
reserves that go with it. And again, the way you would
use this table is if you were looking at a 36-inch
pipe, its nominal capacity is roughly 3 billion cubic
feet a day and for something - say a 30 year life,
would require about 22 trillion cubic feet of reserves
to support that type of a pipeline. Now that's a
pretty significant consequence. Again, I'm going to
show you some of the variations that take place as you
vary the reserve but 22 trillion is very close to what
is not only known but developed on the North Slope in
terms of Prudhoe Bay. The bigger number, 35 trillion
we talk about, is what is quote, known but it is not
necessarily developed. And again, as a petroleum
engineer type, as a former oil company type, I'm not
particularly scared by that difference but the bankers
might be. The people that you go to borrow money from
would look very differently at the 22 trillion cubic
feet as opposed to say the 35 or the 50 trillion cubic
feet. And, as you can see, it does make some
difference in this.
The other thing is that we put together this chart
just to try and show you the full range of
possibilities. If one wanted to look at a bullet line,
for instance to Cook Inlet, if that's the only project
that we could see happening within the next several
decades, it could be a pretty small diameter pipeline
and I'll show you a little more about that in this
chart. After the hearing yesterday I went home and, of
course, instructed the ANGDA engineering department to
get in gear and do some calculations for me.
Unfortunately the graphics art department was on
vacation yesterday so you have to accept the hand
drawn version but at least I do have a scanner and my
green graph paper at least is on a PowerPoint slide
so.... What this chart is trying to illustrate to you
is the fact that as you get to larger and larger pipe
sizes, you will always get a lower tariff if the
pipeline is full. But if you look at how the decrement
of cost goes, once you start to get above 36 inches,
you're into a huge pipe anyway and so going huge-huge
does not change the tariff, if you will, by a lot.
The other dash lines on here show you what happens if
you put in a pipe but you wrong size it and you don't
have the ability to flow through it at that. And as
you can see, that penalty can add up pretty fast in
certain cases. So again, the term I would use is, you
know, you got to right size the pipe. You have to make
sense of what pipe size you select in terms of what
you think the volume is. For instance, if you put in a
pipe to handle 4.5 billion cubic feet a day but the
market gags for the first five years and can only
accept half that volume, there is a very significant
increase in the tariff, maybe in the order of 50 cents
for that one happening. So again, you have to be very
careful that you get it right in terms of reserves, in
terms of market volume and everything else. Again, I
flag that to you because as a great student of the
public record, I will tell you there is nothing out
there at this time that tells us about what the market
volume for North Slope gas might be. There's nothing
you can look at that will tell you whether the market
for North Slope gas is say 2 billion cubic feet a day,
as one of the Stranded Gas Act applicants has said, or
4.5 as another applicant has said, or 6, as another
applicant has said. There's nothing out there on the
public record that allows you to look at that
difference and it does matter, and it is important.
This is a very unsophisticated calculation but 800
miles in this case, by the way, is significant because
800 miles represents roughly the distance from Prudhoe
Bay to the Canadian border. It represents roughly the
difference between Prudhoe Bay and Valdez and Prudhoe
Bay to Cook Inlet. So again, you're looking at a
chart, which portrays for different volumes and pipe
sizes roughly the pipelining cost or tariff for any of
those cases.
Here's an example of the kind of calculations, and
again, I've done this with the revenue department's
model that Mr. Marks developed and again, you can run
cases until you're blue in the face on this. This is
just one looking at the reserve assumption for both
the LNG project and the highway project. What's
interesting is that if you kind of look at the middle
line there, if I move about the same amount of
reserves through both projects, even though it takes a
lot longer in the case of the LNG project, then you
would expect roughly the cost of service to be about
the same, and that's what the chart, the model,
calculates in this case. And it's just a method of
looking at the comparison. Again, you can see what
happens in the highway project, the bottom right-hand
number, if there is not enough reserves. If you build
a project thinking there's 50 but only half shows up,
that does dramatically change the cost factors.
And then finally I just sort of - because I really
don't have maybe the time this afternoon to really
participate, I wanted to offer you one thought about -
as you kind of look at how tariffs might be built and,
again, the advantage of having ANGDA in this whole
fray is that we are able to think constructively and
creatively about how to make the project work. And
frankly, my trips to the Lower 48 and my interactions
with a variety of people that kind of quote, represent
the market say that Alaska has to find some way to
have a little more customer appeal. And I think one of
the ways to do that is to look at some conceptual
variable tariff methodology, which basically invites
the customer to share and help us get over our hurdle,
which is low prices and, at the same time, offer the
customer what they want, which is some discount at
higher prices. And in talks with regulators, this
kind of a scheme, conceptually at least, is very
appealing to them. And what I've portrayed here is
simply, for instance, if the market price, whatever
that means, is say $3 or less, basically the customer
would be willing to pay an upper floor of $3 and
basically there would be for transportation and
production a split that was agreed to on that. As the
market price went up, there would be a split of who
garnered whatever price increases there were here. And
as you'll notice here in this case, I've allocated a
greater part of the increase to the wellhead than to
the gas line or to the transportation charge. And then
above a certain point, the gas line charge would fix,
basically, at a maximum and then the wellhead would
offer some discount to the customer in return. And
again, the advantage is that this kind of a scheme
would allow you more favorably to borrow money
frankly, because by having the customer participate in
the form of the guarantee at the low end, which is
what the banker worries about, is a very powerful
thing because again, these customers tend to have very
big asset bases. They have very captured sets of
customers. They are using monopolies - regulated
monopolies, and all those things. At the high end,
very frankly, giving up some discount at the higher
prices may be the price of getting all this to go and
some scheme like this may work. I don't know. Again,
these numbers are for illustrative purposes only and
obviously that would be subject to a lot of multi-
party discussion and other things so it's just an
idea.
Mr. Chairman, with that I'll quit and entertain
whatever questions you have. I did include several
other sort of handouts and pass outs of other things
that are going on or other things that people have
said about us or whatever.
SENATOR TOM WAGONER said he was cautioned, during a conversation
about FERC controls, to be cognizant that FERC has more of the
control over that pipeline and sometimes asserts certain
controls over what is put in the pipeline and the delivery
point. He asked if that is true.
MR. HEINZE said his personal experience with FERC related to oil
pipeline issues but FERC can do just about anything it wants to
do. He said sometimes the logic of its decisions is not
apparent. He noted that ANGDA's biggest concern right now is
that the conditions for getting gas off a big pipeline, the
highway pipeline for example, may be very difficult to
negotiate, especially with FERC, because [ANDGA] does not have
any great standing on a national level. Second, the lost
revenues of gas taken off within Alaska would be counted as a
cost against the tariff ANGDA is charged, which is of concern.
He said that is a fancy way of saying that ANGDA might have to
pay the full fare even though it took gas off only one-third of
the way down the pipeline. He said he can find no guarantee that
Alaska won't find itself in that situation. He offered that
ANGDA has proposed that it be an investor in the project, at
least for the volume of the gas that it would like to see used
within Alaska. That way, ANDGA could provide some protection for
the tariff and off-take point within Alaska. He said in the long
run, that is an issue that will have to be guaranteed through
the Stranded Gas Act and other proceedings. ANGDA's approach
continues to be the positive one, and that is by being an
investor, which lessens the risk of the other parties and leaves
ANGDA in direct control of what happens in Alaska.
SENATOR LYMAN HOFFMAN referred to the ANGDA chart entitled
"Benefits to Alaskans" and asked how much work has gone into
calculating the feasibility of delivering LNG to the river
communities and to barge LNG to the coastal communities.
MR. HEINZE said last Friday he met with the municipal advisory
group on the Stranded Gas Act and showed that group, in detail,
this benefits analysis spreadsheet. He said one of the major
factors would be fuel costs - power cost equalization and the
cost of fuel in rural communities and other places. He said that
ANGDA is trying to go beyond the "pretty drawing" and is
attempting to reduce those benefits to hard numbers. [End of
TAPE 04-09, SIDE B]
TAPE 04-10, SIDE A
MR. HEINZE continued by saying second, ANGDA believes that on
the rivers, propane may be the better way to meet the energy
needs of many rural villages. ANGDA believes gas can be moved to
the coastal communities in the form of LNG or compressed natural
gas. He explained the reason to liquefy natural gas by cooling
it to cryogenic temperatures is that it provides a 600 to 1
volume advantage. It weighs the same but fits in a container
1/600 of the size. Compressing the natural gas to about 2500
psi can reduce the size of the container, and that volume
advantage is about 100 to 1. Although the volume advantage is
not as great as that of LNG, the cost makes compression a very
competitive idea. ANGDA believes that compressed natural gas is
certainly a possibility for many of the coastal communities.
ANDGA has looked at the idea of barging LNG. A small LNG plant
located in Cook Inlet could be the source for the LNG
distributed to the coastal communities.
MR. HEINZE said ANGDA has estimated that bringing North Slope
gas to the [Anchorage] area will provide about $100 million of
disposable income per year in this economy, the equivalent of
adding $150 million in payroll. He said ANGDA believes it must
be prepared to implement some of the benefits no matter what
project goes forward.
SENATOR HOFFMAN said the problem with propane in rural
communities is that it is used primarily for cooking, which is
not the largest consumptive use. Electricity is generated with
diesel and many of the communities would be interested in
converting to LNG for heating and to generate electricity. He
expressed interest in seeing a comparison of the LNG numbers for
heating and electrical generation.
MR. HEINZE replied that compressed natural gas may be an ideal
feed for a very efficient gas turbine unit. Almost any clean
hydrocarbon fuels, whether ethane, propane, or methane, are very
good feeds for anything resembling fuel cell technology. The
advantage of propane is that any appliance can run on propane
and any hardware store has the gadgets necessary to hook it up.
He said right now, the municipal advisory group under the
Stranded Gas Act has hired a contractor to look at the total
socioeconomic impacts. That study will answer some of Senator
Hoffman's questions about the best fuel source for each
community and should be available within a matter of months.
SENATOR WAGONER asked what impact a bullet line from Fairbanks
or Delta to Cook Inlet would have on current exploration and
production in Cook Inlet.
MR. HEINZE said he provided some background information on Cook
Inlet and explained that Cook Inlet is down to 2 trillion cubic
feet, while the amount used per year is roughly 200 billion
cubic feet. That amounts to a ten-year supply. He commented:
When you get down to a 10-year supply, a lot of things
stop working in terms of borrowing money if you're a
utility so basically Cook Inlet finds itself in a
situation where it probably needs to replace every
year just about what it consumes. The good news is
that can be done. The bad news is to do it, it's going
to cost more money than we pay right now for gas. The
replenishment probably has to take place at prices
competitive with the Lower 48, because that's what it
takes to attract capital to explore for the gas here.
If North Slope gas with a very large supply was hooked
to this area, it is reasonable to expect that the
prices would return to today's levels. Roughly today,
the prices are about $2.50 wholesale. It's expected
that the new prices, you might say, will eventually -
and in about five years that's what we'll pay - is
something double that, about $5. The availability of
North Slope gas into this area as a large supply would
probably take the prices back to $2.50. What it would
probably do is discourage exploration in that sense.
