Legislature(2001 - 2002)
02/13/2002 03:39 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
February 13, 2002
3:39 p.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Pete Kelly
Senator Johnny Ellis
SENATE MEMBERS ABSENT
Senator Rick Halford
HOUSE MEMBERS PRESENT
Representative Joe Green, Vice Chair
Representative Brian Porter
Representative Scott Ogan
HOUSE MEMBERS ABSENT
Representative John Davies
OTHER LEGISLATORS PRESENT
Senator Kim Elton
Senator Gary Wilken
Senator Ben Stevens
Senator Georgianna Lincoln
Senator Robin Taylor
Representative Beth Kerttula
Representative Eric Croft
COMMITTEE CALENDAR
Department of Revenue - Financial Participation in AK Natural Gas
Pipeline Study
Deputy Commissioner Larry Persily
Bill Garner, Investment Banking Firm of Petrie Parkman & Co.
(Houston)
Kevin Banks, Petroleum Analyst, Department of Natural
Resources
William Nebesky, Division of Oil and Gas, DNR
Department of Natural Resources - Gas Supply and Demand: Natural
Gas and NGL Value
ACTION NARRATIVE
TAPE 02-2, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural Gas
Pipelines meeting to order at 3:39 p.m. and announced the committee
would hear comments from the Department of Revenue and its
consultants on an ownership study of state financial participation
in the natural gas pipeline, something that was directed in SB 158.
MR. LARRY PERSILY, Deputy Commissioner, Department of Revenue
(DOR), thanked the committee for its confidence in the department's
abilities to assist them in this work. The department believes the
report it gave the committee a couple of weeks ago on state
financial participation in an Alaska natural gas pipeline is a
thorough desk reference on the history of gas line plans in Alaska,
the latest potential gas line projects, the potential sponsors, the
participants' financing, the investment risks and possible benefits
to the state.
MR. PERSILY briefed the committee on the conclusions regarding
direct state ownership, one of the key questions in the report by
saying:
First, as an owner, not as an investor and buying shares
in a corporation or as a financing authority, regardless
of the percentage of ownership, we believe the state
would need to come up with a 30% down payment and we
couldn't find any examples where you could get away with
borrowing anything more than 70% of your investment as an
owner in a gas line venture. Even if the state's
ownership stake was at 12.5%, which would be equal to the
royalty share of North Slope natural gas, that 30% down
payment would be $0.5 billion or so and we just don't see
where the state has that kind of cash sitting around and
available for appropriation - unless you wanted to take
it from the Permanent Fund, which would mean taking it
from the principal or taking it from the earnings reserve
account, which would jeopardize inflation proofing, the
dividends and the available of earnings to pay for public
services in the event the legislature were to decide to
use some of the Permanent Fund earnings to close the
budget gap. As for where you would get the other 70%, we
believe that could conflict with all the other demands
that exist on the state's bonding capacity unless you
count Permanent Fund earnings as available for debt
service. The state's available bonding capacity is just a
few hundred million dollars - assuming you want to remain
within the same guidelines we've used in the past to
maintain the state's high credit rating.
The other issue to consider as an owner in the gas line
business is what you would get for the money, because you
can be taking the risk and you're certainly going to be a
minority partner. We found the state just wouldn't get
much that it could not otherwise obtain in its role as a
landlord, taxing authority, and regulator of the gas
line. As a minority partner, the state would be sharing
in all of the risks the same as the majority owners, but
we would have much shallower pockets than Exxon or BP or
anyone else on the list to cover problems that might come
up. We would have little control over the operations as a
minority voice.
We believe the state could better influence the project
through statute, regulations, and permitting than putting
up cash and taking our chances. And as a minority
partner, we would be in the gas line business. Again,
this is as a partner at the table rather than as an
investor in a corporation with stocks or as financing.
Being in the gas line business is much different than
simply assisting in the financing of the project. Just as
being in business has its rewards, it also has its
financial risks, its demand on capital and the need for
expertise in running that business.
Finally, I'd like to say we could not see where the state
signing on as a partner would in any way help the gas
line get built any sooner. The market and the cost of the
project will determine when it gets built and not whether
the state is partner. Again, that is separate from
whether the state could help in financing the project for
others.
