Legislature(2013 - 2014)BARNES 124
03/24/2014 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB138 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 138 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
SB 138-GAS PIPELINE; AGDC; OIL & GAS PROD. TAX
1:14:43 PM
CO-CHAIR FEIGE announced that the only order of business is CS
FOR SENATE BILL NO. 138(FIN) am, "An Act relating to the
purposes, powers, and duties of the Alaska Gasline Development
Corporation; relating to an in-state natural gas pipeline, an
Alaska liquefied natural gas project, and associated funds;
requiring state agencies and other entities to expedite reviews
and actions related to natural gas pipelines and projects;
relating to the authorities and duties of the commissioner of
natural resources relating to a North Slope natural gas project,
oil and gas and gas only leases, and royalty gas and other gas
received by the state including gas received as payment for the
production tax on gas; relating to the tax on oil and gas
production, on oil production, and on gas production; relating
to the duties of the commissioner of revenue relating to a North
Slope natural gas project and gas received as payment for tax;
relating to confidential information and public record status of
information provided to or in the custody of the Department of
Natural Resources and the Department of Revenue; relating to
apportionment factors of the Alaska Net Income Tax Act; amending
the definition of gross value at the 'point of production' for
gas for purposes of the oil and gas production tax; clarifying
that the exploration incentive credit, the oil or gas producer
education credit, and the film production tax credit may not be
taken against the gas production tax paid in gas; relating to
the oil or gas producer education credit; requesting the
governor to establish an interim advisory board to advise the
governor on municipal involvement in a North Slope natural gas
project; relating to the development of a plan by the Alaska
Energy Authority for developing infrastructure to deliver
affordable energy to areas of the state that will not have
direct access to a North Slope natural gas pipeline and a
recommendation of a funding source for energy infrastructure
development; establishing the Alaska affordable energy fund;
requiring the commissioner of revenue to develop a plan and
suggest legislation for municipalities, regional corporations,
and residents of the state to acquire ownership interests in a
North Slope natural gas pipeline project; making conforming
amendments; and providing for an effective date."
CO-CHAIR FEIGE noted that the legislature's consultants from
enalytica are providing a presentation regarding the proposed
Alaska Liquefied Natural Gas (LNG) Project.
1:15:03 PM
NIKOS TSAFOS, Partner, Energy Consultant, enalytica, said he
will be talking today about existing project structure versus
alternative project structures, financing options available to
the state, cash in and cash out as regards how much the state
will be paying and what the state can expect to get in return,
and the midstream [portion of the project]. Addressing slide 4,
"Executive Summary," Mr. Tsafos said there is enormous variation
in structure when looking around the world at how other LNG
projects are structured. Regarding Alaska's circumstances, the
current [proposed] structure has a great deal of merit.
Regarding the financing plan, Alaska would be responsible for
paying its share of the investment. Where that money would come
from is currently unknown, but there are various options
available to the state. Regarding the modeling of various
structures, enalytica ran an economic case as well as a stress
case to quantify what would happen if things went wrong. He
cautioned that the stress case he will present is a negative,
but not catastrophic, scenario; he therefore asked members to
please not take this model as the worst that could happen.
Useful in this stress case is that it reiterates a message
enalytica has presented, which is that LNG projects usually do
not lose money, rather they may not make as much money as would
be liked.
1:18:34 PM
MR. TSAFOS continued addressing slide 4, saying the Memorandum
of Understanding (MOU) between the state and TransCanada makes
sense when it is assumed the state is capital constrained.
Given this assumption, it makes sense to focus the state's
money, as is done under [CSSB 138(FIN) am], on the liquefaction
and foregoing some of the participation in the pipeline and gas
treatment plant (GTP). Regarding the tariff - TransCanada's
charge to the state for the state's participation - the tariff
is expensive when compared to a loan because the state could
probably borrow money for a lower rate. However, the tariff is
attractive in terms of what tariffs are generally in the
marketplace. There are two ways to judge this. The first is
how much it would cost the state if it undertook the project by
itself. The second is the tariff cost charged to the state if
it were to find a different partner. Regarding the money that
will be generated by this project, TransCanada will receive
between 1 and 7 percent of the total return, depending on price
and whether [the state exercises its buyback option]. Regarding
the finer points of the MOU, the risk allocation is something
worth focusing on.
