Legislature(2001 - 2002)
04/10/2002 03:42 PM Senate NGP
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
April 10, 2002
3:42 p.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Rick Halford
Senator Pete Kelly
Senator Donald Olson, alternate
SENATE MEMBERS ABSENT
Senator Johnny Ellis
HOUSE MEMBERS PRESENT
Representative Brian Porter
Representative Mike Chenault, alternate
Representative Reggie Joule, alternate
HOUSE MEMBERS ABSENT
Representative Joe Green, Vice-Chair
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate, alternate
COMMITTEE CALENDAR
UPDATE ON CALGARY CONFERENCE: SENATOR TORGERSON
UPDATE ON FEDERAL LEGISLATION: PATRICK COUGHLIN
INTRODUCTION OF SB 360 - "ALASKA NATURAL GAS PROJECT ACT"
ECONOMIC MODELS OF PIPELINE PROJECTS: DR. DOUG REYNOLDS
PREVIOUS COMMITTEE ACTION
None
WITNESS REGISTER
PATRICK COUGHLIN, Special Consultant
to the Senate Resources Committee
Alaska State Legislature
Capitol Building, Room 427
Juneau, Alaska 99801
POSITION STATEMENT: Discussed federal legislation before
Congress and contrasted it with provisions suggested by the
committee.
DOUGLAS B. REYNOLDS, Ph.D.
Northern Economic Research Associates
Fairbanks, Alaska
POSITION STATEMENT: Gave slide presentation on "Economic Models
of Pipeline Projects"; provided handout and answered questions.
ACTION NARRATIVE
TAPE 02-6, SIDE A
Number 0001
CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural
Gas Pipelines meeting to order at 3:42 p.m. Members present at
the call to order were Senators Torgerson and Olson, and
Representatives Porter and Joule. Arriving as the meeting was
in progress were Senators Halford and Kelly, and Representative
Chenault.
UPDATE ON CALGARY CONFERENCE: SENATOR TORGERSON
Number 0039
CHAIRMAN TORGERSON announced the first order of business, an
update on the Global Petroleum Show to be held in Calgary,
Alberta, on June 11-13, 2002. He surmised that the show is
probably the largest in North America. [In packets was a
memorandum from Chairman Torgerson to the committee; information
from the International Alaska Highway Pipeline Committee,
including a mission statement and principles; and a registration
packet and related backup materials.]
CHAIRMAN TORGERSON informed members that the charge for the
committee's portion of the conference had been settled on three
days before. Invitations for one panel had been extended to the
chairman of Canada's National Energy Board (NEB) and to Patrick
Henry Wood III, Chairman, Federal Energy Regulatory Commission
(FERC). Also invited were the Regulatory Commission of Alaska
(RCA) and the equivalent provincial and territorial regulatory
agencies from British Columbia, Alberta, and Yukon Territory.
CHAIRMAN TORGERSON noted that the focus would be on NAFTA [North
American Free Trade Agreement] issues, including cross-border
contractors' going back and forth and what kind of problems that
could entail; he said at least one NAFTA attorney has confirmed
thus far. In addition, the university is to speak about
training and any reciprocity agreement that might be entered
into for cross-border training. Furthermore, a panel of the
"ministers and commissioners of labor" will discuss other labor-
related issues.
CHAIRMAN TORGERSON advised members of the intention to hold the
foregoing discussions on June 12, although he indicated a
possibility of extending into June 13 if necessary. He said
[the conference] is cosponsored by the international committee
he'd established [the International Alaska Highway Pipeline
Committee], which includes members from British Columbia,
Alberta, and Yukon Territory. In addition, there will be
representatives from the Northwest Territories, including people
from its university, although it has no members on the
international committee.
CHAIRMAN TORGERSON noted that the show will be large, but with
no registration fee because most of the money will be made from
the trade show itself. There will be a reception for the
international group, which he indicated the show is paying for.
Number 0236
CHAIRMAN TORGERSON advised members that he most likely wouldn't
call a meeting of the Joint Committee on Natural Gas Pipelines
at the show, but encouraged as many members as possible to
participate. He noted that a booth has been rented and said the
Division of Oil & Gas will hand out promotional lease
information in order to foster interest from companies; in
addition, the booth will be available to any Alaskan businesses,
25-30 of which have shown interest so far in sending a
representative. Details are pending, with few people confirmed.
Chairman Torgerson concluded by indicating the process had just
begun, with invitations already extended to many people.
UPDATE ON FEDERAL LEGISLATION: PATRICK COUGHLIN
Number 0325
CHAIRMAN TORGERSON announced the next order of business, an
update on federal legislation currently before Congress. He
introduced Patrick Coughlin, a consultant to the Senate
Resources Committee, by saying he has been invaluable in working
with the attorney hired in Washington, D.C., regarding federal
issues. He then explained that the starting point was the
principles adopted by the current committee. "We got a lot of
those in the bill," he said. "A lot of the language in the bill
was ours. So we did relatively good work there - not winning
every issue, but coming close."