The exploration that is taking place now, the
decisions people are making now, they are selling
under long-term contracts at very nice prices.
So, what would I predict? I predict that people who
find gas now are going to get a good price for it.
Would I predict that they should wait five or six
years to go looking? No. I mean if it was me, I'd get
on with it right now and be uncertain as to the
future.
CO-CHAIR SAMUELS thanked Mr. Heinze and called Mr. Marks to
testify. He told members that Mr. Marks has been a petroleum
economist with the Tax Division of the Department of Revenue
since 1983 and that much of his recent work has focused on
analyzing the commerciality of North Slope gas.
MR. ROGER MARKS, Department of Revenue, told members his
presentation would focus on the impact of property and corporate
income taxes on tariffs. [A paper copy of Mr. Marks's PowerPoint
presentation is located in the committee file.] He began:
Just to review on what the elements of a tariff are, a
tariff is simply a way of passing through all of the
costs and so the pipeline owner can be reimbursed for
all of his costs and also make a profit. There are
different ways to characterize the costs. I've put
them into seven different categories here: capital
costs, which are recovered through depreciation over
time and include interest during construction and, on
the equity part, funds used during construction;
operating costs; debt or interest costs; property
taxes; state and federal corporate income taxes; and
the return on equity, which is the profit element,
which we'll discuss in some detail.
So starting out with the property tax on page 3, the
property tax administered under AS 43.56 is based on
20 mills, or 2 percent of the remaining value of the
pipeline at any point in time. Value is determined
based on both a cost or income approach by our
assessors. Since it's based on remaining value at any
point in time, it starts high and declines. Any piece
of property that's within a municipality, they retain
their share of the property tax up to their mill rate
and the state gets the remainder. In other words if, I
believe, the Fairbanks North Star Borough, their mill
rate is I think about 15 mills now, so they would get
15 mills, the remaining 5 mills would go to the state.
On the producers' proposed project, the $19 billion
project to Chicago, the portion of that in Alaska is
about $7 billion, which includes the conditioning
plant and the pipeline part. My estimate of the
property tax part of that would be about 8 cents on
the tariff.
Page 4 - in thinking about the economics of the
project and the viability, there are a couple of
issues that the property tax presents that are
problematic to some extent for the pipeline. The first
is that the property tax is what we call front-end
loaded. The way we administer the tax through the law,
the tax starts accruing as soon as property enters the
state, which could be years before it goes into
service and starts producing revenue. On the time
value of money, paying those taxes reduces the rate of
return. And again, the interest and funds used during
construction accumulate and are put in part of the
tariff base.
The second problem with the property tax is what's
called regressive and regressive, in terms of tax
terms means that when profits are low, the taxes are a
high percentage of the profits and when profits are
high, taxes are a low percentage of the profits. The
regressivity part creates an economic problem again
when profits are low.
In the case of the property tax, one of the big risks
of this project is a cost overrun. If there is a cost
overrun, not only do you have a cost overrun, but
since the property tax is based on value, not only are
your costs higher but your property taxes are higher
too, which kind of presents a double whammy.
In the Stranded Gas Development Act, a couple of these
problems have been presented as issues that could be
addressed in negotiations with project sponsors, the
idea being there may be a way to modify the property
tax. This has naturally created a lot of concern for
the local municipalities in terms of their tax base
being modified. With the highway project, it would be
the Fairbanks North Star Borough and the North Slope
Borough who would be affected if the property tax is
modified. Per the Stranded Gas Act, it says that if we
do develop a contract with the project sponsors, that
a fair and reasonable share of the amount of money we
take in as a state should be given to both revenue-
affected communities, which are ones whose tax base is
being affected, and economically-affected communities,
ones who are bearing social burdens because of a
project, that a fair and reasonable share of the taxes
should be given to them with due regard to the amount
of the tax base, the amount of the social burdens.
A municipal advisory group has been established for
the Stranded Gas Act to address concerns that the
local jurisdictions have over modifying the property
tax and that group is up and running.
That's really all I have to say about the property
tax. I was going to go on to the corporate income tax
now on page 5. In understanding the corporate income
tax, it's important to sort of understand just what
the source of income is that's being subject to the
tax and, as we saw back on slide 2, the tariff is made
up of several elements and all those elements are
costs that are recovered through the tariff. The
return equity is not a cash flow cost. What the return
on equity represents is an allowance for an
opportunity cost for the cost of equity and, again,
that represents the income that's subject to the tax.
On page 6, there's an example showing a simple
derivation of the return on equity. Just in this
example we assume a $500 asset that's 80 percent debt
and 20 percent equity so the equity part of it would
be $100. And let's just assume it has a 5-year life
and it's depreciated, I just assumed for this example,
a straight-line depreciation where there's just $20
depreciated each year for 5 years. There are other
methods of depreciation that are allowable under FERC
methods, depending on whether you want to get a
declining tariff or an increasing tariff or a
levelized tariff, but just a real simple method for
the example here, it's just a straight line
depreciation. And so, you can see if you start out
with $100 and depreciate $20 each year, the third
column shows the undepreciated amount each year and
then assuming a return on equity of 10 percent, the
return on equity in each year would be 10 the first
year, then 8-6-4 and 2. Under long-term capital
markets, return on equity would probably be something
around 12 percent. It would really depend on just
exactly when the pipeline comes into service and what
the capital markets are at the time. I just used 10
percent here because it's easier to multiply by 10
percent in looking at these figures.
But this return on equity represents the income that's
subject to taxation and I'll just note here with this
straight-line depreciation, you get a return on equity
that declines each year and this would produce a
declining tariff. Again, there are different
depreciation methods you can do to have either a
levelized tariff or an increasing tariff.
On the debt side there's a mirror image in terms of
the tariff also. A similar way to calculate the return
on debt, in this case it would be with 80 percent debt
it would be a $400 debt that there would be return on
debt. The debt would have a lower rate of interest.
Again, the long-term capital markets - that would
probably be about 8 percent. Again, that depends on
just when the pipeline is built and the capital
markets at that time. On the debt side of this, what
we call the return on equity here, the return on debt
would actually be interest payments and those - again,
it would be an element in the tariff as well. But this
return on equity is not a cash flow cost but
represents again the income subject to taxation.
When talking about the state corporate income tax,
it's useful to know how it works on page 7. The state
corporate income tax - and income taxation in most
states is administered by a method that's called
apportionment where either U.S. income or worldwide
income is apportioned to the state and that becomes
the income subject to taxation. The reason states use
apportionment rather than an actual sort of cash flow
method of measuring income - an example that's used is
sort of if you have General Motors producing cars in
Michigan and selling them all over the country, it
would be very difficult to determine how much the
income is determined in each state. So what states do
in general is use this method of apportionment where,
based on economic factors in the state relative to
worldwide, you apportion the worldwide or U.S. income
back to the state. With oil and gas in Alaska, the
apportionment factors are property sales within the
state or for a pipeline it would be gross tariff
income, and extraction or production if the company
also produces oil or gas. If it's just a plain
pipeline company it would be two factors, property and
sales.
Moving over to page 8, this is how the apportionment
factor in Alaska for oil and gas is determined. It
looks at the relative amount of property sales and
extraction in Alaska to the world.... There is an
error on this. The last fraction should be Alaska
Extraction/Worldwide Extraction - not worldwide sales.
But the three factors - Alaska Property, as opposed to
the property tax, where the property kicks in when it
enters the state with the income tax as property when
the asset goes into service. So what we have here is
the three fractions, the Alaska part divided by the
worldwide part and the average of those divided by
three and that gives you a factor. That's sort of the
percent of your worldwide activity that's deemed to be
in Alaska.
On the extraction part, if there's both oil and gas,
the gas is put on the BTU equivalent with oil so it's
an apples-apples approach. They just take the
thousands of cubic feet and divide by six. That's the
mcf of gas and the barrels of oil on an apples-apples
basis. Now this is what is called a modified
apportionment. Most states, and with non-oil and gas
activity in the state instead of extraction, payroll
is used but starting in 1981, this modified
apportionment has been used. And the other difference
again between oil and gas and other activities in the
state, the way our corporate income tax works, is with
non-oil and gas it's Alaska property divided by U.S.
property and Alaska sales divided by U.S. sales.
That's called a water's edge approach, just putting a
ring fence around U.S. activity and bringing in U.S.
income rather than worldwide. With oil and gas, it's a
worldwide approach.
Page 9 - so once you know the apportionment factor,
the Alaska income is the apportionment factor
multiplied by the worldwide income and our corporate
income tax rate, I believe once your income is over
$100,000 a year, is 9.4 percent so the corporate
income tax is 9.4 percent times the Alaska income.
So what does all this mean? Well if this gas project
happens, there are seven things that will happen. One,
worldwide income will increase. Alaska property will
increase. Alaska's extraction will increase. Alaska
sales will increase. Worldwide sales will increase.
Worldwide extraction will increase and worldwide
property will increase. That's a sure thing.
What does this mean? On the income side, again,
worldwide income would increase but the way
apportionment works, this income is never
distinguished between Alaska income and non-Alaska
income. That's the whole point of apportionment is
that that's difficult to do so it just goes in one big
pot called worldwide income and the apportionment
factor allocates worldwide income into the Alaska tax
base. So, for example, if the Alaska apportionment
factor is 10 percent and worldwide income is $100, $10
gets apportioned into the worldwide tax base and
that's subject to the 9.4 percent tax rate.
And income generated by the Alaska project is
apportioned only to the same extent any other income
is so if there's $20 generated by an Alaska project
and there's a 10 percent apportionment factor, $2
comes into the Alaska tax base. But if there's $20
generated in Peru, same thing, with the 10 percent
apportionment factor, $2 would be apportioned into
Alaska. So, again, income is never distinguished
between Alaska and non-Alaska in origin.
On the apportionment side, again, the apportionment
factor would increase as the result of this project
and the [indisc.] apportionment factor would apportion
more worldwide income into the state. For example, if
we were 10 percent before, the project might make it
go to 11 percent. That might not sound [like] much,
but you're getting an extra 1 percent of worldwide
income. That's quite a bit of money coming into the
Alaska tax base.
So for the derivation of the tax rate for the tariff,
what does this mean for the tariff? Again, income
generated in Alaska is apportioned for taxes
everywhere, not just Alaska, but in the tariff, the
tariff is designed to recover all of the costs to the
company, including the taxes they pay everywhere as a
result of tariff income, not just in Alaska.
Now taxes rates are not uniform everywhere. Income
could be apportioned to all the other 49 states but
they all have their own individual tax rates. They're
not 9.4 percent. However, since each state has its own
apportionment factor and its own tax rate, it's
impossible to determine the exact tax burden that's
going to be borne by the pipeline owner. And what
regulators generally do is assume, for the piece of
property within a jurisdiction, they assume the tax
rate in that jurisdiction. So for the piece of pipe
that's in Alaska, they would assume a 9.4 percent tax
rate.