1:21:31 PM
MR. TSAFOS turned to slide 5, "Proposed Project Structure Has
Lots of Merit," and reminded members of their previous request
for a review of other project structuring possibilities besides
that proposed under CSSB 138(FIN) am. He noted there are four
pieces to the project: the upstream, which is gas in the
ground; the treatment plant, which purifies the gas; the
pipeline, which is 800 miles long and goes to Nikiski; and the
liquefaction facility, which liquefies the gas for transport on
ships. Of the options listed under each of the four pieces, the
ones highlighted in grey represent those [proposed under the
bill]. A project could be created by combining one item from
each of the four pieces/columns. Any of the options listed for
each piece could be selected and combined to create a project.
Some of those combinations probably do not exist in the world
today, but most of the combinations would have an example of a
project somewhere in the world that is structured in that way.
1:23:39 PM
MR. TSAFOS reviewed the various options for structure listed for
each of the four components of the project. Under the upstream
component, one option is for the oil companies to own and
produce the gas with the State of Alaska (SOA) participating
through royalty and taxes. This option is the status quo, or
in-value, world. Another option is for the oil companies to own
a share of the fields, but the state becomes a partner. In this
option, the state owns a share of the asset instead of, or in
addition to, being a royalty or taxing authority. Usually this
would happen at the beginning of the process, so this would have
been a good discussion to have in the mid-1960s. When looking
at LNG projects around the world, usually a sovereign becomes a
partner from the beginning of the lease or the concession term.
In today's world, the option would be for the state to buy into
the field. The last option is where there are no oil companies
and the state fully acquires the upstream. There are places in
the world where this happens, usually when the state
nationalizes and becomes a 100 percent owner of the asset.
There are places where the state is 100 percent owner for assets
that have yet to be leased committed to a lease.
1:25:32 PM
MR. TSAFOS noted that all of the structure options listed for
the gas treatment plant, pipeline, and liquefaction components
are the same. He said the structure chosen for each of these
three components may or may not be the same as that chosen for
the other two components. One option is the oil companies own
100 percent of the assets. A second option is that the oil
companies and the state own the asset, which is what is
envisioned in the Heads of Agreement (HOA). A third option is
for the oil companies plus the state plus a third party. A
fourth option is the oil companies plus a third party. These
last two options are the worlds envisioned by the MOU and the
HOA together. A fifth option is the state being 100 percent
owner. A sixth option is the state and a third party. The last
option is for a third party being 100 percent owner, which was
the beginning structure for the project under the Alaska Gasline
Inducement Act (AGIA) until one of the oil companies joined into
that process. The options highlighted in grey are the structure
options chosen under the HOA and the MOU [as well as in CSSB
138(FIN) am].
1:27:22 PM
MR. TSAFOS described each of the structure options on slide 5.
Regarding the options listed under the upstream component, he
said the proposal [under CSSB 138(FIN) am] for the state to move
from in-value to in-kind, or the idea of the state taking
physical ownership of the gas, is between the first option where
the oil companies own and produce the gas with the State of
Alaska (SOA) participating through royalty and taxes and the
second option where the oil companies and the state become
partners. This is because the state is in some ways a partner
since it is responsible for some of the cost through the tax
system and because the state is entitled to some of the gas.
Thus, in some ways, the state is becoming a partner by virtue of
its gas entitlement. Regarding the third option under upstream,
he said expropriation, while a path open to the state, might be
too harsh. The drawbacks to this option are the amount of money
the state would have to pay upfront and the state having to
learn how to run this massive asset on its own.
1:28:55 PM
MR. TSAFOS addressed the options for structure under the gas
treatment, pipeline, and liquefaction components, conjecturing
that he does not need to say much about why the state would not
want the oil companies to own 100 percent. If the state had an
asset where this was the only gas around, it might not be a bad
structure; but, if the state is looking to develop an
infrastructure that should be open to others and to incentivize
the development of additional gas, this structure poses some
challenges. Regarding a structure of 100 percent state, he said
there is merit to this in terms of the state's ability to create
an open access pipeline network. The challenge to that
structure would be chiefly financial given the [estimated total
project cost of $45-$65 billion]. Regarding a structure of the
state with a third party, he said there are places where that
happens but it generally does not happen because it is very
difficult for someone to come in and make that big investment
without also having that visibility on the upstream as it is
difficult to coordinate and integrate with the upstream.
Regarding a structure of 100 percent ownership by a third party,
he said it would have the same problems as with the option of
the state and a third party.