Number 0371
PATRICK COUGHLIN, Special Consultant to the Senate Resources
Committee, Alaska State Legislature, informed members that he
would go through the federal Alaska Natural Gas Pipeline Act of
2002 ("the Act"), which is part of the national Energy Policy
Act of 2002 being debated by the U.S. Senate now, and would
compare it with recommendations made by the current committee.
MR. COUGHLIN noted that during February and early March, many
amendments were made to the Act, and there were suggested and
rumored amendments as well. Tracking what was going on was
difficult, he said, but was helped by Karol Newman, a lawyer
retained by the legislature in Washington, D.C. He noted that
Chairman Torgerson had spent many hours talking with U.S.
Senator Frank Murkowski's staff, other legislative staff, and
"our attorneys in D.C." to keep abreast of what was happening
there.
Number 0453
MR. COUGHLIN reported that the most recent version of the Act
was proposed as a bipartisan amendment on March 21 by U.S.
Senators Murkowski and Bingaman. He reminded members that the
first proposal put forth by the Joint Committee on Natural Gas
Pipelines, on September 19, 2001, was a provision to ban the
"over-the-top" route; that is currently in the [U.S.] Senate
version of the Act. Under the next proposed amendment, any
certificate FERC would issue for the project "shall" require
that access be granted for the state's royalty share of its gas;
the current version of the Act, by contrast, says it "may" be
provided, and only if it doesn't increase existing shippers'
costs. Mr. Coughlin noted that it is a little weaker in
protecting the state's rights than the current provision in
ANGTA [the federal Alaska Natural Gas Transportation Act of
1976], which says "shall".
MR. COUGHLIN highlighted other provisions in the Act dealing
with state access. For example, the applicant for a certificate
to build the pipeline must conduct a study of in-state needs and
present it to FERC; the study must include a description of
potential tie-in points within Alaska. Also regarding access,
the current committee has requested that RCA and FERC jointly
set rates for the in-state portion of the transportation; by
contrast, the Act allows FERC to set the rate by itself, but
FERC must consult with the state before doing so.
Number 0595
MR. COUGHLIN turned attention to issues regarding "explorer
access" for oil and gas companies. These explorers are
companies that have lease rights on the North Slope and that
currently are either exploring or planning to explore for gas;
they would have no ownership interest in the pipeline. Mr.
Coughlin reminded members that this committee has requested an
open-season provision that would allow the explorers to at least
bid in a consistent or fair manner. Under the requested
provision, FERC would establish regulations to govern an open
season; FERC would consider effective competition in determining
how to conduct the open season - in other words, it would set up
an open season such that it would continue competition in the
oil and gas industry in Alaska; and for any open season beyond
the very first one, the procedures would maximize the
opportunity to ship gas from oil and gas units other than
Prudhoe Bay or Point Thomson, which are held by the current
producers. The Act contains that type of provision, Mr.
Coughlin reported.
Number 0677
MR. COUGHLIN reminded members of this committee's request that
FERC have authority to expand the pipeline under certain
circumstances; he said the Act currently grants that expansion
authority, although it requires FERC to make more findings than
requested. With regard to the request that the explorers only
would pay for conditioning services they use, however, that
provision was not adopted and isn't currently in the Act.
MR. COUGHLIN noted this committee's request that the term
"Alaska North Slope gas" be expanded to include gas resources in
the so-called foothills area of the state and as far south as
Nenana; he explained that there is a potential gas basin in
Nenana that might benefit if the pipeline goes south and goes
through there; that provision was adopted by the [U.S.] Senate.
Mr. Coughlin pointed out that one of the three purposes of the
Act is to establish a process for providing access to such
transportation projects "in order to promote competition and
exploration, development, and production of Alaska natural gas."
Number 0805
MR. COUGHLIN reminded members that this committee has wanted to
ensure that supporting this "producers' enabling legislation"
doesn't hinder "those that had ANGTA rights." Therefore,
provisions have been requested to reaffirm ANGTA and allow it to
be modernized; those provisions have been adopted as part of the
Act. Furthermore, he said, the current committee was concerned
about the Yukon Pacific Corporation (YPC) project and had
specifically requested a provision to protect the presidential
waiver granted for the YPC project; that also has been adopted.
MR. COUGHLIN said the other request relating to ANGTA "fell by
the wayside when the 'foothills group' decided that they ...
would no longer oppose the producers' legislation." He added,
"We did request them, but I'm not sure that they're relevant
anymore."
Number 0830
MR. COUGHLIN turned attention to requests relating to Alaskan
jobs. He noted this committee's request for a provision calling
for approval of a project labor agreement "in the sense of the
Senate provision"; he reported that the U.S. Senate has said it
urges the sponsors of the project to agree to a project labor
agreement." He noted that Congress didn't grant a preference to
Alaskan workers, but passed several provisions to enhance
opportunities for Alaskan employees and contractors. Mr.