This just shows sort of the derivation of the
corporate income tax allowance in the tariff. The
allowance is an after tax allowance and in the example
we had back on slide number 6 where we had a 10
percent return on equity, that 10 percent is an after
tax return. To get an after tax - you need to recover
more before tax to get a 10 percent return after tax.
And in that example, with a 10 percent return on
equity - let me just go back to slide 6 for a second
here, just looking at that first year with a 10
percent return on equity, that $10 is an after tax
return. For taxes, the way a pipeline company will pay
its taxes, it will receive tariff income for shipping
the gas and the tariff times the amount of gas will be
its gross income. Then it will subtract its cost and
that will be its taxable income and then they'll pay
tax on that. Now the tariff gives the pipeline company
an allowance to cover the taxes and, in this case, so
that they're left with $10 after they pay the tax. So
they need to recover more than $10 before tax to be
left with $10 after tax and that's done with something
called a tax gross-up factor and that's simply the tax
rate divided by 1 minus the tax rate and again, with
our state, with a 9.4 percent income tax rate, 9.4
divided by 1.94 is 10.38 percent as sort of the
effective amount of tax you need to collect before so
that you're left with return on equity afterwards. So,
if your return on equity target is $10, the state
corporate income tax allowance needs to be, in this
example, you know, .1038 times 10 or $1.038.
And just in the box here, to see how it works, if your
return on equity allowance is $10 and your tax
allowance is $1.038, you have $11.038 and when you're
computing your taxes if you take 9.4 percent for your
tax times the $11.038, that gives you 1.038 and so
your return after tax is your total allowance minus a
tax allowance, 11.038 minus 1.038, which leaves you
with $10. Again, that's what your return on equity
was.
Again, this is for tariff making purposes. This is
again pro forma, the calculation for the tax
allowance. It's different than the actual taxes that
will be paid. They'll be paid again subject to
apportionment and worldwide income. If this project
goes forward there will also be state income taxes on
upstream profits that are made from the producers
selling the gas. In addition to state corporate
taxation, there's also federal income taxation - which
there's an allowance for that in a tariff as well.
That's computed similarly. The only difference is,
again, the feds have a different tax rate. It's at 35
percent and the state income tax is deductible for the
federal tax. My estimate of the Alaska corporate
income tax adds about 2 cents to the tariff and the
federal side, again, on a $19 billion project, is
about 20 cents.
That concludes my remarks and I'd be happy to answer
questions if I can. Thank you.
CO-CHAIR SAMUELS said the committee heard yesterday that the
amount of risk a pipeline owner has in a project would also be
factored into the tariff by FERC. He asked Mr. Marks where he
would incorporate that risk on page 2 of his PowerPoint
presentation.
MR. MARKS said risk would be explicitly addressed as the return
on equity. Generally, pipeline companies need a throughput
commitment and a shipper pay commitment to get financing. In a
shipper pay commitment, the shipper will commit to put gas in
the line and pay to ship it, whether the shipper has the gas or
not. That reduces the risk of the project. The 12 percent return
on equity is commensurate with that amount of business risk.
With no further questions of Mr. Marks, CO-CHAIR SAMUELS asked
Mr. Carruthers to present.
MR. JOHN CARRUTHERS, Vice President of Northern Development at
Enbridge, informed members that Enbridge has submitted an
application that was approved under Alaska's Stranded Gas
Development Act. He said the goal of his presentation is to
provide context to some of the questions members have regarding
what must happen to the gas once it reaches Alberta. He noted
that recently, the Canadian producers could not ship stranded
gas out of Alberta due to pipeline constraints. They found the
most economical way to move the gas was through Alliance, a new
high-pressure liquid-rich system that is consistent with
Alaska's needs. Alliance began service in 2001 and was
considered to be very successful by the industry. Enbridge
worked with producers throughout the process and now owns 50
percent of Alliance. He introduced Jack Crawford, the Chief
Operating Officer of Alliance Pipeline and noted that Mr.
Crawford has been with Alliance throughout conception,
construction, and operation.
MR. CARRUTHERS began by explaining that Enbridge has 50 years of
experience in pipeline transmission. It owns and operates the
world's largest crude oil pipeline system, which moves crude oil
from the Western Canadian sedimentary basin through the Midwest.
Enbridge also owns the Norman Wells pipeline; therefore Enbridge
is the only pipeline company with extensive experience in the
construction and operation of pipelines in continuous and
discontinuous permafrost. He continued:
We also bring a market perspective as the largest gas
distribution company in Canada, shown in yellow, but
today we want to focus on our experience in completing
the Alliance pipeline. Again, it was a response to a
consistent situation - pipeline-constrained gas, in
this case in Alberta. It's a high-pressure liquid-rich
line that transverses both the U.S. and Canada and was
permitted efficiently in both Canada and the U.S. That
line is shown in red on the map that you have.
I think we can skip forward a bit. I've given some of
this information to some of you previously and some of
it was discussed earlier. I really want to go to the
forecast of Canadian supply. It's going to be very key
and this forecast is back a few pages in your
presentation. It's consistent with many and shows
continuing growing production out of the Western
Canadian sedimentary basin although a key
consideration is much of this portion of growth is
from natural gas from goal. So we do have a huge asset
in Canada that parallels that of the United States in
terms of size but certainly we haven't developed it
nearly as much as the U.S. has. Less that 1 percent of
our total production is from gas from coal, in
comparison to over 10 percent in the United States,
although we have a similar resource. It will require
significant capital going forward and, given the
decline of traditional reserves, our expectation is
that capital will come but it's very important to
continue to watch that. Clearly, the key for that in
Canada is the use of water, something that has some
opposition to the development of coal bed methane but
we think there's a significant resource that can be
developed.
This graph is very relevant. You'll see a significant
decline in the lower portion, which is Alberta
conventional. Again, we would see coal bed methane
being able to make up a significant portion of that
decline. But I think what's more important, this graph
is relevant, it's about the time that Alaska gas will
come on in 2012, 2015 period, so it's quite relevant.
Really what's important is what will the picture look
like going forward from 2015 because we'll have
investment in a 30-year asset and we'd like to have
consideration.
I think what we're trying to show here is that
although we can have forecasts and they're well
thought through, there's considerable uncertainty with
what actually [it] will look like - what production
will look like out of the Western Canadian basin. So
it's something that we'll have to have a number of
alternatives that we need to consider.
So let's start with where the gas goes today with the
capacity of the pipelines. The good news is that there
is well-developed infrastructure out of Alberta and
there will be competitive options for Alaska gas.
There is the potential to fill underutilized capacity.
I think Tony will talk to you a little bit about that
today. In the red - and these graphs as I mentioned,
are relative, TransCanada is the largest - moves much
of the gas out of the system. Eastern Gas, as you can
see on the graph, handles 7 bcf per day and today
you'll see something in the order of 2 bcf per day of
spare capacity. As you look at the other pipeline
systems, Alliance, Northern Border, Duke are all near
capacity and they would have existing shippers with
contractual rights.
When you look at the capacities from a producer
perspective, which includes royalty owners like Alaska
and Alberta governments, you want the pipeline systems
to remain below full capacity to avoid bottlenecks and
reduce prices. We went through that situation prior to
the construction of Alliance and as a producer they
saw significantly reduced prices, so you always want
to have some extra capacity in your system. You don't
want significant underutilized assets, as those have
associated costs.
So it does provide good context to understand these
systems today but again, you'll have to take that
previous forecast and overlay it on these systems to
see what they look like going forward. I think you'd
also have to be cognizant of what capacity remains
going forward. It is possible that certain capacity
would be taken out of the system if it's not being
utilized so it could be retired so some of the
capacity lines could change as well. So it's very
important to understand the systems and the capacity
of those. It's also important to understand what the
contractual commitments are with each of those. As we
heard yesterday, there's a number of - the existing
shippers will have rights to certain capacity. So
again, it would be important to look at the contract
[expirations] over the course of development of Alaska
gas. As you can see from this graph, many of the
contracts expire. Typically they can be renewed on
one-year extensions with six months notice. So again,
just in terms of consideration of the project and
downstream opportunities, people have to be cognizant
of what shippers are on what systems and what rights
they have. Alliance itself has signed 15-year shipper
pay agreements that could expire in 2015.
Again, I think this slide is included just to show
that once you reach the Western Canadian sedimentary
basin, there is significant optionality out of there
to markets across North America and what we wanted to
look at was the capacity outlook going forward. I
think it's good context to understand what's happening
today, what might happen when MacKenzie gas comes on-
stream and then look at what might happen once
Alaska's gas arrives.
So if you look at the top right hand corner, which
summarizes it, I won't go through this entire slide
but I think it does provide good context for people to
work through. Today the Western Canadian sedimentary
basin produces about 17 bcf per day and we export 12.
Supply is expected to increase with MacKenzie by 2010
and Alaska gas certainly by 2015. At the same time,
Alberta demand will increase largely in response to
the oil sands development. So you have to look at the
Western Canadian sedimentary basin production, what's
coming in from MacKenzie and Alaska, and then what is
the internal market within Alberta. So the box
immediately below the one in the top right hand
corner, we are looking at the pipeline capacity based
on the earlier throughput. And today, you'd look at it
and say we have something in the order of 3.3 bcf per
day of spare capacity, but again, I'd caution you as a
royalty owner, you do want some spare capacity. On a
practical basis, we think there's more like 1.5 to 2
bcf per day of practical underutilization.
If you work down that line based on the previous
forecast, it shows that we need 2.1 bcf per day of new
pipeline capacity. Again there are a lot of factors
that go into that forecast. It's consistent with most
around but you would want something like a 90 percent
load factor in order to manage your load. You don't
want to be full up against the pipeline utilization.
If you take that into account, you need something in
the order of new pipeline capacity at 4 bcf per day if
you assume Alaska gas is in the order of 5 bcf per day
at that time. It could be a situation where you do
need a full 4 bcf per day pipeline.
At that amount, Alliance would have the lowest cost
option - would be to loop Alliance and would be the
most attractive option. But again, that's not the only
[indisc.]. You'd still have to look forward past 2015
to what the Canadian sedimentary basin is doing,
what's spare capacity. You could have a situation
where the more measured approach that Enbridge had
proposed might fit better where you have some
underutilization of capacity and you build a pipeline
that could handle more like 2.5 bcf per day out of
Alaska initially with expansion to 5 going forward.
Again, there are some scenarios. You'd want to keep
your optionality open as developments occur as we get
better insight as to whether there is coal bed methane
development in Alberta, how the existing basin is
progressing, and the timing of Alaska gas. The bottom
line is you'd want to maintain optionality.
Clearly, of course, the advantage to not having to
build the pipeline out of Alberta is its cost is
estimated to be close to $5 billion, so if you can
utilize existing capacity, there could be significant
advantage.