1:31:11 PM
MR. TSAFOS said what comes across when looking at this structure
is the integration benefits of having one company see through
the entire chain, with the benefit of that infrastructure not
being exclusive. One example was brought up during the [2/4/14]
presentation by Steve Butt, Senior Project Manager of the Alaska
LNG Project for ExxonMobil Development. In his presentation,
Mr. Butt stated that during the AGIA process the thought was
that there would be four trains at the gas treatment plant.
However, once [all of the producers] were brought together and
there was access to all the data information across the entire
chain, it was found that three trains would be the optimum
number. When looking at the structure highlighted in grey
representing the MOU and HOA, it is seen that there is a lot of
merit in avoiding the pitfalls of an oil company-only asset, but
gaining the benefit of having the oil companies involved to gain
efficiencies across the entire value chain.
1:33:18 PM
MR. TSAFOS brought attention to the difference in structure
between the liquefaction component and the pipeline and gas
treatment plant components as proposed by the MOU and HOA. He
said this difference makes sense in that the state's primary
interest is to ensure that if someone develops more gas, this
gas can be delivered by putting it through the pipeline. That
structure really needs a third party for the gas treatment plant
and the pipeline. However, for the liquefaction facility, an
entity finding enough gas to expand the liquefaction facility
could take on the task of building that additional capacity. A
third party owner in the liquefaction would not be as critical
as for the pipeline. Similar ownership between the pipeline and
liquefaction is unnecessary because liquefaction is the building
of a parallel facility at the same location, so the same
ownership that allows open access to the infrastructure is not
needed.
1:34:43 PM
REPRESENTATIVE KAWASAKI related it has been argued that under
state ownership there is better transparency when it comes to
negotiating. He read a statement by a legislative consultant,
Roger Marks: "It is possible that any partnership with private
parties who generally operate with greater confidentiality than
public entities could limit transparency." He requested that
enalytica address this statement, adding that Mr. Marks made
this statement under the "ownership section dealing with whether
state ownership is a good thing or not."
JANEK MAYER, Partner, Energy Consultant, enalytica, replied
there are two different considerations. There is the question
of transparency toward the state's administration, and
transparency beyond the administration to the legislature and to
the general public. It is difficult not to think that the state
as an active participant does not radically increase
transparency toward the executive branch because it is an
investor in this project and is making key decisions along with
the other members and therefore has access to all that
information. His impression from the aforementioned quote is
that the argument being made is that the state is being brought
in to private participation in a private project, and it may no
longer have the same impetus to disclose everything to the
legislature or the public, which, he allowed, may be true. He
said he thinks CSSB 138(FIN) am goes a long way in terms of this
initial contract negotiation process and how that will be
handled in terms of both things that need to be maintained as
confidential through that process and then an eventual public
process for approval or disapproval of the contracts that are
negotiated. But, if core interest of the state is in
understanding the details of the project so that its financial
interest is protected, it seems to him it is hard not to think
that that is addressed by participation, whether or not that
means that all the details are suddenly open to the public.
1:38:22 PM
REPRESENTATIVE HAWKER pointed out that missing from the chart on
slide 5 are the transmission lines from the Point Thomson and
Prudhoe Bay fields to the treatment plant, which in the HOA are
carved out for special treatment. He asked whether the
transmission lines are a relevant consideration in this chart,
recognizing that upstream is defined differently in this project
than in the past.
MR. TSAFOS responded enalytica did not include the transmission
lines in this chart because they were not thought relevant.
Whether the transmission lines are considered upstream or gas
treatment matters for taxation, but does not matter in the
broader structure of the project.
1:39:39 PM
REPRESENTATIVE HAWKER took issue with the statement that the
transmission lines are relevant to taxation but not in the
broader perspective, saying it is not a congruent statement as
taxation is a big issue for the state.
MR. TSAFOS answered that it classifies the lease expenditure
that is deductible for the upstream and it also defines the
point of production. Agreeing it is important, he qualified
that it is not important in terms of how that structure is
thought about. Where exactly the split is between each
column/component is quite important in how the pass is made from
one column to the other. Enalytica did not include an
additional piece as it is either part of the upstream or part of
the treatment plant in terms of an LNG project structure.
Rarely is there another party that comes in to just do the
pipeline from the upstream to the treatment plant, and that is
the context in which he meant the transmission lines are not
important to the structure. He agreed it is important to the
economics in how the state's share is calculated and how lease
expenditures are calculated. Because enalytica thought that the
transmission lines will be part of either the first or second
column, it was thought unnecessary to have an additional column
for them.