Coughlin said those include the following:
The Secretary of Labor is required to prepare a report
setting forth a program to train Alaska residents in
the skills and crafts required to design, construct,
and operate a pipeline, to enhance employment and
contracting opportunities for Alaska residents. The
report should recommend needed changes to laws or
regulations that act as a deterrent to hiring Alaskans
or contracting with Alaskans. And the Secretary of
Labor must establish, within one year after preparing
the report, training centers within Alaska to train
... Alaskans in the skills necessary. ... And $20
million is appropriated to the Secretary to carry out
the purposes of this particular provision.
Number 0906
MR. COUGHLIN addressed financing proposals. He reminded members
that this committee has recommended opposition to any incentives
for foreign LNG production that is being brought into the United
States; the Act currently provides for none. In addition, this
committee has supported having an accelerated-depreciation
provision; although one was adopted, it was for ten years,
rather than seven. That disagreement between the [U.S.] House
and Senate versions of the bill likely will be taken up in a
conference committee if the Senate passes the Act, he noted.
Furthermore, this committee has supported a provision to reduce
price risk uncertainty so long as state finances aren't harmed
by such a provision; that provision is being worked on
currently. He said he expected to see an amendment to that
effect the coming Friday.
MR. COUGHLIN concluded by offering his understanding that if
there is a conference [committee] between the [U.S.] Senate and
the House on the energy bill, Chairman Torgerson plans to work
with such a committee to try to change some of the provisions in
the pipeline Act portion to further benefit Alaskan citizens.
Number 0995
REPRESENTATIVE PORTER referred to Mr. Coughlin's mention that
[under the Act] FERC is required to consult with the state,
rather than having RCA participate. He asked whether the Act
says who in the state is supposed to be consulted.
MR. COUGHLIN answered no, specifying that it just says "the
state".
REPRESENTATIVE PORTER asked what the state would do if there
were no guaranteed access for royalty gas. Would the state have
to stand in line at the open season, like everybody else?
MR. COUGHLIN answered that it is unclear. Like any other
entity, the state would have the right to petition FERC; as long
as the state could show that the gas could be taken off without
harming other shippers, and would pay that cost, it could get
access. He added, "As I understand it, under the current
version, there's no special protection for the state as was
contemplated in ANGTA."
Number 1057
CHAIRMAN TORGERSON explained, "Clearly, we have in our leases
that the producers have to ship our royalty gas, ... whatever
our percent is. So the confusion comes from future discoveries
where we have royalty gas, where it would require an expansion
of the line or less producer gas shipped down the line, to
accommodate our royalty." He reiterated that he is still
working on it and that there will be a conference committee [if
it passes the U.S. Senate]. He thanked Mr. Coughlin.
INTRODUCTION OF SB 360 - "ALASKA NATURAL GAS PROJECT ACT"
[This was not a scheduled hearing, but an explanation before the
Joint Committee on Natural Gas Pipelines.]
Number 1098
CHAIRMAN TORGERSON announced the next order of business, an
explanation of SB 360, which was introduced that day by the
Senate Resources Committee. As chairman of that committee as
well, he explained the intention behind the legislation.
CHAIRMAN TORGERSON expressed hope that SB 360 will become a
vehicle for "passage of any of the work that we're currently
doing." He said it accomplishes a lot of necessary things.
First, it recognizes that there won't be a project built this
year. There isn't a lot of work that the legislature needs to
do this year, he explained. However, there has been a public
expectation that something would happen, such as passage of
legislation to provide incentives or help spur the project.
"I've said, from day one, that I would not leave my negotiations
with an incentive," he said. "I still believe that, that we
shouldn't until all the details are laid on the table of what
we're doing, what the project economics are."
CHAIRMAN TORGERSON noted that the timeline for receiving the
project economics has continued to slide backwards, with nothing
received; he said he isn't sure that information will be
received this session, but believes it is important to at least
put the parameters together that would direct the administration
to start negotiations, for example, with municipalities on some
of their issues. In some cases, he noted, it will come back to
the legislature for approval later.
Number 1194
CHAIRMAN TORGERSON highlighted provisions of SB 360. It allows
the project to be phased under the Alaska Right-of-Way Leasing
Act. It gives all agencies the full cooperation of the
Department of Natural Resources (DNR) commissioner, "more or
less," for expedited permitting. It allows the governor, if
he/she finds provisions of the law that impede the project, to
propose a waiver. Furthermore, any decisions by the
commissioner or other agencies shall be subject to limited
judicial review. He remarked, "These are all part of ANGTA that
we wanted to have part of our laws." It also says that any
judicial action brought must be done within 60 days, he noted.
CHAIRMAN TORGERSON continued, noting that SB 360 allows the
commissioner of the Department of Revenue to start negotiations
with local governments on property tax "after they are sure that
the project is not economically feasible, and then the
commissioner will put together a ... [socioeconomic] report on
the impacts of local governments, and then ... he may recommend
to us whether to waive it all, reduce it, defer it, or whatever;
and that would require legislative approval after that work is
done." The bill also directs the commissioner of DNR to waive,
reduce, or defer all or part of the royalty payments on the
project; again, this takes legislative approval, he told
members, upon discovery that the project is not economically
feasible without taking such action. Furthermore, it allows the
Alaska Railroad Corporation (ARRC) to issue tax-exempt bonds for
the project.