Some of the key points I think we should be cognizant
of that - I mean Alberta should have significant
capacity to handle Alaska gas by a phased approach. If
you expect 2.5 bcf of spare capacity, if you need a
full 4, Alliance would be your most economic option at
this point. And then there's ways too, if you don't
need it all, you'll see a number of the pipelines that
could have a spare capacity and you see a more -
potentially PG&E has some spare capacity, Duke has
about 200 million, Alliance has 500 million, so you
could have a way to make up the needed volumes with a
variety of pipes, TransCanada, Alliance, et al.
I think again on this slide - again, I'm not wanting
to necessarily go through all of the numbers. Really
to take away I think you'll want to recognize in terms
of tolls, tariffs - tolls are important but also, of
course, the fuel is important, particularly at the
high gas prices - from Alaska gas development, high
gas prices are positive, in terms of the fuel cost
they are not. So you certainly, you know, alternatives
downstream you need to look at tolls plus fuel and the
other thing that's most important...[END OF TAPE 04-
09, SIDE A]
TAPE 04-10, SIDE B
MR. CARRUTHERS continued:
...additional volumes - what the expectation is and
what those volumes would be, and what those tolls
would be with new expanded volumes, both from a toll
and fuel perspective.
So tolls are clearly important but you have to also
understand which market you're going to.
Again, some historical reference as to what the
spreads have been between Alberta and current markets
in the United States. [Indisc.] toll the pipeline and
the advantage of going there is an important
consideration. You'd need to look at - always in
pipeline development you need to look at what happens
if you do build a pipeline and what happens if you
don't build a pipeline in all scenarios and I think
that will dictate where much of this gas will
ultimately go. And really, what you'd really want to
have, from a resource ownership perspective, is a
competitive alternative out of Alberta when it comes
and probably, as you heard yesterday, the best way is
to have an open season where there are proposals from
different proponents and then the market, in the end,
ultimately speaks as to which market they want to go
to under which scenario because there are different
risks associated with the different markets, different
scenarios - clearly less risk with utilization of
existing pipe.
And I think the other thing is that - it won't drive
the pipeline economics but you need to understand the
NGL processing considerations. Alberta does face a
methane shortage and does want to access the liquids.
I'm not aware of any proposals that would not provide
access to the liquids. Certainly the producers can
[indisc.] contemplated liquids being stripped in
Alberta but you can also do it commercially in
Chicago. Those seem to be the two preferred
alternatives at this time.
So really what we wanted to do was provide a
perspective of some of the questions you might think
about, some of the ways you might look at that
information. But also Jack Crawford joined us because,
as I mentioned, Alliance has just been through this
process in terms of concept of a pipeline, looking at
tolls, tariffs, looking at the regulatory perspective
and the financing, and some of the things we talked
about yesterday. So certainly we would be willing to
answer any questions you have today.
SENATOR BUNDE said he understands the need for competition once
Alaska gas reaches Alberta but expressed concern about the
"dotted line" between the Alaska border and Alberta. He asked
Mr. Carruthers his view of the challenges of building a new line
in Canada between the Alaska border and Alberta instead of
connecting with an existing pipeline.
MR. CARRUTHERS said the fact that the pipeline will cross a
border is no different than other projects Enbridge has recently
been involved with. He noted the engineering would be the same
and Enbridge would not split the project at the border because
there would be no sales there.
SENATOR BUNDE clarified that putting in an Alaska pipeline will
require major congressional legislation to solve some Native
American issues and he expects Canada to have to deal with some
of the same issues with its First Nations peoples. He asked what
challenges exist on a national level for Canadians to support a
pipeline in that area.
MR. CARRUTHERS said Canada supports the development of natural
gas. There was opposition to the production tax credit that was
included in the legislation. The provinces support the
development as well and the First Nations are supportive of
pipeline development but want to assure that they benefit from
the pipeline activity and that the environment is respected. He
stated:
But I think your question about the potential for
aboriginal delay is very relevant and a good
indication would be how the MacKenzie gas pipeline is
being developed today and there [are] issues in terms
of aboriginal support so it's a very important issue
that needs to be considered. Relationships with the
aboriginals will be key in Canada to development of
the pipeline. But again, I think there's actually
support for it, but it will have to be managed well
and there is an expectation and a need for the
aboriginals to have benefited out of the project.
CO-CHAIR OGAN asked if the Enbridge proposal is to phase in the
amount of gas that comes down the highway and whether Enbridge
wants to start with a 36 inch pipeline and add another one
later.
MR. CARRUTHERS said he thinks consideration needs to be given in
comparison to a 48 to 52 inch pipeline, which has the economies
of scale and is a very competitive alternative. Another
alternative that should be explored is the initial development
of a 36-inch pipeline that would bring in the order of 2.5 bcf
of gas per day and then subsequently looping another 36-inch
line. The second line could be bigger depending on exploration
activity and the market but that is a more measured approach
that has less risk.
CO-CHAIR OGAN asked if the lines would primarily be buried.
MR. CARRUTHERS said yes.
CO-CHAIR OGAN thought digging two trenches for two pipelines
would not be as cost effective as building one trench and
putting a bigger line in to start with. He said he would be
interested in getting more information on the costs because
those costs will increase the tariff.
MR. CARRUTHERS said that is the key consideration. He said as
the process goes forward, the commitment for shippers for gas
will have to be determined. Clearly, building a larger line
would not be useful if the commitments aren't there. The next
consideration would be competitiveness of supply. Generally,
there is more competitiveness on a more conventional build,
which should reduce costs. The third consideration is that fewer
funds would be used during construction before any revenue from
the pipeline comes in. Enbridge sees less risk in a conventional
build so it could be that the expected costs might be less on a
52-inch line. He said the crux of the matter is what commitments
have been made to support it and how much risk is involved.
CO-CHAIR OGAN said the state wants to encourage development in
the foothills where there are large quantities of gas. With a
36-inch line, that gas could be run for a long time but it would
discourage development in other areas. He agreed that too much
gas to market in the Lower 48 could affect pricing but he has
heard the market will need as much gas as Alaska can produce
unless nuclear or coal fired generation plants are built. He
said the legislature wants to encourage the development of the
frontier areas so it needs to consider how much that development
will be delayed if the state starts off with a 36-inch pipeline.
MR. CARRUTHERS said in terms of exploration, there is a scenario
in which a loop line would accommodate that better. It may be
difficult for explorers to indicate a shipping commitment up
front. But the expanded pipeline scenario might facilitate more
exploration because companies could come in at the second round
and the line could be sized even larger. He added that the
phased approach would entail a longer construction period.
MR. JACK CRAWFORD, Executive Vice President, Northern
Development, Enbridge, told members part of the flip side of
that, in terms of looping, is that development could take place
over a period of years. He noted the TransCanada pipeline was
expanded in increments over a number of years and that levelized
the construction boom in a significant way. He pointed out the
Alaska line could be looped in increments if a lot of
exploration took place, depending on how much gas was developed.
Supply would be matched with transportation capability.
CO-CHAIR OGAN asked Mr. Crawford to explain looping.
MR. CRAWFORD said looping is another term for twinning the
pipeline so a single line system today could be twinned by
building a second parallel pipeline. Additional capacity could
also be garnered by building short sections of loop along
sections of the pipe. He noted that Alliance's stations today
are 120 miles apart. It could loop 30 miles and then the entire
120 miles over a staged period of time and get additional
capacity at each juncture.
CO-CHAIR SAMUELS asked Mr. Crawford if he had a separate
presentation.
MR. CRAWFORD said he did not but was available to answer
questions.
SENATOR WAGONER asked Mr. Crawford his opinion of how FERC will
exercise its authority over the distribution of the product
going through the line once the pipeline is built.
MR. CRAWFORD said he shares some of the previous speaker's
concerns about some of the things FERC has done over the years
that haven't always made sense to him. However, he believes the
concern that FERC would divert destinations or significantly
impact the market is overblown. FERC has tried to step back and
let the market work in the past few years. He believes FERC
operates with the philosophy that it would prefer to let the
market work rather than to be interventionist and dictate how
the market should develop.
CO-CHAIR SAMUELS thanked Mr. Carruthers and Mr. Crawford and
asked Mr. Palmer to present.
MR. TONY PALMER, Vice President, Alaska Business Development,
TransCanada Pipelines, Ltd., told members there has been some
commonality in what a couple of speakers have said with regard
to facilities from Alberta to market and integration of
facilities rather than constructing a bullet line beyond
Alberta. He then began his testimony:
The Alaska project will be a huge undertaking with
large risks for all stakeholders. We believe the
project should be limited to the frontier pipeline
from Prudhoe Bay to Alberta and, at that point, take
an integrated approach from Alberta to market and that
will give optimal results for Alaskan and Canadian
stakeholders. By integrated, I mean that from the
Alberta trading hub, which is the largest trading hub
in North America, Alaskan gas will integrate into the
existing North American gas pipeline grid and Alaskan
gas at that point can flow east or west to markets
across North America from San Francisco all the way to
New York.
This is a map similar to what I had up yesterday, just
to show the integrated approach - a little different
color scheme. Actually I see that the color scheme
doesn't actually show up that well on the screen but
hopefully it does in your hard copy. You can see the
Prudhoe Bay to Alberta system being a new piece of
pipe at that point, going to an integrated approach.
You heard this morning from participants from Enbridge
and Alliance with regards to their facilities.
TransCanada's facilities within Alberta - we have
about 15,000 miles of big inch pipe that you would be
integrating into and we have another 9,000 miles of
big inch pipe going across Canada or into the United
States. We own the pipeline going east from Alberta
into eastern Canada and ultimately service markets in
eastern Canada and into New York and Boston. We own
the piece of the pipeline that goes down, called
Northern border, that goes down into Chicago and we
own Foothills Pipelines, of course, the Canadian piece
that connects to the borders, and we are soon to own
what used to be called PGT, which is the line from
British Columbia. On the map it's a greenish line
running down to Northern California. It used to be
owned by PG&E. It is still currently owned by them.
We're in the process of closing that transaction.
So our 'B to C' Proposition has an integration with
the TransCanada System at Boundary Lake, which is the
dark blue line, as I mentioned, by extending the
Foothills prebuild to that point.
Our underlying principle of our 'B to C' proposition
recognizes that integration with the existing
TransCanada system will best serve the interests of
all constituents by fully utilizing the extensive
natural gas pipeline grid and the spare capacity that
exists on that grid today and is expected to continue
when Alaskan gas flows.
Our proposal provides the most competitive and
flexible economic solution for Alaska producers,
Alaska royalty owners, and all affected constituents
across a broad range of alternatives, we would argue.
What are key criteria and perspectives to examine when
you're constructing a pipeline? Well, normally
greenfield pipeline decisions are based on an analysis
of routing, volumes, and capital cost. The shortest
route with the highest volume and lowest cost would
always be the preferred route.
However, there are a number of aspects to integration
that we believe provide advantages over the normal
distance, volume and capital relationships. Those
major factors are volumetric requirements. The Alaska
volumes are expected to ramp up over a 5-10 year time
frame to 6 bcf/d. Our understanding at this point is
that the major North Slope producers would anticipate
commencing with a volume in the 4 to 4.5 bcf/day and
expand from that volume. I spoke to that yesterday.