CHAIRMAN TORGERSON asked him who wrote the executive summary.
MR. PERSILY said he wrote the executive summary personally and the
consultants wrote the conclusions at the back of the report. He
maintained, "We felt the executive summary should come from the
commissioner's office and the conclusions should come from the
consultants, which in addition to Petrie Parkman included CH2M
Hill, which is a well known engineering firm. They helped us with
economic analysis and economic engineering on the project."
MR. BILL GARNER said he was with the investment-banking firm of
Petrie Parkman and Company in Houston and thanked members for the
opportunity to testify about the report. He told members:
I thought I would supplement the Department of Revenue's
testimony this afternoon with comments on the discussion
and conclusions within the sections of [the] SB 158
report that I worked upon. To refresh the committee's
recollection, my firm, Petrie Parkman and Co., is a full
service investment bank that solely focuses on services
to the oil and gas industry. The context of my remarks is
somewhat unique in that not only do I provide investment
banking advisory services on behalf of the firm, but
prior to my joining the firm, I spent 15 years as an
attorney and business executive with Kaen Energy, the
third largest interstate natural gas pipeline company in
North America. In my years with Kaen, I developed a
strong appreciation for the challenges and opportunities
associated with developing new natural gas pipelines.
Clearly, the construction of an Alaska natural gas
pipeline is vital to both the future economic growth of
Alaska and the security of energy supply to the United
States as a whole. The problem today, as it has been for
the past 30 years, is to balance those needs with the
practical realities of building the largest natural gas
pipeline project ever attempted in North America. The
risks for all stakeholders [are] great. As you know, as
part of this report last fall, we interviewed the then
known commercial developers of the gas pipeline project
to obtain their assessments of the project risks and how
these risks could be mitigated. The developers fell into
three main categories: first, the three major oil
producers; second, the natural gas pipeline group holding
the ANGTS certificate; and third, the other new gas
producer entrants on the North Slope such as Anadarko and
Alberta Energy that wanted to ensure access to whatever
gas line may be built.
We learned some interesting things during those
interviews. In an effort to mitigate risks, some of the
companies are seeking federal assistance through
legislative action that would provide economic benefits
or accelerated regulatory review, among other things.
With respect to the State of Alaska, however, the
companies were only in favor of an indirect state role in
the gas pipeline by the state providing, for example,
clarity on certain of the state's tax and royalty fiscal
terms, acceleration of state regulatory approvals and/or
for the state to somehow provide access to tax exempt
financing. They did not want the state as an equity
partner in the gas line project, although some would
reluctantly allow some form of minority participation if
the state forced the issue. They did not see state equity
involvement as assisting the project to get constructed
or constructed any sooner than planned. And several
companies saw state involvement as actually slowing the
project down. Finally, given the condition of global
financial markets, we learned that direct state funding
provided from taxable funds was not necessary. Many
companies already have sufficient funds available from
their current cash flow and the others saw no problem
with financing a project at favorable interest and upon
favorable terms that could be obtained from traditional
banking sources.
Despite the private companies' thoughts about state
involvement, the ultimate decision as to whether the
state should continue to pursue an equity stake in the
pipeline project rests with the executive and legislative
branches of the government. Some of the numerous
practical issues the state must wrestle with in
determining whether to proceed or not included the
following: the source of funds, the amount of investment
that the state may wish to make and its motivation for
doing so, which may not coincide with the role and
ownership percentage that may be offered by any of the
developer groups. Another point is the impact of the
amount and nature of the state's investment on the
state's credit rating. Another factor is how the state
would weigh its legal obligations to state citizens
through regulatory oversight and access to information
with the fiduciary obligations the state would have to
its private company equity partners to keep proprietary
information confidential and to act in a manner best
suited to the success of the joint venture. These
responsibilities may be irreconcilable at times.
Finally, another example would be how the state would
replace expected amounts and timing of revenue from the
gas line if the project were not constructed, it was
delayed or the project did not perform as forecasted due
to design defects or market conditions. These and the
other practical issues raised in sections 3, 5 and 8 of
the report are not easily answered.