CHAIRMAN TORGERSON mentioned the commissioners of the respective
agencies and noted that under SB 360, companies must agree,
before receiving any benefits, to train and hire Alaskans and
use Alaskan businesses in the construction and operation of the
project, consistent with constitutional provisions. They also
must complete a study on in-state demand and submit a plan that
must be approved by RCA; complete a study on natural gas
resources in northern Alaska; and submit a plan that must be
approved by RCA to maximize access to the project so that
competition for Alaskan oil and gas can be promoted.
Furthermore, they must update the studies after ten years, and
they must agree to the provisions in the right-of-way lease
[providing] for in-state use of gas and expansion of the
project.
Number 1329
CHAIRMAN TORGERSON characterized SB 360 as a carrot-and-stick
approach intended to bring everybody to the table. He noted
that it would be heard [by the Senate Resources Committee] on
Monday [4/15/02], when the commissioners and so forth, along
with the oil companies, if ready, would testify by invitation
only; he expressed the hope of moving it from committee at the
following hearing so it could go to the Senate Finance Committee
for debate. Again suggesting that SB 360 is the vehicle to use,
he acknowledged that it is major legislation to get through the
process in the time remaining. He concluded the discussion of
SB 360 by encouraging members of the Joint Committee on Natural
Gas Pipelines to read it and provide any suggestions.
ECONOMIC MODELS OF PIPELINE PROJECTS: DR. DOUG REYNOLDS
CHAIRMAN TORGERSON announced the final order of business, a
presentation by Dr. Douglas B. Reynolds, whose Fairbanks-based
economic firm was hired by the committee in February through the
work of the Legislative Council. He mentioned the series of
models that have been reviewed and the frustration from not
having figures from the producers. He explained that there had
been a need to narrow it to a few models, rather than having so
many variations. Therefore, a couple of weeks ago he'd asked
Dr. Reynolds to have economists from the Department of Natural
Resources (DNR) and the Department of Revenue meet along with
Bonnie [Robson] of [the Division of] Oil and Gas.
CHAIRMAN TORGERSON indicated that the handout provided to the
committee, which duplicates Dr. Reynolds' slide presentation, is
the product of that discussion. Indicating there wasn't
agreement on every point, he said Dr. Reynolds would highlight
the parts for which there is insufficient data. He also noted
that extensive work had been done with Yukon Pacific Corporation
(YPC) on its model, as well as with the [Alaska Gasline] Port
Authority, which had provided a lot of data and information. In
addition, there has been input from Canada. "They kind of took
the best of all inputs," he added, turning the presentation over
to Dr. Reynolds.
Number 1501
DOUGLAS B. REYNOLDS, Ph.D., Northern Economic Research
Associates (NERA), came forward, noting that he is a professor
of economics at the University of Alaska Fairbanks (UAF) and is
working as a consultant for the legislature along with Dr.
Robert R. Logan and Dr. H. Charlie Sparks of UAF. He introduced
his assistant, Michael Backus, noting that he is an Alaska
Scholar. Elaborating on the slide presentation, Dr. Reynolds
told members:
Building a model has been really complicated, because
what we're trying to do is compare three different
types of models. And there's a lot of ... issues
involved. Before we started, we looked at a large
number of other models. We looked at Canadian models,
Cambridge Energy Research Associates models, YPC, and
many others, and also the Department of Revenue,
Department of Natural Resources, and worked with their
economists. We had updates with Senator Torgerson and
Patrick Coughlin. And ... we finally came down to ...
the three major models, because you can always change
things - and we can change things ... in our basic
model - but we had to narrow it down to three basic
models to look at.
Number 1581
DR. REYNOLDS presented a slide [page 3 of the handout] that
called rate of return (ROR) "a cash flow concept." Noting that
this is a general concept with many variations, he said it would
be used to compare the projects. He paraphrased from the slide
from page 4 of the handout, which provided the following
information: ROR is like interest from a bank; higher ROR means
a better investment and more profit; if ROR is low, then firms
choose alternative investments; and producers want to sell gas
to high-ROR projects. He said producers will want to sell their
gas to the best project out of all possible projects, and
usually will want a higher rate of return.
Number 1629
DR. REYNOLDS turned attention to the first issue that can affect
ROR, which is leveraging [page 5 of the handout]. He explained
that most companies start with 100 percent equity to compare
projects, but then may do some leveraging - some debt, some
equity - once they actually do the project. He added, "And then
when you do the leveraging you'll have to weight-average what
your whole return is."
DR. REYNOLDS turned to the second issue, natural gas liquids
(NGLs) [page 6 of the handout]. He said:
Now, NGLs are already used for miscible injectants on
the Slope for producing more oil. And the heavier NGLs
can ... already be shipped down TAPS [Trans-Alaska
Pipeline System] ... because they're heavy enough to
get into the ... pipeline, and they can be sold. The
lighter NGLs would go through the pipeline with the
methane - which is the usual gas for natural gas - and
then be stripped out at the end of the pipeline. The
NGLs are more valuable. So, obviously, if you sell
more NGLs, you're going to make more money. So that's
a big issue in a lot of these different projects. And
if you sell more, you'll get a higher rate of return.