The last increment of that volume may depend on
exploration and production activity once the pipeline
is constructed. If you take 6 bcf/day and multiply
that by a 25-year or 30-year life, there are
insufficient proven reserves today so you would expect
that drilling and other proving up would be undertaken
over the course of the life of the project.
The liquids composition of the gas likely will change
over this time frame as well. That's normal for a gas
project. Because the range of potential outcomes is so
broad, and may involve more producers than the initial
three Alaska producers, the facilities planning for
what's described as B to C, which is from Alberta to
market, needs to be flexible.
The facilities planning for total supply, not
incremental supply, is a very important factor from
Alberta. I addressed some of that yesterday.
The interconnection with the existing grid can occur
when the Alaska gas reaches Alberta. The Western
Canadian Sedimentary Basin (WCSB) is producing
approximately 17 bcf/d and the Mackenzie Delta can be
expected to ramp up to 1.5 bcf/d. The additional
Alaska gas of 4.0 or 4.5 bcf/d would create a
requirement of about 22.5 bcf/d in total. This
fundamental assumption drives the integration prospect
that you're planning for a 22.5 bcf/d gas supply, not
just planning for 4 to 4.5 bcf/d.
We believe that market flexibility will be very
important for Alaskan gas. It's important for every
other source of gas. They will look to attract and
attach to the most attractive market and that market
may change over time. Rather than constructing a
bullet line to one particular market, we believe
there's value for Alaskans as there is for Canadian
gas in being connected to multiple markets. The
combination of reduced Western Canadian supply and
expansions on the existing pipelines driven by market
factors prior to Alaskan volumes ramping up will
influence the appetite to sign up for new greenfield
pipelines from the basin.
Depending upon the marketing strategy and the existing
commitments from each producer's portfolio, a variety
of commitments may or may not be made. The Alaskan
producers do not have to precisely match their
additional Alaskan production with downstream market
commitments as they may choose to sell some of their
Alaskan gas within Alberta. That would be their
choice. Clearly, you see today major producers seeking
a portfolio of markets and a portfolio of terms and
that's generally how they optimize their structure.
So what are the system integration benefits beyond
what I've spoken to today? The Alberta system has
several unique features that are not immediately
evident when examining a map of the pipeline system
that give Alberta several advantages.
The Alberta system is not operating at full capacity.
You heard testimony from a number of parties yesterday
to that effect and I heard that again this morning
from the parties from Enbridge and Alliance. However,
the Alberta system was partially offloaded by the
construction of the Alliance pipeline so you had a
facility that was built to match TransCanada's
northern border system. Once Alliance was built and
there wasn't a subsequent addition to gas supply out
of Western Canada, you've effectively offloaded,
unfortunately, our system because we had the shorter-
term contract and you saw evidence of that this
morning. New supply has not been robust enough to
refill this capacity. This spare capacity can handle
some volumes with no incremental construction costs,
no incremental environmental impact. Additional
compression can further add volumes with little
incremental cost.
The net supply additions and demand requirements on
the Alberta system are also shifting. If you look at
the map of Alberta, you should be aware that the
supply in the northeastern section of Alberta near the
oil sands, near Fort McMurray, is declining. That is
in addition to having an increase in demand in that
region so you have two factors that are unloading the
pipeline system on the northeastern section of Alberta
and there's likely to be a pipeline constructed by us
in addition to our existing facility to connect the
northwest part of our province with the northeastern
part of the province to meet that incremental demand
from gas entering in from either western Alberta or
northeastern B.C. That is likely to happen in the next
several years. That will also improve the integration
benefits for this project. This shift in the system
load creates a low-cost addition of incremental
capability from the northwest to the southeast portion
of the Alberta system.
I'd like to address construction costs. The single
largest variable having the biggest impact on the
toll, on the pipeline tariff, is the construction
cost. You've heard that from a number of parties. The
estimation of the costs is influenced by pipe size and
by competition for resources if both 'A to B' and 'B
to C' are constructed in a two-year time frame with
the same pipe size, the same compressors, the same
valves. Construction of a smaller sized 'B to C'
pipeline, as necessary, with more conventional pipe
sizing, not only increases the certainty around the
construction cost estimates but reduces the
competition for steel mill space that would influence
the costs of the A to B portion of the pipeline as
well. Clearly there is going to be a worldwide supply
of steel pipe for this project. That is going to be a
necessity. It's very clear that North American mills
can be competitive, however they will not supply 100
percent of the steel pipe for this project. If there's
a variation in pipe size to Alberta and away from
Alberta, that will bring more competitors to that
marketplace, not only in the steel business, but in
the valve business as well as the contractors. We
think that's to the benefit of all parties.
The roll-in, and I believe that term has been
described here before - roll-in simply means an
averaging of old costs and new costs, but the roll-in
of new capital expenditures with existing capital
investment to create a toll charged to shippers also
influences the capital obligations. In a rolled-in
toll, the incremental capital is proportionally less
so the impact of a hot construction market is less in
the blended average toll. Clearly, one of the fears
that you heard me describe yesterday with regards to a
potential cost overrun, is there's real potential on a
project of this scale for a hot construction market
and that environment can affect capital cost overruns.
It's prudent to try to minimize that.
Toll integration - so integrating the toll would also
have a mitigating effect on construction costs because
the system costs are essentially spent today and will
be unlikely to increase over the planning horizon. The
tariff design in Alberta has created an expressway
toll concept from the northwest portion of the
province where the 'B' is, near the British Columbia
border, and therefore all the way through to the
southern portions of the province of Alberta and into
the export market. Therefore future additions are
likely to have a smaller toll impact at Boundary Lake.
Another advantage of the Alberta system that is often
not appreciated is the volumetric size of our system.
System receipts are approximately 11.5 bcf/d today,
and the export deliveries are approximately 10.0
bcf/d. So those are volumes in the two and three times
the expected Alaska volumes. That's the system you
would be integrating into. The size of our system adds
tremendous stability to the toll. It changes very
slowly, very insignificantly, if you add volumes of
gas and variances in volumes are relatively small so
the toll does not change significantly.
Just to summarize - our integration model is flexible
and it appeals to a broad cross section of market
participants. Consequently the regulatory approval
for this solution is likely to be less contested and,
in fact, supported by more interested parties, a very
important factor we would argue.
And a key to the integrated approach is to continually
monitor the requirement for facilities and to be
poised to gain market support for the timely addition
of new facilities.
I would like to address a few scorecard items as to
how we compare - our integrated proposition with other
alternatives. We believe that an integrated solution
is more attractive and will be more attractive to
Alaskans and Canadians. It's economically superior to
any alternative for an independent pipeline - separate
pipeline - from Boundary Lake through a broad range of
Western Canadian supply and capacity scenarios. You've
heard my testimony as well as others that Western
Canadian supply and demand numbers are changing. Our
forecasts are changing, have changed over the past two
years, and I believe that's common across the
industry. We are less optimistic about Western
Canadian supply than we would have been two years ago.
We also believe that demand will not grow as quickly
as we expected. But fundamentally, the gap - the spare
capacity in the pipeline is growing and depending on
what happens over the next several years, you may or
may not be constructing additional facilities away
from Alberta to serve Alaska gas. That will depend on
what happens with parties' actual forecasts.
One of the key advantages for integration is you can
defer the decision on constructing the specifics of
pipelines beyond Alberta. The time frame to strike a
commercial deal on the project in advance of in-
service from A to B - from Prudhoe Bay to Alberta as I
described yesterday in my testimony, in our case is
seven years so if there's a commercial deal struck
next year, we have indicated we can be in service to
Alberta by 2012. If you want to be in service by 2012
from Alberta away to whatever market you're seeking
from San Francisco east to New York, if you're using
existing facilities, clearly that commercial deal can
be struck several years later than 2005. If you want
to build a new pipeline or some component of the
additional volumes needs a new pipeline, you also have
a significant time frame lag of approximately two
years. You wouldn't have to make the decision on the
downstream pipeline increment until about 2007. That's
a two-year advantage to see what's happening in the
marketplace with supply and demand in Western Canada
and also to see what's happening in overall markets.
We would argue having additional time is very
valuable. It generally means you make a better
decision.
So, just to walk through some scorecard items - we
think that an integrated approach will provide the
highest netback price to producers and royalty gas
netback owners at Boundary Lake. The tolls - there
will be more stable tolls across a wide range of
western Canadian supply and demand forecasts - lowest
tolls and fuel compared to alternatives. The
TransCanada Alberta system tolls receive an immediate
benefit from Alaskan gas. That will be attractive to
Canadian producers and that will be attractive to the
Canadian government I would argue as well.
Capital and warranty costs - the lowest infrastructure
capital cost across different pipe size alternatives
away from Alberta.
Lowest warranty capital cost. By warranty capital I
mean the commitment cost to commit for pipeline demand
charges away from Alberta will be lower because
fundamentally the existing pipelines do not require 15
and 20 and 25 and 30 year contracts. As you heard
testimony this morning, on existing pipes you can
contract for one-year worth of service with renewal
rights and continue to roll forward that contract if
you wish. You can also get expansions on our system in
Alberta with a 5-year contract rather than a 15 to 30
year contract. That has value for parties that are
making commitments.
Flexibility - We believe that having access to liquids
processing within Alberta will have value. Clearly
there may be liquids removed within the state of
Alaska. There may be liquids removed within Alberta
and there may be liquids removed on the way to market.
Having additional access to liquids removal facilities
will give Alaskan gas one more opportunity to sell
their liquids. You'd be connected to an extremely
liquid Alberta hub at AECO, and you also hear another
term sometimes called NIT - that's Nova Inventory
Transfer that's on our existing system. That is the
most liquid hub today in North America - more liquid
than NYMEX.
Easy access to flexible and diverse markets away from
Alberta Hub - I think I've addressed that, and the
shortest lead-time for capital decisions. I've also
addressed that for new capacity away from Alberta.
Risk mitigation - also important - lowest risk of
'hot-market' cost overruns. Spread the downstream risk
at the integrated hub by having more participants in
new capacity may not require additional downstream
facilities, depending on the timing and volume of
Alaskan flows, and the existing certificates provide
the lowest regulatory risk and fastest in-service.
I would wrap up by indicating that the integrated
TransCanada Foothills proposition - Foothills
Pipelines is now 100 percent owned by TransCanada.
They have held the certificates for constructing the
Alaska pipeline project within Canada, including B to
C, since 1978. They have met those commitments and
still hold those certificates today and, as you would
have seen from the map, they have an existing pipeline
today called the prebuild that has capacity of about
3.3 bcf/d from central Alberta to the Lower 48
interconnects.
The underlying principle of TransCanada's proposition
is integration of Alaskan gas into its existing grid,
including the Foothills prebuild. The concepts that
originally underpinned the Foothills certificates are
still valid today and we would argue the overall
public interest will best be served by fully utilizing
the extensive natural gas pipeline that currently
supports Canadian and American gas consumers.