Let's turn to the sources of state funds if the state
does decide to proceed with an investment or financial
participation in the gas line. As you know, this report
went into some detail regarding the potential source of
such funds including such sources as the general fund,
the Permanent Fund, the Earnings Reserve Account of the
Permanent Fund, the CBRF, general obligation bonds and
various types of revenue bonds. For various practical and
legal reasons, some of those sources are foreclosed. The
most viable source of funding probably would be through
the issuance of some form of a revenue bond through a
conduit of a state authority. The bonds probably could be
secured by shipper pay contracts. The difficulty,
however, today is that such revenue bonds would be
taxable under the current federal revenue code and the
companies likely could issue debt at the same or a lower
cost than the state. Nevertheless, if the state could
assist with issuing tax-exempt bonds, such issuance could
help the project's economic feasibility. I personally
have not been part of the Railroad Transfer Act
discussions, so I can offer no opinion about the
potential use of the tax-exempt funding mechanism within
that legislation.
If, however, tax-exempt financing could be made
available, there might be a strong interest by at least
some of the company developers in having access to these
funds. The interest rates on tax-exempt bonds would be
about 25% less than conventional taxable rates and
assuming the tax benefits were passed through, the
pipeline tariff could be lowered by perhaps 10%. Needless
to say, the availability of tax-exempt financing raises
complex tax securities and fiscal issues that will be
fact-specific to the particular financing plans of the
developers. If tax-exempt financing can be made
available, detailed discussions with the developers will
be required to gauge their interest and to determine how
it fits within their overall development scheme.
In summary, the financial and practical risks to all the
stakeholders in this project are material. Should the
state wish to pursue participation in the project, there
are practical and financial hurdles it must overcome, but
they are not necessarily insurmountable, just difficult.
3:55 p.m.
CHAIRMAN TORGERSON asked if, in his expert opinion, would the state
involvement in ownership of the pipeline enhance the project's
feasibility since his statement said that tax-exempt bonds would
move the project along, but he also stated that there is nothing
they can do to move the project along.
MR. PERSILY replied that they believe the state participation as a
part owner would do nothing to move the project along, but tax-
exempt financing would lower the rate the borrower has to pay on
the funds, which would lower the tariff and might help move the
project over the hurdle so someone would be willing to build it.
CHAIRMAN TORGERSON asked how much work they did on the port
authority issue.
MR. PERSILY replied that they spent a fair amount of time
discussing it, but didn't think it would make an appreciable
difference. There is a constitutional issue of whether a port
authority could exist as a political subdivision. He noted, "The
Alaska Constitution spells out what is a political subdivision
explicitly and it does not list port authorities."
CHAIRMAN TORGERSON said he didn't think the port authority was
being organized as a municipality and asked how he made that
connection.
MR. PERSILY replied, "Because it is not a municipality; it is not a
political subdivision, which…"
CHAIRMAN TORGESRON responded that it's owned by a municipality.
"So, it theoretically is a quasi-government arm of those three
entities that are creating it."
MR. PERSILY replied that argument could be made, but the
Constitution says "municipalities," it doesn't say port authorities
or transit authorities or airport authorities. Someone could make
the argument that it's formed by municipalities and it was the
intent of the Constitution, so it should be allowed.
CHAIRMAN TORGERSON said he thought the higher test was that it had
to have a public purpose, but it concerned distribution of the
profits back to the local governments. He asked if they had any
discussions with the IRS on the port authority idea.
MR. PERSILY replied that they hadn't.
CHAIRMAN TORGERSON asked if they had an opinion as to whether or
not the port authority's income was tax-exempt.
MR. PERSILY replied they relied on the opinion that the IRS gave to
the port authority, but there are some questions as to whether the
IRS had all the facts.
CHAIRMAN TORGERSON said he thought the department had an opinion
saying the state couldn't issue G.O. bonds.
MR. PERSILY said that they don't believe the state could issue G.O.
debt and if they could, it would be an intolerable risk.
MR. GARNER pointed out that the state would be pledging the full
faith and credit of the state behind that sort of funding
mechanism.
CHAIRMAN TORGERSON asked if he was part of the discussion on the
railroad tax-exempt bonds.