1:41:22 PM
REPRESENTATIVE HAWKER appreciated the difficulty of simplifying
a very complex project into a chart, saying an inherent danger
of simplification is that it provides the appearance that the
chart is an exclusive list of options. Drawing attention to the
statement on slide 5, "Possible Project Structures based on
Ownership," he expressed concern that ownership and control are
not equal. Both have merits and when the gives and the gets
come to the contract that is established, ownership and control
can be managed through the relationship. Saying slide 5 is
purely an ownership analysis, he queried whether the state
should be concerned about control in addition to ownership or
whether control is not an issue for enalytica.
MR. TSAFOS, in regard to the dangers of trying to simplify the
complex, replied that enalytica could show this ownership in
terms of what it entitles the state to in terms of capacity
rights and control. Speaking to the question of control, with
the state as a minority partner, he noted the question of how
much control 20 or 25 percent [ownership] gives the state, and
against what. When compared against zero, the state probably
has quite a bit more control, but at the same time it does not
have a majority share. It is important to understand that if
this proposed legislation passes the state will spend the next
year developing joint venture agreements and setting up the
corporate structure for this project. In that corporate
structure, one of the things that will be defined is the kind of
agreement the different decisions require. As with any company,
some can be passed with a majority vote, some need two-thirds,
and still others need unanimous consent.
MR. TSAFOS hypothesized that major decisions [for the Alaska LNG
Project], such as whether to go to Front-End Engineering and
Design (FEED) and authorize the next $1-$2 billion, or whether
to construct the project, will most likely require unanimous
consent. Looking at projects around the world, when companies
are not interested or unwilling to move something forward, the
project either completely slows down or the companies leave.
Qualifying that this does not mean it has not happened, he said
he cannot think of an example where 51 percent of the ownership
of an LNG project decided to go ahead with the project, while 49
percent did not want to. He allowed this does not protect
against all sorts of decisions. As a minority owner, there will
be decisions in which the state is on the losing side. When
looking at the joint venture agreements, it is crucial to
understand exactly what those decisions are. The administration
will negotiate those agreements and in some things the state
will only have 25 percent veto power and in some things the
state will have no veto power. There will be many times the
state will not care to have veto power, such as more technical
or operational aspects, whereas the operators might care a great
deal.
MR. TSAFOS, continuing his response, said that the State of
Alaska will likely be the second largest owner with 25 percent
and ExxonMobil will likely have a bit more than 25 percent.
Based on his experience, he cautioned committee members not to
assume that the oil companies will always agree with one another
or will always sit on the same side on any given issue.
1:47:49 PM
REPRESENTATIVE HAWKER agreed with the aforementioned analysis by
Mr. Tsafos. He said the state should try to anticipate and
identify every one of its conceivable concerns and write them
into the joint venture and limited partnership agreements,
saying that regardless of ownership the state has the right of
refusal. He added he is trying to keep in mind the concept that
this project is a pipe within a pipe. Although Mr. Tsafos said
that the state owns 25 percent of this project, he argued, that
it is not really ownership as it is within a limited liability
partnership that the state does not control, and therein lays
his concern because those different issues must be anticipated
and dealt with. He noted the legislature has no say in how
those issues get resolved.
MR. TSAFOS answered that the state has a 25 percent share in the
liquefaction, whereas, in the pipeline and the gas treatment
plant, the state's share comes through TransCanada.
REPRESENTATIVE HAWKER clarified he is talking about the pipeline
and the gas treatment plant.
MR. TSAFOS agreed with Representative Hawker in that it must be
seen how that agreement is structured. He said enalytica's
understanding is that the intention of this structuring is to
ensure that TransCanada and the state participate as a 25
percent owner as opposed to having one company own 15 percent
and another company own 10 percent. Whether that is a wise
decision depends on the level of control and influence that the
state will have in that joint venture and he does not think that
is known yet. Thus, it will be well worth looking out for this
when these agreements come back [to the legislature].
1:51:00 PM
REPRESENTATIVE TARR asked whether it would have been premature
to expect some of those major decisions to have been outlined in
the Heads of Agreement (HOA), thereby providing comfort to the
legislators.
MR. TSAFOS offered his understanding that the MOU had some
language to that effect.
REPRESENTATIVE HAWKER confirmed that it does.