To conclude, the benefits of integration are many and
substantial. The economic advantages in capital and
warranty costs will not only provide lower prices to
consumers, but also higher netbacks to resource
owners. What was true in '78 remains true today, that
TransCanada and Foothills can provide the most
beneficial products for the development of Alaska
reserves.
Thank you for this opportunity to appear at this
session today and I'm available to respond to your
questions.
SENATOR HOFFMAN asked Mr. Palmer to address any consideration
given by TransCanada of the potential benefits of this proposal
to Alaskan consumers, in particular to consumers along the river
system and coastal communities, and of the spur line.
MR. PALMER said the original project, which TransCanada is a
proponent of, always anticipated volumes would be taken off of
the line at several locations to connect to Alaskan communities.
TransCanada's focus is the main line from Prudhoe Bay through
Alaska to market but off takes from the line to serve Alaskan
consumers were always contemplated. Valves and connections would
be built and Alaskan and other investors would pursue
constructing those laterals. He noted the original legislation
contains specific language regarding reasonable tolls to
Alaskans and making gas available to Alaskans.
SENATOR HOFFMAN thanked Mr. Palmer for addressing benefits to
Alaskans as that topic was missing from his presentation.
SENATOR WAGONER asked if the 3.3 bcf/d capacity in the system is
additional capacity that is not currently being used.
MR. PALMER said that is currently fully utilized and contracted
by Alberta Gas. The project was initially constructed because
there was seven years of spare Alberta gas at the time in the
1980s, which subsequently turned out to be more than that. It is
fully contracted today, generally on a short-term basis. He
believed the remaining terms on those contracts would be one
through four years. At the time Alaska gas comes on line, Alaska
gas would have that as an alternative, as would Alberta or
Western Canadian gas.
The committee took a 15-minute at-ease at 10:45 a.m.
CO-CHAIR SAMUELS announced that Mr. Brena would be the next
presenter and that he has represented ratepayers before FERC,
the RCA, the APUC and the Supreme Court of Alaska. He has
participated in virtually all the major rate proceedings
affecting Alaska for the past couple of decades.
MR. ROBIN BRENA, Partner, Brena, Bell & Clarkson, P.C., thanked
the chair for his introduction, but said he left out the most
important part - that he is from Skagway. He stated that he
represents Tesoro, Anadarko and Agrium, but he is not
representing anyone today and wants to give the committee his
opinion on this topic as a citizen.
It goes without saying that the vast majority of our
resources and our wealth are going to flow through
pipeline infrastructure that is monopoly
infrastructure. It's absolutely essential to our
economic future that this monopoly infrastructure has
just and reasonable cost-based rates. Rates in excess
of that will result in less development of our
resources, less revenue from the resources we do
develop and fewer opportunities for manufacturing and
value-added jobs in Alaska.
This is something that you've got to get right. I am
here today to encourage the state to act to insure
that cost-based just and reasonable rates are
established for this pipeline infrastructure now and
into the future and anything that you can do to help
that, I think, would be good.
I have sat through many of the presentations, as
you've heard and, were I in your position, I would
consider myself to have been 'technocrated' to death.
So, what I'm going to try to do is try to bring this
home in real dollars and cents and real issues that I
think, as a legislator, you should be concerned with
in the forming of policy. I thought I'd begin with
what the true cost is of not getting this issue right
- of not establishing just and reasonable rates. The
example that you were encouraged by several
participants to consider was an example from history,
which is TAPS. It's the first time around, it's a
large project; it has a great many similarities to the
process. And so, what are the lessons of TAPS?
To date, the TAPS carriers have charged and collected
transportation rates that are $12.5 billion over just
and reasonable rates. They have charged and collected
and earned an additional $10.1 billion in excess of
just and reasonable DR&R rates. If you only consider
the transportation over-collections of $12.5 billion,
the impact to state revenues is $8.5 billion. Framed
somewhat differently, our Alaska Permanent Fund, if
rates were just and reasonable on TAPS, we'd have $8.5
billion more in it today, if the state would have got
this issue right. It would have a balance of $36.5
billion instead of $28 billion. That is what many of
the technical analysts have told you. You've heard it
in bits and pieces and percentages, and please ask me
to defend those calculations at some point. I would be
more than happy to.
With regard to the transportation rate, it was simply
done. The RCA has done a comprehensive review of the
rates on TAPS. The chair at the time, Thompson,
presented to you. She referred you and offered you
copies of Order 151, docket P974. In that docket, the
commission held that the TAPS carriers had over-
collected these amounts of money. All that I've done
is take the amounts that the RCA has said is over-
collected and plugged in what is the Permanent
Dividend annual return - if those funds had rather
than being collected by the carriers had not been
collected by the carriers. That's 10.3 cents and I
contacted the Permanent Fund and got their rates of
return for the past 20 years. So, that number is real.
The state got it wrong on TAPS and it's cost us $8.5
billion. Let's get it right this time. There's no
excuses for not getting it right this time. To
understand how to get it right, you have to understand
how the state got it wrong. So, I want to talk about
some of these concepts.... If you have an alignment of
ownership between production and transportation so
that people are paying themselves the tariff rate,
then they will charge the highest possible tariff rate
they can, because they save a quarter in royalty and
severance taxes on every dollar they over-charge
themselves. So, their incentives will be to have the
highest rates possible while holding their costs down.
So, where the rubber meets the road is what is the
return component - because the return is they don't
have to pay it, they just get it and they save a
quarter in taxes for every dollar they over-charge
from the state. They also save money because they make
that excessive profit from independents that need to
use this monopoly infrastructure. So, there is a huge
incentive for the producers to own and to control this
line and to manage the ownership structure so it stays
perfectly aligned with the production interests - and
to transfer profitability from their production into
their transportation. That is what has happened here.
That is the game that is afoot and that is the game
that we haven't figured out yet, well enough.
Let me say, too, that [END OF TAPE 04-10, SIDE B]
TAPE 04-11, SIDE A
MR. BRENA explained that oversight of regulators didn't work,
because the reality of regulatory practice is that someone must
ask them to regulate or they will not. All the shippers will be
affiliated with the producers and their incentive will have the
highest rates. Most shippers will ask for reasonable rates and
that leaves only the state or small independents. It's difficult
for small independents to carry the ball. He illustrated his
point by saying that he represented a client in a rate case and
won; the rate was set through negotiation at about $1.25, but
his client can no longer ship on that line. The producers will
only sell oil to his client at the end of the line.
It's tough for them to get the oil, because they rely
on the oil. It's tough for them to stay on the line if
the producers don't want to sell it and allow them to
ship it. It's tough because the small independents
need cooperation in the field and with the
transportation infrastructure in order to survive
here. So, don't rely on the small independents
carrying the water for the state; the state has to do
it.
MR. BRENA said the state settled on the TAPS project and it
should have litigated. Many of the assumptions in the settlement
were proved wrong, but the settlement didn't have a re-opener
clause; so, there was no opportunity for the state to come back
in and get something that was fair. He summarized how he thought
the state should try to get things right on slide 5.
· Establish clear goals. Ratemaking is not complex and a
transparent informed process among all the participants is
necessary.
· Properly staff and resource the litigation effort.
· Maximize the state's leverage - the state needs to win a
rate case once in a while.
Back to the subject of establishing clear goals, MR. BRENA said
cost-based, just and reasonable rates are very simple.
When it costs somebody to build something, you give
them their investment back. Until they get their
investment back, whatever their investment is, they
get a reasonable return on it. They get to recover
their operating costs and a tax allowance. And, that's
it. Rates should be based on the cost of providing
service.
He cautioned that the first question to be asked with any
settlement or any proposal is: Are the rates just and
reasonable, cost-based rates? Business people don't want to know
the rate will be $1; they want to know the rate will stay linked
to the actual costs.
Fair terms and conditions for access for future independents is
a major consideration. Independents always come to the party
later and develop the marginal fields. They will need access to
the infrastructure on a forward-going basis. If the major
producers lock the transportation and can control access, the
independents will be squeezed out. He encouraged the Legislature
to do what it can to encourage transparency of the process and
include all financially interested parties. "Everybody needs to
be at the table."
MR. BRENA said Professor Witherspoon, one of the foremost
experts on pipelines in the nation, drafted the enabling
legislation.
I don't think it's fully appreciated that you are
negotiating matters with companies that have more
sophistication and greater incomes than most nations.
You need to recognize that. So, please devote the
resources equal to the task and recognize the task or
the cost will be at another $8 billion or $10 billion
ten years from now.
Recognize you're negotiating and litigating with
certain disadvantages. Like it or not, the state is a
political process and there are opportunities to
influence the political process that don't go the
other way with the other negotiated parties. So, it's
important because of your disadvantages in this
process to have it be an open process. I think the
state should focus on maximizing its [negotiation] and
litigation leverage and you have huge amounts of it.
On slide nine, you are the owner of the resource. You
can put anything in the lease that you want. It's your
oil; it's your gas. If there are games being played
that you can't figure out the solution for downstream
- if there's not enough tankage to get our resources
to the market for fair prices, if there's a bottleneck
in transportation and monopoly profits being realized,
if the independents can't get the access to field
facilities because they aren't able to negotiate cost-
based use of field facilities - those are three major
bottlenecks that the state will have to deal with in
terms of future public policy. All you've got to do is
put a sentence in your lease.
The right-of-way. You're the owner of the
transportation corridor. That sentence could be under
right-of-way. This infrastructure crosses state land.
You have tremendous authority and control over the
circumstances under which that is used. Your taxing
authority and I won't emphasize that, but I would hate
to negotiate with someone that had the power to tax
me. I would not assume I was in a position of strength
in that situation. You have the power to tax.
The power to regulate.... I was very interested in the
chair's question from an earlier speaker with regard
to state ownership and whether state ownership is
appropriate or not. The important thing isn't whether
the state owns or doesn't own it, setting aside
financing opportunities that may exist for a state-
owned facility. The issue is whether or not the
production interest is aligned with the transportation
interest. If, to use an example, BP as a producer has
to pay TransCanada or me if I own the pipeline, then
you can bet that rate is going to be just and
reasonable. If it's not, BP will go to FERC and get a
just and reasonable rate. So, you have control over
what the ownership structure of this pipeline should
be. Let's say, for example, you decide you want a
third-party owner of that pipeline. If you are able to
get third-party ownership of that pipeline, then those
rates will be just and reasonable, because then the
producers will have a huge incentive that they be just
and reasonable and they will beat down FERC's doors
getting a just and reasonable rate.
Avoid litigating against the state's own interests.
I'm litigating against the state, I'm trying to get
just and reasonable rates for instate shippers and the
state is opposing me at every step of the way. The
positions they are taking are compromising and
undermining their ability to negotiate good
settlements and to litigate good settlements in the
future. It doesn't make any sense.
Avoid compromising state authority. Last year, you had
an opportunity to take a look at HB 277. I can't
imagine a more broad-scaled give-away of the state's
own authority to regulate these issues than was
proposed through HB 277. Please do not compromise your
authority - and understand something about your
regulatory authority. As Professor Witherspoon drafted
the legislation, what he intended is the state have
the power that the federal government didn't have.