MR. GARNER replied that he thought the state would have to overcome
many hurdles to issue tax-exempt financing absent, but using the
Railroad Transfer Act is a whole other situation.
CHAIRMAN TORGERSON quoted page 5 through line 10 saying and read,
"The state would face formidable legal and practical hurdles to
financing a significant portion of the project with tax-exempt
financing."
He said that their statements don't necessarily fit with some of
the other statements they are hearing today.
MR. GARNER said he hadn't heard about the railroad possibility,
which might provide a clear exception to the existing federal tax
laws. It would be difficult to do without that.
CHAIRMAN TORGERSON asked Mr. Persily if it would be a good
investment for the Permanent Fund (not talking about large
withdrawals, but investing) and would such a large investment
violate the prudent investor oath.
MR. PERSILY asked if he meant as an active business partner rather
than just buying shares in a corporation.
CHAIRMAN TORGERSON said it would be targeted to the actual line.
MR. PERSILY replied that they believe investing a large sum from
the Permanent Fund would violate the prudent investor rule. He told
members, "For example, if we're 12.5% ownership of the line with
30% equity, that's $0.5 billion and would be 2% of the Permanent
Fund's market value and they don't have 2% invested in any one
activity.
CHAIRMAN TORGERSON asked if the producers sign on the dotted line,
which would happen no matter what happens if the state loans money,
aren't [they] the ones on the hook.
MR. PERSILY replied that they are on the hook, but there are risks
that the project would be delayed and there might be cost overruns
or a catastrophe that would stop the revenue flow.
CHAIRMAN TORGERSON asked if the risk wasn't borne more by the
producers than by the investors.
MR. PERSILY replied, "They [the producers] might as well own it
themselves, if they're going to take all the risks."
CHAIRMAN TORGERSON said he was integrating recent legislation that
puts the state in that position. He said, "Either the state's going
to do it through the railroad and it's a good thing and there's no
risk and if the state wants to do it somewhere over here, there's
high risk."
MR. PERSILY replied that the difference is that the state would be
an owner of part of the line as opposed to the railroad just being
a conduit. He explained, "Their name would be on the top of the
prospectus, but they would not be liable in any way for that debt."
SENATOR LINCOLN said she was flipping back and forth between the
conclusion and the summary to see if there were any glaring
differences between the two or if there were any disagreements the
department might have had with the conclusions.
MR. PERSILY said he wasn't aware of any glaring conflicts between
them.
MR. GARNER said he didn't recall any either.
CHAIRMAN TORGERSON said, if risk is a known factor, isn't it true
that the more investors there are the less risk there is per
investor. He questioned, "Why wouldn't it lower the risk?"
MR. GARNER replied that it lowers the risk for the individual
investors, but they are still putting forth their money and there
is a risk of the project functioning as forecasted.
MR. PERSILY said:
In terms of return on your investment, my understanding
of the way FERC sets rates is that investors are allowed
a return on their equity portion. So, I guess you're
saying you're guaranteed a profit of return on your
equity investment. All FERC will allow you on your debt
investment is a return adequate to cover the debt
service. Bill, correct me if I'm wrong, but if the state
borrows 70% of the money they need to invest in this
project, FERC will allow us enough to cover the interest
on the debt, but no profit or extra return to the state.
The only return we would get would be on the cash we take
out of our pockets.
MR. GARNER said that was correct, but FERC would allow the state
the opportunity to earn that amount of money so long as the project
functions as it was forecasted. He added, "If there is a problem
with the way the project works, you may not be allowed to earn that
rate of return as a practical matter."
MR. PERSILY clarified, "So, if you're looking for a return, you're
only going to get a return on the cash you take out of your pocket
to invest money you borrow. You just get enough to make the
mortgage payment."
MR. GARNER agreed.
SENATOR LINCOLN said what pops out at her is that the state
participation would do nothing to eliminate the risk, that the
potential companies simply do not need the state's money to build a
project.
She asked if they had the Alaska railroad bill before them prior to
writing the report, would the conclusion be different than what
they have today.