However, one of the last things I should say is that
it's questionable how much these NGLs are sustainable.
In other words, ... if you start taking a lot of NGLs,
especially propane, the amount of propane's going to
start to decline over time. And so, some of the models
... that we've looked at have very high propane levels
that they're trying to extract and use, and those high
levels cannot be sustained for ... a long time. So it
would impact their models.
Number 1710
DR. REYNOLDS turned to the third issue, economies of scale
[page 7]. He emphasized the importance of this big factor in
terms of costs, as brought up by the port authority, since for a
larger-diameter pipeline, costs per bcf [billion cubic feet] will
be lowered. With regard to liquefied gas (LNG), however, he
said:
As far as LNG - liquefied natural gas - plants, you
will usually build one plant, and then, when that's at
capacity, you'll build another plant, and you're not
going to get a lot of economies of scale, especially
for the larger Alaskan projects, because they have to
build these LNG plants all at one time. They can't
build one and then build another and then another,
which is what is usually done. In order to make the
economies of these projects work, they ... basically
have to build them all at one time. Of course, if you
get lower costs, you increase your rate of return.
Number 1752
DR. REYNOLDS addressed a graph labeled "Economies of Scale" [page
8] that he described as an example of how economies of scale
work. As the bcf output increases, he noted, costs per bcf for
[LNG] plants and tankers won't decline, but costs for the
pipeline will.
DR. REYNOLDS discussed a diagram labeled "Typical Y Line Concept"
[page 9]. He asked that members not focus on the numbers, but
focus instead on the big circle on the lower right-hand side,
which read, "Total cost of Valdez LNG line: $7.2 billion." He
reported that in this particular model, that $7.2 billion is for
the 2 bcf going from Delta Junction to Japan. It takes 4 [bcf a
day], with a split after Delta Junction that provides 2 bcf to
Japan, at a cost of $7.2 billion, and 2 [bcf] to Alberta. There
are economies of scale from the North Slope to Delta Junction, he
added.
DR. REYNOLDS addressed a diagram labeled "Typical ALCAN Route"
[page 10]. If all 4 bcf [a day] went to Alberta, he noted, the
cost of getting that extra 2 bcf to market in Alberta would be
$3.2 billion, less than half [of the cost to Japan], because the
pipeline would be made larger from the planning stages onward.
That will be a big factor for the rate of return.
Number 1853
DR. REYNOLDS turned attention to the fourth issue, the price of
the product [pages 11-12]. He noted that there are two
different markets: the Pacific Rim and North America. Although
potentially there is "20 new million tons of LNG per year demand
in the Pacific Rim," there is a lot of supply, especially from
the Middle East; he cited Iran, Saudi Arabia, and Qatar as being
on or close to the shoreline, so that a large pipeline isn't
needed. He also mentioned Indonesia, Australia, and Russia.
Dr. Reynolds said the only way to outcompete those is to have a
lower price. The problem with the models or projects with
Alaskan LNG is the need to sell a lot of LNG once the pipeline
is finished; it needs to be sold all at one time, which is a lot
for that particular market. He added, "You also have to do it
for Alberta, but the percentage of the market is a little lower
for Alberta than for ... the Pacific Rim." Historic prices
cannot be used to determine the price of sale for the Pacific
Rim, he added, noting that lower prices reduce the rate of
return.
DR. REYNOLDS explained why he believes North America is a better
market. In the North American market, demand is increasing at
about 2 percent [a year]. One advantage Alaska will have is
that the mid-continent supply is close to or on the verge of
being in decline. He mentioned onshore natural gas supplies and
then said LNG imports are "difficult to do into the U.S."
because of difficulties with permits or high expense, and they
take time. He said there probably will be 1 or 2 new bcf a day
of demand in the U.S. every year, "and so prices in the U.S.
could ... be a lot higher." Indicating Alaska's primary
competition would be Texas, he said:
Texas has saturated everything they've looked for,
everything there, and they're on the verge of decline,
just like in 1970, when their oil production went in
decline. And once it went in decline, it ... went
down pretty fast. And the same thing's probably going
to happen with their gas supply, and that's where
Alaska will have a great advantage. So, in my
opinion, the North American market is a much better
market.
Number 1980
DR. REYNOLDS turned to the fifth issue, risk [page 13]. He told
members:
Producers have to guarantee a "ship or pay" contract.
It really doesn't matter who owns the pipeline.
They're going to take the risk; they have to guarantee
the contract.
Another part of the risk is that this is a very large
... project. Not many projects have been done that are
this large. ... Really, the only comparable projects
are the TAPS oil pipeline and the natural gas pipeline
... built in the Soviet Union to Western Europe back in
the '80s. But both of those projects had better ...
economics than this project. For example, the oil
pipeline had tremendous revenue potential compared to
the costs; even though the costs were high and they
could have been higher, you'd still make money on ...
that oil pipeline. On the Soviet ... gas pipeline,
they had much lower costs compared to Western Europe
because in the '80s the Soviet Union had a closed
market; its ruble was nonconvertible, and so, in
essence, they had much lower costs ... than what was
available for their revenues ... in Western Europe. ...