REPRESENTATIVE TARR pointed out the MOU is the state's alignment
with TransCanada, while the HOA is the alignment with all the
partners.
MR. MAYER responded that it was probably premature. He said the
HOA does not commit the state to take gas in-kind or to have an
equity share; rather, the HOA sets a vision where, if
satisfactory agreements can be reached, this will happen. The
question of satisfactory agreements is integral as it answers
the question of what the state has control of and veto over, as
well as an endless array of other issues.
1:52:43 PM
REPRESENTATIVE TARR said it would be instructive to consider
whether language should be included in the bill to have the
force of law for expectations that would be used to work on
those joint venture agreements. She remarked that the timeline
is an issue given "how little control we might have once the
enabling legislation goes forward" because "at that point we
would no longer be the negotiator ... we would be hoping that
the deal was negotiated in the best possible way on our behalf
... and then eventually come back, but we would not actually be
able to participate in that way."
MR. MAYER concurred, saying the aforementioned points out why it
is so important the legislature be clear about, and have
confidence in, this process of executive session briefings with
the administration as these contracts are being negotiated.
Additionally, the legislature must have confidence that these
are going to happen on a regular basis and will have the full
degree of transparency needed to understand what is being
contemplated and what might be traded off, and provide an
adequate opportunity to say "do not go here because ... going
there would fundamentally jeopardize the ability for us to
approve this when it actually comes back to us." Without that,
he continued, it seems the legislature does face an up or down
vote, and cannot have confidence. The process of executive
session briefings is so critical and one that the legislature
needs to have full confidence in.
1:54:54 PM
REPRESENTATIVE HAWKER drew attention to the MOU, Exhibit B, page
1, Alaska LNG Project Equity Option Term Sheet, item 3, which is
the area of the document being talked about and which reads
[original punctuation provided]:
The Limited Partnership Agreement would provide that
TADI [TransCanada Alaska Development, Inc.] or its
Affiliate would own 100% of the general partner of the
Limited Partnership, and such general partner would
hold a minimal (less than 1%) interest in the Limited
Partnership. The General Partner would make all
decisions on behalf of the Limited Partnership,
provided that the Equity Option Agreement will provide
that certain fundamental decisions (e.g. change to
distribution policy, winding-up of Limited
Partnership, sale of significant interest of Limited
Partnership in AK LNG) could not be made without the
approval of the Optionee (before the option is
exercised) or the Limited Partner (after the option is
exercised). The General Partner would be entitled to
recover all of its reasonable direct and indirect
costs that are associated with it acting as the
general partner.
REPRESENTATIVE HAWKER noted that, basically, there are words in
the aforementioned that say the State of Alaska. He expressed
his concern that those are very vague descriptions of the kind
of control that would be put in place through the contractual
relationship. Regarding an up or down vote, he said it is
important to remember that the legislature passes enabling
legislation that empowers the administration to go forward and
ink the document that inherently involves the Equity Option Term
Sheet, which does not come back to the legislature for approval.
The legislature is proceeding in good faith that the
administration get it right for the next 50 years, a concern he
struggles with in this whole process.
1:57:20 PM
REPRESENTATIVE KAWASAKI recalled discussion about the difference
between ownership and control. He said his concern with the
state becoming a part owner or junior partner in a pipeline is
for how that balances out with the state being a sovereign, a
taxing authority, and a regulator, the state's current role. He
asked whether there are examples of similar situations.
MR. TSAFOS replied that the typical case in the world of LNG is
for the state to be an owner in the project rather than not.
Most LNG projects "out there" have a sovereign as a full equity
partner all the way from the investment to marketing that gas.
However, when a state wears multiple hats things can sometimes
get confusing and difficult. In his experience working with
national oil companies, he related, it sometimes becomes
difficult to separate the company functions from the sovereign
functions and sometimes national oil companies act as regulators
or as the authority that grants the leases. So, in some ways, a
national company can be thought of as encompassing four or five
of the State of Alaska's departments or functions within those
departments. The lesson is that things can be structured in a
good way that delineates the responsibilities of the state-owned
enterprises, the responsibilities of the regulators, and the
relationship between them. It is important to sketch that out
in the proper way, but this is by no means a conundrum. It is
typical for states to be both regulators and part owners in the
resource.
1:59:53 PM
REPRESENTATIVE KAWASAKI requested specific examples.
MR. TSAFOS answered oil examples include Brazil and Venezuela,
and LNG examples include Qatar, Algeria, United Arab Emirates,
Indonesia, Russia, and Yemen.