MR. PERSILY replied if producers, or whoever decides to build the
pipeline, used the railroad's tax-exempt financing that lowers the
cost of funds, which reduces the tariff they have to charge. This
means the project might pass their economic test. This risk is
certainly an issue. He explained:
If you're going to risk $15 billion, you want a higher
rate of return than if you're just risking $1 billion on
a smaller project somewhere else. The market is a
question. Four billion cubic feet per day or six billion
cubic feet per day is a lot of gas to bring into North
America regardless of projections. When that much gas
hits the market…You really can't ramp up a gas line
slowly as you would an oil line. When that much gas comes
into the market, depending on the market situation in
2008 or 2009, it could very well depress the price of
natural gas across the country.
He said it could very well lower the price on not just the Alaskan
gas, but of all the gas that a company is selling.
MR. GARNER added that there is no doubt in anyone's mind that
Alaska gas is needed in the Lower 48 in one form or the other. That
is an absolute given, but the problem is the timing. The other
factor is that this project is going to take a long time to get
built - a minimum of four years. He stated,
Hopefully, we won't wait too long to get this pipeline
built when the Lower 48 is going to be demanding the gas
for two years before it actually arrives. We'll just have
to see what people are forecasting when they put the
first shovel in the ground.
SENATOR WILKEN noted that item 5 on page 10 says that the
Constitution does not allow general obligation bonds to finance
state participation of joint business ventures. He asked if that
was a severely limiting constitutional prohibition and is it common
to see it in state constitutions.
MR. PERSILY answered that it would certainly prohibit G.O. bonds
and tax-exempt revenue bonds. Since Exxon, BP, Phillips and others
can obtain debt at a very low rate, if they can find debt at a
lower price, there is a value to having the state involved. Since a
G.O. bond is a full faith credit of the state, it makes sense that
there would be a constitutional prohibition against the state
pledging them for joint ventures with business since joint ventures
have not always returned good profit."
MR. GARNER said that many states prohibit the state government from
getting involved in private business except for certain economic
development projects. Some states are more severe than the State of
Alaska and some are less. Some states, for example, do not require
a vote of the citizens to issue G.O. bonds and other states, like
Alaska, do.
REPRESENTATIVE FATE asked if the state had an ownership (as in
partnership) position, would there be a reduction in the tariff.
MR. PERSILY said he didn't think so.
MR. GARNER responded that FERC sets the tariff for the project
irrespective of the investors. He added that tax-exempt financing
would result in a lowering of the debt cost and assuming that was
passed through, that would affect the tariff.
CHAIRMAN TORGERSON thanked them for joining the committee and said
the discussion was not over yet.
MR. KEVIN BANKS, Petroleum Analyst, Department of Natural Resources
(DNR), said he would talk first about their value study and used
projected slides. The purpose of it was to encapsulate what they
understand about the markets in the Lower 48 and what kinds of
drivers exist that will influence how the state should value its
royalty gas when it's produced. Page 3 shows a picture of the
natural gas suppliers in the U.S. He said that most of the
production occurs in the western Canadian sedimentary basin and the
Rockies. New supplies of gas will come from the Gulf of Mexico, the
Mackenzie Delta and the North Slope. There is room for new supplies
of gas, but in every instance those supplies come in only after
significant investment. He said that current supply from the
Rockies and Canada are in a decline.
The next slide shows consumption, which pretty much happens where
the gas is produced. He noted a large network of pipelines wherever
the gas is produced and significant storage areas around the
country in both the consuming and producing areas. This makes a
very active and flexible marketplace for gas, which produces
volatility.
TAPE 02-2, SIDE B
MR. BANKS said that NGL market is different than the dry gas
market. They recognize that gas shipped from Alaska will be
enriched with ethane and other gas liquids. The market for those
other liquids is significantly different from the natural gas
market. He informed them that the gas liquids are processed out of
natural gas fairly near the wellhead and can't be moved to market
until they are removed.
The processing plants will distribute these liquids either blended
or fractionated into component parts to just basically three market
centers - Alberta, Conway and Mont Bellvieu. This means that there
is a large market of purchasers of processing facilities. The
processors sell into a fairly restricted market. The folks who buy
those products are refineries and petrochemical plants that
represent an even smaller number of purchasers. The market funnels
down to fewer and fewer players. Figure 8 shows that one component
of NGLs is more valuable most of the time than the energy content.