This [Alaska] gas pipeline has huge costs, and the
revenues are just on the verge of making or breaking
... the economics of building that. And so it's a much
... tighter fit between revenue and costs than either
of those large pipelines. So you have a large
pipeline. It has to be all or nothing: you either
build it or you don't. And you have to sell that gas
once it's built or you're not going to make money, so
you have to sell it right from the start. And that
makes it ... a pretty risky affair. ... If you have a
lot of risk, then you have to have a higher rate of
return to compensate for that risk.
Number 2062
DR. REYNOLDS addressed the sixth issue, federal tax exemptions
[pages 14-15 of the handout]. Mentioning tax-free [bond
financing] proposed for the Alaska Railroad Corporation (ARRC),
he said tax-free bond financing could lower the financing costs
and help the rate of return somewhat. However, a tariff income-
tax exemption "may or may not really help." For example, one
idea for a port authority or other authority would be having an
income-tax exemption to lower costs. But the problem is that
there needs to be a way to hand that value over to the producers,
who otherwise don't benefit. Although that might not be
important to the State of Alaska, he suggested, it probably is
important with regard to the desire to do "one or another
project." He said it isn't possible to hand over a tax benefit
to the producers without its being taxed in some way; if it is
handed to the producers as a fee or a higher wellhead [price],
then it will be taxed.
Number 2119
DR. REYNOLDS turned to the seventh issue, in-state demand
[page 16]. Noting that in-state demand obviously is important to
the State of Alaska, he said one problem is when it will be
needed. He explained:
We have Kenai gas right now, and eventually sometime
it's ... going to run out, and so ... the state is
going to want some gas from the North Slope. Well, if
you build a pipeline with some extra capacity for that
in-state demand, you have to pay [for it]. And if it's
not used right away, then you have a lot of cost that
is not productive; it's like nonperforming assets. And
that's going to lower the rate of return for the entire
project. So either somebody has to pay for that extra
capacity or it has to be used right away. And since
right now the Kenai does have gas reserves for at least
... five or ten years, then ... it might potentially
sit idle.
According to the Department of ... Natural Resources,
they had a ... demand scenario, and ... by maybe 2020,
if Kenai gas does decline, the in-state demand could be
... 1 bcf per day. And the normal project for this gas
line is somewhere around 4 bcf per day. So you're
talking about an extra bcf. You either have to take it
out of that capacity - which would mean there's a ...
lot of pipeline ... going to Alberta that's not being
used, and so you're not paying for that asset - or you
have to build the extra asset and pay for it somehow.
So that's important to remember.
Number 2185
DR. REYNOLDS turned attention to the next slide [page 17 of the
handout], "Producer Numbers," which read simply, "We asked for
but have not yet received producer study numbers for their
projects."
DR. REYNOLDS discussed the next slide [pages 18-19 of the
handout, labeled "Approximate Model Cost Assumptions"]. He said:
After looking at a lot of different ... engineering
reports and estimations, we come out with about
$140,000 per inch mile, less in Canada. This includes
the pipe and compressor and installation. You can
separate these costs, but when you put them back
together again, you get roughly 140,000 [dollars], give
or take - obviously, it's only an estimate. Now, ...
for example, if we have a ... 4-bcf project, you might
need a 46-inch pipe. One mile of that would cost $6.4
million. You just multiply ... 46 times ... $140,000
times one mile. ... So if you had a thousand-mile
pipeline, that's $6.4 billion.
DR. REYNOLDS offered the following estimates: for conditioning
plants, roughly $600 million per bcf plus some fixed costs; for
LNG plants, roughly $1.6 billion per bcf; and for LNG tankers,
approximately $170 [listed as $175 on the handout] million per
ship, with about three ships needed per bcf. He alluded to the
following statement on page 19: "There are some gas losses
during gas shipping which reduces revenues." He remarked that
these were just the rough numbers used in the model.
Number 2252
DR. REYNOLDS discussed the final model [page 20 of the handout],
noting that for comparing the different projects, the same cost
structure and "rate of return" concept was used for all.
However, there will be a higher amount of NGLs sold for smaller
projects than for bigger ones, and it is tough to compare them
for these different projects. He indicated that after talking to
a lot of people to try to figure out the best way to compare
them, he believes this is the best comparison possible.
[Dr. Reynolds continued his slide presentation, discussing the
unnumbered three pages of models found at the back of the
handout. At the top of each page it said "30 Years of
Production" and listed the following categories from left to
right: Capital Cost (millions) (2002$), bcf/day, Return on
Equity, Return to Project, Wellhead, State Revenue (millions)
(2002$), Federal Revenue (millions) 2002$), Canadian Revenue
(millions) (2002$), and Undiscounted Profit (millions) (2002$).]
Number 2292
DR. REYNOLDS noted that the first set of numbers relates to YPC.