There was no gap between the two. That may be very,
very important to you in the future - that there's no
gap between the two.
MR. BRENA said the FERC can't force extension or expansion of
the pipeline, but the local commission can.
If the federal government doesn't have the authority,
under your current act, the state does. That's very,
very important. That was very well conceived and
thought-out by the Legislature and Professor
Witherspoon. Please don't compromise away your own
leverage to negotiate and litigate better deals for
the state!
Next, win a rate case. You know, if the state's going
to run with the big dogs, it has to have more than a
bark and the state has never won a rate case. At some
point...if you're not able to win in litigation,
you're not able to get a good settlement. If the
settlement is before a litigation victory, then it's a
bad settlement; it's costing you money. In the last
settlement, the state knew that. There wasn't a secret
about it. The assistant AG said we think we can
litigate and get $2.5 billion more out of this deal
than what we can get, but we can't get a better deal
through settlement. So, they took the settlement
anyway. Well, fairly compare the cost results in
efficiencies of settling with litigating. I realize
it's popular to bash attorneys; I realize it's popular
to say that litigation is something that should be
avoided. Well, 20-years ago you avoided it. You had
$35 million into litigation, largely on the wrong
issues - I just throw that in as an aside - and you
settled. It cost you $8.5 billion. Everyone is trying
to avoid litigation. What for? Why didn't you litigate
that to its end? I hope I'm not back 10 years from now
talking to a different legislature with a similar
message. Don't just assume that settlement must be
done. In these circumstances, it has proved to be the
worst result in almost every settlement for the state
that I've reviewed with regard to rate transportation.
I have felt, without exception, that a litigated
result would have been far favorable.
The ratemaking strategy that the state is faced with
is to make regulation as difficult as possible for as
long as possible until the state settles with them.
Let me tell you, for example, the last 79 rate filings
on the TransAlaska Pipeline system have been rejected
as inadequate or not supported - the last 79! All
right? They're not trying to get it right. The local
electric company in Skagway makes filings to support
its rates every three or four years. They get it
right; they know - what we call it a 275A filing -
it's what you're supposed to file with your testimony
to say what your rates are supposed to be. Every small
utility and bush company in this state with 5 or 6
employees gets it right. The last 79 filings on TAPS
haven't met that minimum standard. They're not trying
to get it right. So, don't underestimate the
successfulness of not meaningfully participating in
the ratemaking process - dragging it along until the
state finally settles.
Finally, if I were you, I would like to know what to
look for in a future settlement that would come before
me, so I just thought I'd tell you.
Indications of a bad settlement - rates are not
determined based on standard ratemaking principles. As
soon as people start talking about rates different
than just and reasonable rates or rates based on the
cost of service, then you've lost. It's just a matter
of trying to figure out how much and you'll never
figure out how much.
Future access is somehow limited so the people that
come late to the party can't get in the party. The
people that come late to the party are the people that
the state needs to develop their marginal fields and
outer fields. They're the independents. After the big
puddles of oil and gas are gone, they are the people
that are left here developing our marginal fields. If
that future is that the infrastructure is controlled
by the majors, then the independents are who you're
relying on for the exploration, then the state will
lose.
Return is not based on investment. Actually, in the
TAPS, they gave them a return that was unrelated to
investment. Five years before I filed a protest on
TAPS, the rate of return on equity for TAPS was over
100 percent per year for the last five years, because
it wasn't linked to investment.
Long-term agreements with no re-openers, if their
assumptions prove false - I put throughput down there.
When you build pipelines, you don't know how much of
the resource is really there. So, you need to admit to
yourself that you don't know. You also need to admit
to yourself that you know less than the people you're
negotiating with about what's there. Once you admit
those two things, then you're on the way to realizing
the limitations that if there are throughput
assumptions that go into setting those rates, that if
they go out and develop three or four times more
resource, that that three or four times more resource
isn't flowing through at those set rates because that
will result in exorbitant returns. So, if there is a
settlement, be sure that it can be reopened if it's
needed. If the assumptions prove false - and the state
has essentially taken itself and TAPS out of the
litigation for 25 years - that's the reason why it's
gotten so out of kilter. Many of the assumptions that
were made are false and throughput was one of them.
If the settlement that comes before you is so complex
that it takes a team of experts a long time to explain
it, ratemaking is not complicated - not withstanding
you sitting through two days of less than pleasant
comment. If you don't understand it, then it's because
it's a bad deal. It's not because you're missing
something. If the settlement trust process was not
transparent, if other parties didn't participate, if
certainty is confused with predictability - and that
goes back to my earlier point that if you see any kind
of set rate rather than a methodology, then you've
lost. Then, if what you hear when it's presented [is]
the limitations, costs and risks of FERC litigation -
FERC litigation is not difficult. FERC has done a lot
to streamline its process. It would take 18 months to
two years for a rate case on this pipeline to go
through and one of the things that people continue to
confuse is that it matters what FERC's opinion is. The
D.C. Circuit really establishes ratemaking principles,
not FERC.
So, the question is how is the settlement consistent
or inconsistent with the ratemaking authority that the
D.C. Circuit has established that it will use to
review FERC.... So, don't have overstated to you the
costs or limitations of FERC litigation. Every once in
a while, go find out. For a $10 million check, you can
go set a just and reasonable rate at FERC in a two-
year process and that gives everybody a tremendous
amount of predictability because you then will have
established what the ratemaking principles that will
govern this line through its life will be. One of the
real problems with settlement is that you never really
know how that line is going to be regulated and
oftentimes complex settlements deviate so much that
they create their own problems if greater problems
than standard ratemaking were allowed to continue.
Those are my comments and I'd be happy to answer any
questions I can.
CO-CHAIR SAMUELS thanked Mr. Brena for his presentation.
CO-CHAIR OGAN considered Mr. Brena's allegations that the state
had been overcharged $12 billion to be serious and asked him to
explain what he meant.
MR. BRENA replied that he didn't intend it as an allegation, but
the Regulatory Commission of Alaska (RCA) sat through weeks of
hearings and Order 151 shows, on a year-by-year basis on
spreadsheets, that the over-collections were $9.9 billion
through 1996. He added investment return to that - had it not
been overcharged. The over-collection happened when the state
settled by signing a bad deal when it should have litigated.
CO-CHAIR OGAN said while he appreciated Mr. Brena's testimony,
it might throw a wet blanket on the enthusiasm of people
investing in Alaska. He has told investors the best way to avoid
this type of thing is to have clear and concise rules upfront.
MR. BRENA agreed and said he thought getting terms and
conditions right in the first place would result in greater
investment in the state, not less. Tilting the cost of the
pipeline infrastructure so that there are excessive returns for
it would drive out the independents. The best public policy for
the state to adopt is to make sure that the people who build the
line get their costs back for building it, get a reasonable
return for investing in it and get their cost of operation,
which they are entitled to under just and reasonable rates. If
they got more than that, it would discourage investment. Fair
rules for everybody encourage more investment.
SENATOR DYSON commented that the state needs the best
consultants to negotiate with these oil companies that are the
biggest corporations employing the best minds in the world.
MR. BRENA emphatically agreed.
SENATOR HOFFMAN stated that the industry should not view this
hearing as a wet blanket because they are talking about the
state's resources and legislators need to make sure they are
maximized.
CO-CHAIR SAMUELS said the point is to educate legislators with a
variety of ideas and to expose the public on the complexities of
this issue. He mentioned there would be another hearing in July
with entirely different points of view.
MR. BRENA said he would be happy to discuss these ideas with
anyone if the legislature thought that would be helpful.
CO-CHAIR OGAN said he favored an alignment between the state and
producers with an independent pipeline and both would be
interested in having the lowest tariff possible. He thought that
would bring the best netback.
MR. BRENA cautioned that there would be many opportunities for
misalignment.
You don't need complete misalignment, you just need
sufficient misalignment so you have a major shipper
who has an economic incentive in a just and reasonable
rate and that can be a single shipper. For example,
when BP and Arco merged, Arco's interest was allowed
to be acquired by BP. If it weren't, BP would be TAPS'
major shipper and there would be just and reasonable
rates on TAPS. I just used the merger as an example. A
condition of the merger could have been that Arco's
interest was acquired by a third-party. Then the state
would not be losing $100 million a year right now.
CO-CHAIR SAMUELS thanked Mr. Brena for his testimony and invited
Mr. John Carruthers, Vice President, Northern Development,
Enbridge, to testify next on how he would move forward on a
business plan.
MR. JOHN CARRUTHERS, Vice President, Northern Development,
Enbridge, said he wasn't going to forward a proposal, but would
reinforce the idea that there are some options for the state to
consider. Enbridge has had some success with incentive tolling
in Canada in terms of aligning pipeline companies with shippers.
Pipeline companies want to maximize revenue, but not at the
expense of shippers. Obviously there has to be a fair allocation
of costs based on risk assumptions. Shippers often want to align
the pipeline companies with incentive at as low a cost as
possible.
MR. JACK CRAWFORD, Vice President and Chief Operating Officer,
Alliance Pipeline, added that in terms of alignment, he realizes
that almost all cost issues are related to capital costs and
it's very important to control those. Historically, a regulated
pipeline company has the incentive to spend more money because
it makes money on what it spends. So, it makes sense to focus
attention at the outset on the capital costs. As a consequence,
the arrangements that Alliance put in place had incentives to
control capital costs. He didn't know if the same incentives
would be appropriate here because the risks are different.
It is pretty much a risk-allocation-type procedure....
It's probably premature to forecast how that might
look given there is still a number of factors that are
not settled in terms of how the risk would be
allocated in the future.
MR. CARRUTHERS added that companies with experience in building
pipelines in the Western Canadian sedimentary basin are apt to
take more risk in terms of building something if they had done
it before. "It's more difficult in Alaska, because there hasn't
been an underground pipeline built...." The Alliance pipeline
might be able to take more risk because of its recent experience
in the area.
We've had some good experience with incentive tolling
in negotiations with producers in Alberta.
Historically, costs were based on cost of volumes and
it became fairly adversarial where it was in opposing
interests in terms of estimating costs and estimating
volumes. They tended to be adversarial and litigated
and you came up with a solution.
We moved from that to looking at incentive tolling
where the tolls are separated from the costs and
trying to align the shippers with the pipeline
companies. So, the results you were trying to obtain -
that was how you were rewarded on the attainment of
those.
MR. CARRUTHERS said Enbridge had the first pipeline in Canada to
negotiate incentive tolling and it had good success. The first
agreement was in 1995 for a five-year period. It was
renegotiated in 2000 and is being renegotiated again. It has
worked well reducing costs for both parties. A lot has been done
with cost reduction and the renewed negotiations are focused on
providing additional services. Flexibility is needed over time
to realign.