This suggests that when valuing our royalty, we better make sure we
pay attention to this uplift. He noted, "It is perfectly reasonable
for the state in evaluating its royalty to try and capture some of
that value."
MR. BANKS told members the chart on page 10 shows some of the
problems about where they choose to calculate royalty:
Because of the royalty settlement agreements we now have,
because of the way we have interpreted them, our lease
contacts are calculated as a netback. That means what is
the destination value of the gas in this instance minus
the transportation and that should give us the value of
our gas on the North Slope at the wellhead. A lot depends
on where you make that destination value calculation.
He explained that sometimes the value of natural gas in Chicago is
higher than the value of it in Alberta and that is because, if it's
difficult to get it into Chicago, there would be a response in
Alberta to drive the price down.
If they choose to value the gas at Alberta, it could be a mistake,
because they have collected in an area that could get backed up
behind transportation constraints into the Lower 48. It may be that
there are transportation constraints for many of the participants
in that market, but not necessarily the Alaska producers. They may
find alternative routes or make commitments on transportation going
to Lower 48 markets either by building a bullet pipeline all the
way to Chicago or by buying substantially in existing pipelines or
by securing shipping on existing pipeline space.
MR. BANKS said the summary on pages 12 and 13 says:
As we move forward there is certainly compelling argument
that the state should try to arrive at some kind of
valuation agreement with producers to avoid the kind of
task that we had litigating oil for value. That
discussion and that negotiation certainly require that we
have a considerable amount of information and experience.
The producers need some time to get some experience with this
market place as well.
CHAIRMAN TORGERSON asked if he meant that gas is always more
expensive in Chicago than Alberta because of transportation costs.
MR. BANKS replied that would be the case.
CHAIRMAN TORGERSON asked what he thought the tariff was from
Alberta to Chicago.
MR. BANKS replied that he thought it was $0.80 - $1.00.
CHAIRMAN TORGERSON asked if everything above the $1.00 would be
the benefit we'd be losing if we chose the Alberta Hub.
MR. BANKS said that would be right.
CHAIRMAN TORGERSON thanked Mr. Banks for his comments.
MR. WILLIAM NEBESKY, Division of Oil and Gas, DNR, recognized that
one of the principal authors of the Alaska Natural Gas In-State
Demand Study was David Dismukes with the research firm, Econ One,
and he was also on the faculty of the Center for Energy Studies at
Louisiana State University. He noted:
Basically, the purpose of the study was to evaluate the
possibility for meeting Alaska's energy needs through
Alaska North Slope gas and that question is divided into
two parts: one is the potential in-state demand out there
today and in the future that a gas source from the North
Slope could serve - and then, secondly, what is the
ability of Alaska North Slope gas to meet that demand.
He said that looking at the demand was done two ways. First, they
looked at the existing baseline demand for gas in the state and
extrapolated how that demand would grow in the various segments
that make up that demand, which includes residential, commercial,
industrial and electric power generation.
The study used standard statistical extrapolation tools
to explore how baseline demand would grow based primarily
on assumptions that are consistent with the idea that the
past five years of growth and expansion will be the
underlying assumptions driving future demand. The study
looked at specific applications that would go beyond the
baseline and those include expanding residential service
into areas that are currently not served by natural gas -
looking also at our existing industrial applications and
what is the potential for those applications to expand.
Two final areas deal with electric power generation - one
called fuel switching and the other gas by wire.
He gave the committee a handout, which illustrated the overall
picture of the statistics. The first bar shows in the year 2000,
total in-state demand for gas was about 230 billion cubic feet per
year. It shows that demand would grow to about 360 billion cubic
feet of demand by the year 2020. So, there is roughly the
opportunity for a 60% increase in the current level of demand with
all the applications that were explored in the study. The State of
Alaska demand is about 1% of existing North American demand.
Existing usage of gas in Alaska is roughly about one-sixth of the
volume of gas that would flow through the gas line at a 4 bcf/d
throughput.
MR. NEBESKY highlighted another bar graph that shows most of the
current in-state demand centered in Southcentral Alaska and about
65% of the current in-state demand was generated by industrial
uses, consisting mostly of the Phillips Marathon LNG plant and the
Agrium Ammonia Urea plant, both in Kenai. Electric power uses about
15% and commercial and residential together use about 20%.