He pointed out that the "Return to Project" category should be
"Return to Earnings." Including tax exemptions and so forth, he
said [YPC] would get about 14.8 percent, whereas [the state]
would get about 13.21 percent. More important, he said, is that
on the basic model, "our 1.5 model" [labeled "NERA LNG 1.5 on the
handout], at 100 percent equity, uses the same kinds of inputs as
for the next models, and shows about a 12 percent rate of return.
He said there are similar costs for the NERA model versus the
YPC, but that YPC's uses a higher price in Japan. He explained
that the gas must be sold within a year of the end of
construction; otherwise, money is lost quickly and the rate of
return starts going down. To do that, he suggested, there must
be a little lower price. He said YPC deals with that issue [in
its model] by selling some to Japan and some to California; the
second price is a California price. By contrast, Dr. Reynolds
said, "We just ... sell it all to Japan at one price, so it's
kind of a medium ground for that. They also sell some to
Alaska." He said the "outputs" are fairly close.
TAPE 02-6, SIDE B
Number 2352
DR. REYNOLDS turned to the next slide [the second page of the
models]. He noted that the port authority model [for a "Y-Line
6"] is a huge, 6-bcf project, although the producers also
envision having 6 bcf going to the Lower 48; therefore, he said,
it isn't out of the question. He pointed out that the port
authority's capital costs are only for Alaska, so it's hard to
compare them exactly because the [NERA] model includes all the
Canadian costs. He explained:
They don't have a rate of return because ... they have
theirs 100 percent debt financed, which is hard to
compare. In order to get close to their model, we put
85/15 ... debt/equity. And we get maybe ... a higher
wellhead [price]. And as far as state revenues are
concerned, ... in order to get what they got, we had to
put it at a 7.3 percent net present value, and we get a
little bit lower than what they got. When you put it
on a 100-percent-equity basis, we get a rate of return
of 4.31 percent; that's compared to about a 12 percent
for the YPC project. ...
I know this whole thing is complicated, but what you
might want to look at is this "ALCAN marginal" [listed
under "NERA Y-LINE 6"] and what that is saying is, what
if, instead of having a 6 bcf where 3 goes one way and
3 goes the other way, let's put the 3 to the LNG in
with the 3 to Alberta and make it a total 6 [bcf]
project, and what's the marginal benefit for those 3
bcf that went to the LNG? And we would get a higher
return on that. Now, that's assuming that prices don't
change in the Lower 48, ... which could be the case.
Anyways, the total 6, if we just did an ALCAN 6 [shown
on handout], we would get something on the order of
almost 17 percent rate of return. And ... the costs
are pretty similar, only they don't have the Canadian
costs, so we had to put those in. They think they can
get a $3.35 price in Japan; we say $3.10.
Number 2259
DR. REYNOLDS continued comparing models:
The port authority used to say that they could get a
$3.10, and then recently - because of violence in the
Middle East and so on - they think they can probably
get a higher price, which may be true, but if ... you
get a 20-year contract with a little higher price
because there's violence in the Middle East, what
you're saying is that you think there's a lot of risk
involved with not getting ... gas from the Middle East.
If you're saying you can't get the gas, you might not
be able to get the oil. And if you can't get the oil,
the price of oil and gas is just going to go sky high.
And then you get a high price in the Lower 48 too - a
much higher price.
So I'm reluctant to go with the $3.35; I would go with
$3.10, and even that's going to be ... hard to sell.
... I'm thinking I'm giving the benefit of the doubt;
they might argue it's just my opinion I'm giving the
benefit of the doubt to give a $3.10 price. It could
be lower because ... that's a very high number, 14
million tons per year, when we only expect maybe 10
[extra] million tons in the next 10 years to be needed.
...
So they're going to have to sell a lot of gas; they're
going to sell it to China, Korea, and so on, and China
... could be a problem. In their basic model, they're
selling 14; in our basic model, we're selling upwards
of 18. They're selling a lot of propane; we cut down
those numbers because we don't think ... their numbers
are sustainable. We do give a lot of ethane - this
"NGL" is the ethane - which may or may not be possible.
And then they sell a lot of pentane, which we believe
the producers would just take for themselves, because
it's not hard to take out ... the pentane. It's the
heavier NGLs. ... It doesn't really make too much
difference on the rate of return, but for their project
it ... probably makes a lot of difference. Anyways,
the number to remember is 14.31 percent rate of return.
Number 2114
DR. REYNOLDS addressed the final slide [last page of models in
the handout], calling it a "basic ALCAN 4." He said the numbers
are from the producers' midsummer report last year, and that the
$13 billion includes Point Thomson's development, which wasn't
included in the ["NERA ALCAN 4"] model in order to get close to
[the producers'] numbers. He explained, "If we tried to get as
close to what they are doing as possible, we get ... almost [a]
15.5 percent return."