MR. CARRUTHERS noted that work still needs to be done on the
pipeline tariffs, which need to align with the strategy for
commercialization of gas - how it would ramp up and what the
shippers' needs are. While they have heard testimony today that
shippers want predictability versus certainty, that's not
consistent with his experience. Experienced companies are able
to take more operating risk if they have confidence in their
capabilities.
There's a trade-off between project rating in terms of
AA, AAA, B, whatever and the amount of equity risk
that is being taken. So, it's not like [a company] can
always go to one corner of the matrix and pick the
lowest cost, because there is certainly more risk,
which increases the need for returns and higher
equity. As we progress through the design and
development of the project, there certainly is a way
we can align interests between the shippers and the
companies building it.
REPRESENTATIVE BETH KERTTULA said his point about having
incentives to control the capital costs is particularly
important and asked what some of the incentives would be.
MR. CARRUTHERS replied that Alliance has the most current
system.
MR. CRAWFORD related that the Alliance system was constructed on
a contract that used 12 percent as a target rate of return
realizing that at some point, there was a limit on what the rate
of return could be.
TAPE 04-11, SIDE B
REPRESENTATIVE KERTTULA asked him what the rate went up to.
MR. CRAWFORD remembered that it went up to 14 percent, but he
would have to check.
REPRESENTATIVE KERTTULA asked how that was measured.
MR. CRAWFORD replied that it was pretty straightforward, but
there has to be agreement on the initial estimate.
When we were going through the open season, we had a
capital cost that translated through a number of fixed
factors into a rate that customers found reasonable.
As long as that was reasonable, then in effect, the
capital cost was reasonable. There was a recognition
that to the extent that we spent more than what the
capital costs were that the rate would be higher than
what it would otherwise be, but not as high as it
would be if the rate of return stayed the same.
Likewise, if we had been successful in inflating the
cost estimate and we came in under budget, then we
would earn a higher rate of return, but all the
shippers would see a lower rate than what they had
signed up for in the first place. So, why worry as
long as it was acceptable at the target rate? Then,
there was a restraint on what ultimately could be
considered a rate-based company in over-spending and
incentives to minimize costs.
REPRESENTATIVE KERTTULA said that explanation was helpful and
added the state has done something similar in some of its rate
cases. However, the state has a lot more factors in determining
the reasonableness of the costs all the way along rather than
just saying it's set.
CO-CHAIR SAMUELS thanked Mr. Crawford and Mr. Carruthers for
their comments and asked Mr. Palmer to give his presentation.
MR. TONY PALMER, Vice President, Alaska Business Development,
TransCanada Pipelines, Ltd., prefaced his remarks saying he
wouldn't address specifics on how he would structure a tariff.
There are a number of different methodologies used to
create gas pipeline tariffs in the United States and
Canada. My testimony will focus primarily on a cost-
of-service methodology, which is the traditional form
for a new long pipeline system with high risks, as
this project will see. At the end of my testimony I
will discuss a couple of alternatives that could be
utilized for a project such as the Alaska gas
pipeline.
The initial pipeline from Alaska can be expected to
remain regulated by U.S. and Canadian governments. It
will be highly capital intensive with route-specific
investments that cannot readily be redirected to serve
other purposes. Once you lay that steel in the ground,
it's very difficult to move it to provide another
service. The inherent business risks for a pipeline
include development risk, construction completion
risk, reserve, credit, operating, etc.... The pipeline
will be a contract carrier; that is standard in the
gas business.... The regulators in the United States
and Canada - FERC in the United States, the National
Energy Board in Canada - for commercial matters that
determine the types and levels of tariffs, which a
pipeline may charge its customers for the services it
provides and also the terms and conditions of service.
The approved tariffs and terms and conditions attempt
to balance the interests of shippers, consumers, other
stakeholders and the pipeline investors. It's intended
to be a fine balance of interests.
The terms and conditions of service are an integral
part of the tariff and must be considered in
conjunction with the tariff. Natural gas pipelines are
highly leveraged businesses with significant financial
risk and lower business risk than many other large
corporations. That's the structure. Pipeline companies
generally have higher financial risk because they are
highly leveraged and they have lower business risk and
that enables them to take on the additional debt.
That's the fundamental structure that is the
foundation for most pipeline projects.
The Alaska gas pipeline can be expected to commence
operations with a high debt ratio in order to minimize
the pipeline tariff. You heard testimony yesterday
from J.P. Morgan. They gave you some evidence as to
how that variation can change the pipeline structure,
but the fundamental business risk must be matched with
the leverage on the pipe - the debt equity ratio - as
well as the returns.
So, the high debt ratio will require a properly
secured contract with low business risk for the
pipeline. The proposed U.S. energy bill provisions for
the Alaska project stipulate that the U.S. government
may provide loan guarantees [for] up to 80 percent of
the capital costs of the project. Such a loan
guarantee would assist the pipeline owners in
obtaining the multibillions in debt financing and
improve the interest rate and loan terms to the
benefit of all project stakeholders. In order to
obtain the financing, the pipeline must demonstrate
the ability to make payments on its debt, both
principle and interest, generally through long-term
shipping commitments from credit-worthy customers and
by meeting certain debt service coverage covenants and
other loan conditions.
MR. PALMER showed the committee a schematic of the equity
investment that goes into a project of this scale. It
demonstrated that risk capital is advanced by equity investors
early in the project and before the debt is invested.
So, the current investment that my company has, as
well as others, in this project is 100 percent equity.
There is no debt behind the project during the
development phase; it is 100 percent equity - all risk
capital. Even during construction, that also is a
period where you have equity capital. If you have
contractual terms resolved at that point, you can
start to advance your debt during the construction
phase.
Recovery of the equity comes over the life of the project and
while he used 20 years for his illustration, it's typically
spread over the life of a contract.
Most new pipes in North America have been structured
on a cost-of-service basis and a cost-of-service
methodology allows the pipe company to recover all
prudently incurred costs for providing transportation
service including a fair return on capital investment.
This usually results in an efficient use of capital
with the lowest possible tariffs. These low tariffs,
however, are achieved by minimizing the business risks
to the pipeline company. The tariffs are subject to
full discovery and are completely transparent to all
stakeholders for each component of the cost of
service. That cost of service model allows the pipe
company to recover its fixed costs in a demand charge
to its customers - in other words, unrelated to the
actual volumes transported on any particular day....
The variable costs are recovered through a commodity charge,
which is related to the actual volumes. His schematic addressed
property and income taxes and depreciation rate. The
depreciation rate is often a factor that is used on a project of
this scale to adjust the variability of the tariff over time. It
normally reflects the economic life of the pipeline and allows
the recovery of capital, both equity and debt, invested in the
pipeline over that life. The traditional model had depreciation
rates established on a straight-line basis collecting an even
amount of depreciation over the life of the project.
For large new pipelines that need to compete in the
marketplace with existing infrastructure, depreciation
rates are sometimes modified to levelize the tariff.
This means a lower collection of depreciation in the
early years of the project and a higher collection in
the later years, much like a residential mortgage
schedule for principle repayment.... This method, of
course, increases the risk for a pipeline company.
Instead of getting an even recovery, an early recovery
of your capital, you're moving that to the back. That
increases risk. There are a number of other
methodologies that have been used over the years
instead of cost-of-service for gas pipelines.
MR. PALMER said forms of incentive regulation have been used
that apply some degree of sharing between shippers and pipeline
owners for both capital costs, operating costs and,
occasionally, debt costs.
Other forms of negotiated rates include a fixed toll
model with some or all of the components of cost-of-
service fixed for the shipper for some period of time.
This methodology provides toll certainty for the
customer, but significantly increases the risk for the
pipeline company. Changes in inflation, interest
rates, equity returns for investments of similar
risks, capital cost overruns, operating tax variations
in a fixed toll model may not be fully passed through
to the customer as would be the case for the cost-of-
service methodology. There are definitely merits to
different tariff methodologies that can be considered
for the Alaska gas pipeline by project stakeholders. A
traditional cost-of-service methodology with terms
negotiated between the pipe company and the shippers
and ultimately approved by regulators will usually
result in the lowest tariff over the life of the
project as it should have the lowest business risk for
the pipeline company, assuming solid transportation
contracts with strong credit-worthy customers.
However, this methodology increases the risk
allocation for the shipper and may not provide the
highest value to the shipper. If actual costs differ
from estimated costs, then all these changes will be
fully borne by the customer in the cost-of-service
methodology. That's the way it works. For example, you
have current interest rates at extremely low levels.
You heard testimony to that effect yesterday from J.P.
Morgan. An estimated cost-of-service tariff today
would likely use those low interest rates. If the
actual interest rates are several percentage points
higher at the time the pipeline were actually
financed, cost-of-service methodology would insure
that 100 percent of those increased costs would be
passed through to the customer in their tariff and it
works the other way, as well. If interest rates fall,
that's a pass-through to the customer. That's not a
risk the pipeline company bears in a cost-of-service
methodology.... You would have an estimation based on
interest rates, inflation and other components. The
actuals will be what will show up in people's tariffs.
A fixed toll model or other incentive mechanisms shift
some or all of the inflation, interest rate return and
equity, operating costs, capital costs and capital
cost recovery onto the pipeline company. Capital
recovery shifts can imply the pipeline is bearing gas
reserves risk in the case where proven gas reserves
are insufficient to fill the pipeline beyond the
contract term. That may be a risk that the shippers
want to bear and it may be a risk that they want the
pipeline to bear or some sharing of that risk. This
shifting of risk could be beneficial to a shipper that
cannot or will not bear the risks inherent in a cost-
of-service tariff. A fixed tariff with commensurate
lower risks can provide higher value to some shippers
despite a higher nominal tariff than would be applied
with a cost-of-service methodology.
I'll give you an example in ordinary life - is some of
us choose to sign up for a 30-year residential
mortgage because we want to know that the price of
that interest rate over the life of that mortgage.
Others of us choose to go for six-month mortgages.
Generally, the six-month mortgage has a lower interest
rate. Which is better? Well, it depends on your
circumstances and which suits your pistol, in effect,
as to how you would like to structure your business.
It's not that one is better than the other. Some
parties will prefer one and some parties will prefer
another. We would suggest that the shippers and
pipeline companies and other stakeholders will
negotiate the methodology that is best for all
parties. North American regulators have been
cooperative in recent years in approving negotiated
methodologies if sophisticated parties have negotiated
arrangements on both sides. So, if you have
independent pipeline companies negotiating with
sophisticate shippers or other stakeholders,
regulators have generally been cooperative in
approving those. Transcanada has significant
experience in cost-of-service models as well as
negotiated or other incentive models and we're ready
to negotiate with shippers and other stakeholders on
the tariff model which best suites the project, which
provides a reasonable reward commensurate with risk
for the pipeline and a clear regulatory path to an
early in-service date. If customers and other
stakeholders want a cost-of-service methodology,
that's just fine with our company. If they prefer
other alternatives that will shift some risks assuming
that there's a balance of risk and reward, we're happy
to negotiate on those, as well.
CO-CHAIR SAMUELS thanked him for his testimony. There being no
further business to come before the committee, he adjourned the
meeting at 12:20 p.m.
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