The potential for baseline growth from about 233 bcf is to increase
by about another 27 bcf across all the sectors, a fairly modest
potential for existing baseline usage to expand.
Page 3 of the study shows a map of the State of Alaska, which
identifies the local distribution utility companies that provide
gas service in various locations and the 340 settlements that make
up the state's population. There are five natural gas service
providers in the state. Right now three out of four households in
the state receive gas service. The potential to expand is into the
last 25%. He pointed out, "So, you could say on a statewide basis
right now, natural gas penetration rate is about 75% statewide."
MR. NEBESKY said that nine out of ten communities do not receive
gas service in the state. That illustrates there is only so much
potential to expand and most of the gas in the state is
concentrated in Southcentral.
To show the potential to expand into the residential sector, they
used a kind of geographic analysis called the Residential Proximity
Analysis, which explored geographically occupied households that
currently don't have access to gas service, but are relatively near
existing local distribution companies that do provide that service
and near where the Alaska Highway route would fall. They found (on
page 6) that there is potential in both the Interior region, which
increases from 5,000 - 8,000 households within a 20-mile zone that
could be potential customers for gas service. Similarly in the
Southcentral region, there's about 11,000 occupied households
within 20-miles of existing facilities. This is about 10% of the
existing 105,000 Enstar customers now.
The chart on page 7 shows an area graph of the various major
segments of gas usage in the state over time. Even the small amount
of residential usage has potential for a gas line to supply it. The
charts on the next two pages continue to illustrate potential for
expansion in the different segments. A large facility like
Netricity would use about 400 mcf/y of gas to generate the power to
run computers. This is close to the size of a small electric power
generation plant for a small community. That application doesn't
imply a lot of additional use of gas in the overall scheme of
things, but it is one to consider. They considered the gas usage of
a petrochemical facility similar to the proposal that Williams is
in the process of studying now.
MR. NEBESKY explained that on=page 9 they looked at two
applications that involved electric power generation. The first is
fuel switching where they compare the new applications to the
existing baseline usage. This application involves converting
existing coal and diesel driven power generation facilities into
natural gas power generating facilities. They have identified 20
power utilities in eight communities in the Interior region that
might have some proximity to the pipeline. Finally, the gas by wire
application is an idea where there is a central power station
located near the pipeline in a community like Fairbanks which is
gas-fired electric power generation and then the power is
distributed by wire into communities. That was the demand side of
the study.
The supply side of the study explores the potential for a gas line
to serve these kinds of demands. The chart on page 10 estimates the
cost of delivering natural gas to a residential or commercial user
in the Interior region (the greater Fairbanks area) taking into
account all of the transportation, all of the step-down meter
station costs in connecting to the gas line, depressurizing and
extracting liquids possibly, also the local distribution charges
for a local distribution gas line into the community, as well as
commodity cost for the gas itself. A couple key assumptions are a
tariff of $1 to get the gas from the North Slope to the meter
station in Fairbanks where it's taken off the gas line and used for
some local distribution application. A portion of the tariff on the
whole gas line is applied for that first 400-mile segment from the
North Slope to Fairbanks. The other key assumption is the commodity
costs of $1.91, which reflects the prevailing value of gas in the
Cook Inlet Basin that produces the gas to sell to electric and gas
service utilities.
MR. NEBESKY said they found that even in the case of a small
application to maybe 8,000 households that currently don't have
access to gas, but are within 20-miles of an existing local service
provider and the highway route, the study shows that gas could be
delivered to those retail users for about $5.87. This result is
somewhat encouraging because the graph on page 11 shows delivered
cost and penetration rates.
If 80% of the households hook up and all the other
assumptions built into the cost side are satisfied, then
that indicates the delivered cost. But as we move down,
in terms of the proportion of households that hook up
(penetration rate), we see that the delivered cost rises
more steeply as we move toward lower rates of
penetration.