DR. REYNOLDS told members, "There's been a lot of confusion about
the state and federal revenues. These numbers are not adjusted
for inflation, whereas we always adjust for inflation." He said
although it may be common practice elsewhere not to use
inflation-adjusted numbers, he wouldn't feel comfortable doing
that. He then explained that the base model ["NERA ALCAN 4"] was
made to compare with the other models; he pointed out the 100
percent equity and over-15-percent rate of return. He added, "We
have very similar costs, very similar prices, and ... I'm not
sure if we have exactly all their numbers on propane and such,
and they may or may not sell ethane." He then said:
If this is a comparison with the other projects on ...
an equal footing where propane and ethane are sold, and
... in some sort of proportion - not exactly
proportional to the size of the project, but in some
sort of comparable basis - then the "ALCAN 4" [has] got
the better numbers. It's got a 15.5; the ... port
authority had about a 14.5; and the YPC had about ... a
12 percent. So, in a comparison basis, with all
similar costs - similar way of adjusting for NGLs and
so on - the ALCAN 4 is about the best way.
Number 2060
CHAIRMAN TORGERSON inquired about the loss of oil [in the
calculations relating to gas].
DR. REYNOLDS answered:
We did not include the loss of oil. We are going ...
to try and include that right now. We had it included
previously, and it was very complicated to put in
because this is already a complicated model. We're
trying to model three different scenarios; actually, we
have many scenarios we could do, but we're trying to
focus on the three scenarios. And the problem with the
oil loss is, you'll have a small project versus a large
project, and you'll probably have low losses, large
losses, but it's not going to be proportional.
And a lot of the oil losses tend to happen later on in
the years, and so ... the effect on the rate of return
was very minimal; so we decided to take it out, and
we're thinking about putting it in - we're starting to
try and put it in again. But I don't think it's going
to make much difference, especially on the comparison
... of these. And I also believe that they're going to
mitigate those losses, and it's just a matter of how
much cost to mitigate them - more than the ... value of
the lost oil is the cost to mitigate, and, again, then
I'd have to have numbers from the producers on those
costs.
Number 2010
CHAIRMAN TORGERSON asked, "Just to be fair, because you said the
YPC has the lowest rate of return, ... isn't it because the port
authority has a higher volume - isn't that the primary reason?"
DR. REYNOLDS answered:
To be fair with the port authority, there's a couple of
things that you should be fair about with them. Number
one, ... we're ... doing larger amounts of propane and
ethane, and ... how much propane and ethane is
sustainable is a big issue; it's not been resolved, or
it's not officially resolved, and from what I hear,
it's not even resolved between the different producers.
So to be fair, theirs probably has a better chance ...
of sustaining the levels of propane and ethane.
The other thing is, because they have a smaller
project, they probably have less risk. A smaller
project is a little less risky than a larger project.
And, to be fair, even if they get a lower rate of
return, they probably would have a lower hurdle rate,
and, therefore, have possibly a little bit better
chance of succeeding.
Number 1964
CHAIRMAN TORGERSON turned attention to the interactive model [a
computer program whereby scenarios can be plugged in to produce
relevant numbers that are shown on the slide screen].
DR. REYNOLDS, using "the basic 4-bcf ALCAN," plugged in property-
tax incentives, using the assumption that during the construction
period of about four years, and for ten years afterwards, there
would be no property tax. He pointed out that there would be a
higher rate of return; whereas it had been 15.5, under this
scenario it would rise to almost 16.5. He suggested the need to
look at the rate of return, not the wellhead [price], because
there are differences of opinion on how the wellhead will work.
DR. REYNOLDS then plugged in numbers [relating to bond financing
through the ARRC]. Using 70/30 debt/equity, he said it will be a
little more complicated "than what we have" because there are
many different tax implications. "Roughly, you get almost a half
percent better rate of return ... on a railroad financing," he
said.
[There were other numbers plugged in, but the discussion on tape
wasn't clear without seeing the slide screen.]
DR. REYNOLDS remarked that the producers never do a comparison
with debt/equity; rather, they go with 100 percent equity. In
response to Chairman Torgerson, he said that if there is 100
percent equity, the railroad bond cannot be shown [in the
interactive model]; the only way to show that is if there is some
debt. He offered to show it with the property-tax incentive.
Plugging in numbers, he said, "We're at about a 15 percent rate
of return with 100 percent equity." He plugged in further
numbers and then said, "On an equity basis, which is what they
would normally do, you'd get at least a half percent better.
And, again, that could be the difference, depending on hurdle
rates and so on, between a good project and a bad project,
depending on their risk analysis."
Number 1695
DR. REYNOLDS asked his assistant to change the price in Alberta
[in the interactive model]. He said:
A 5 percent change in Chicago is about 15 cents - so
put $2.45. And it goes up a half percent. So no
matter how much we give to this project, a 5 percent
change in Chicago is probably going to be bigger than
what we can do in Alaska, incentivewise. And a 10
percent change in Chicago is going to be really big.
So, obviously, that price in Chicago - or whatever we
get in Alberta - is going to have a big effect.
CHAIRMAN TORGERSON asked if there were questions; none were
offered. He thanked Dr. Reynolds.
ADJOURNMENT
There being no further business before the committee, the Joint
Committee on Natural Gas Pipelines meeting was adjourned at
4:48 p.m.
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