Fairbanks Natural Gas Utility serves 400 customers or about 1% of
the occupied households in the greater Fairbanks area. It provides
gas to its customers at about $8 mcf. This gas is shipped in the
Enstar system and liquefied at a small facility at Pt. Mackenzie
and trucked up the Parks Highway to Fairbanks. Tapping the gas line
and providing gas by that mechanism, if penetration rates could
exceed 30%, that system could compete with the existing shipage of
gas from Southcentral.
Most Interior residents heat with heating fuel and by comparison
the mcf equivalent cost of heating your home in the Interior at
$1.23 per gallon is $10 - $12 mcf. It wouldn't take very much
penetration into those occupied households to compete with the
heating fuel alternative.
MR. NEBESKY said the chart on page 13 looks at prices in Cook Inlet
Basin, which has enjoyed a long history of excess supply of gas.
Both industrial and residential gas has had relatively inexpensive
costs. Today Anchorage residents pay about $4.27 mcf. The forecast
going forward into the future is based on the Department of
Energy's most recent forecast of gas prices with adjustments to the
Henry Hub. He explained:
Pricing in the Cook Inlet Basin as evidenced by this new
Unocal Enstar contract, which will provide service
beginning in 2004 are going up. There's some recognition
in the market place to the looming potential demand and
supply in the Cook Inlet Basin.
Another chart shows that in 2005 there is an imbalance between
demand and supply. This makes the assumption the energy prices
remain the same as they have been in recent history. They see a
shortfall in the supply and a steady gradual increase in demand.
MR. NEBESKY said assuming an additional 1 tcf of reserves coming
into service around 2004 in the Cook Inlet Basin is a very
reasonable assumption considering the stepped up exploration
activity and the studies that explored reserves in great detail
(connected with the last go-round for the LNG plant export license
extension in 1996 and 1997). Therefore, the imbalance is delayed
until the year 2009 or 2010. But, it doesn't go away with the
addition of 1 tcf of gas. If the LNG plant does not receive a
renewal for continued LNG exports beyond 2009, when the current
license expires, there will be a significant reduction in demand,
but even then the imbalance between demand and supply isn't erased
entirely. It's just further out in time.
The study also explored to what extent gas from the North Slope
could interface with the demand supply balance in the Cook Inlet
Basin. The results were somewhat encouraging. For example, on a 16-
inch pipeline, the unit cost would fall from $3 mcf at 10 bcf/y to
less than $1 once there is more than 40 bcf/y.
MR. NEBESKY said a number of assumptions were behind the capital
cost for the lateral spur line that connects Fairbanks and
Anchorage drawing heavily from a study by Stone and Webster Co. (in
connection with the Susitna Hydro project in 1989). They gave it a
25-year life, assumed a 10% regulated rate of return, which is
consistent with the rules of thumb that experts use in designing
pipelines. It might not answer all of the Cook Inlet imbalance
questions, but for a lateral line to meet the cost that meets an
economic curve that might convince an investor to invest in this
line, you would need to get 30 - 40 bcf/y. All the applications
they looked at and studied would not be enough to bring those
volumes up to 30 - 40 bcf/y. If there is not sufficient replacement
to cover all the imbalance, that might speak well for the lateral
spur line coming out of Fairbanks sometime in the next decade.
CHAIRMAN TORGERSON asked if his assumptions were identified.
MR. NEBESKY said they were.
CHAIRMAN TORGERSON asked who developed the assumptions on the
capital costs for Fairbanks.
MR. NEBESKY said he had help from Williams and Econ One Research.
He said they used a high-pressure dense phase gas line, stepping
that down into some kind of local system.
REPRESENTATIVE GREEN asked, regarding the slide on page 17, how far
out would a bigger line have to go to achieve economies of scale.
He thought that should happen somewhere in the future or they
should be building a smaller line.
MR. NEBESKY replied that was a good question and the answer is that
the volumes on the graph don't go far enough to the right. A 16-
inch pipeline is more than capable of handling 40 - 100 bcf.
TAPE 02-3, SIDE A
MR. NEBESKY said if the charts went more to the right, they would
begin to curve up at different rates. The green curve representing
the 24-inch pipeline would probably continue to decline while the
blue and red curves started to turn up steeply.
CHAIRMAN TORGERSON thanked everyone for their presentations and
adjourned the meeting at 5:18 p.m.
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