REPRESENTATIVE KAWASAKI maintained the aforementioned examples
are different because they are state-owned oil companies that
are partners. He queried whether there are examples where the
state does not own its own oil company and oil company interest
so that it is more similar to what is proposed for the Alaska
LNG Project.
MR. MAYER responded there are plenty of examples of states that
either did not have a large or any national oil company at the
outset. They typical situation is still one of participation
through a national oil company even if it is a fledgling
national oil company that is sometimes referred to as a purse
box national oil company, which is a place to mail checks to.
The bill before the committee is also a corporate entity of the
State of Alaska which would participate and, in that sense, is
no different in some ways to a fledgling national oil company in
another jurisdiction. There is one part of this that is unique
to Alaska, as far as he is aware, and that is the question of
creating the equivalent of an equity share of the gas itself by
taking the royalty and the tax in-kind and turning that into a
state profit share. In that sense, Alaska is already used to
relatively unique, hybrid models. For instance, the profit-
based production tax laid on top of royalty is a hybrid in its
own way. This comes from the state wanting to be a more active
participant in its resource, but coming from a general U.S.
framework that is one of private ownership and a much less
involved role of the state. The basic foundation here of leases
and all the rest, and the way this foundation is written is not
one in which the state naturally has an equity stake in the
upstream and other things. The unique component of the Alaska
LNG Project is its construction of royalty and production tax
in-kind to create an equity share for the state. The broader
point of equity participation in a project is the norm rather
than the exception.
2:03:44 PM
MR. TSAFOS returned to his presentation, addressing slide 6,
"Various Financing Options Open to LNG Projects." Qualifying
that this is again a simplification, he said there are two ways
to finance a project of this type: balance sheet financing and
project financing. Under balance sheet financing, the project
sponsors provide funds. For example, each part-owner could put
down the same percentage as its ownership, creating a pool of
money for building the project. These funds can combine debt as
well as cash flow, so when one party puts down, say, $10
billion, that money could be both revenues as well as debt that
was raised. The ultimate guarantee comes from the project
sponsor and the sponsor's balance sheet. It comes down to faith
in the project sponsor, the company that is putting in the
money, and the faith that that company will pay its debts. This
type of financing is easier if all the parties have great
balance sheets. Under project financing, third parties lend
money to the project directly, not to the sponsors. In this
case, money would be loaned to the Alaska LNG Project, not to
ExxonMobil, BP, Conoco, and the State of Alaska. The project
would get some equity; for example, the project could be
capitalized with 30 percent equity from the pockets of the
sponsors, with the rest borrowed by the Alaska LNG Project.
Crucial is that the guarantee for the debt is the project
revenues, not the project sponsor. The difference between the
two options is that with balance sheet finance the ultimate
guarantor is the project sponsor and with project finance it is
the revenues of the project. Because of that, the rate for
project finance depends on risk of the project and, in
particular, the risk of the people who are promising to pay back
the money. This form of finance is attractive because it is
easier to accommodate riskier sponsors. For example, when an
LNG project was being done in Qatar in the mid-1990s and the
State of Qatar was bankrupt, a lender may not have wanted to
loan money to the State of Qatar, but the lender may have wanted
to loan money to a project being led by ExxonMobil in which the
State of Qatar was a partner and the revenue was guaranteed by
the Japanese utility that had promised to buy gas from that
project. In the case of the Alaska LNG Project, the financial
strength of the state's partners is probably not at the top of
the list.
2:09:42 PM
MR. TSAFOS, continuing his discussion of financing options, said
it was important to keep the distinction between the two in mind
because project finance is non-recourse debt, so the bank can
only take the asset, which, from an accounting perspective,
allows a project sponsor to not have that asset on its balance
sheet. In thinking about debt specifically for the Alaska LNG
Project, project financing would make a difference for the
state's credit ratings, its debt numbers. Under balance sheet
finance for the Alaska LNG Project, the State of Alaska would
borrow money or take money from taxes to put into the project,
while under project finance it would be the Alaska LNG Project
that is borrowing the money. This is an important distinction
when looking at the key questions for the State of Alaska.
These have not yet been answered and should not be answered
until the details are clear. The first key question is the mix
of debt and equity. In the case of Alaska, equity means
carrying revenue that the state has. The second key question is
whether the debt will be specific to the LNG project or part of
the broader state balance sheet liability. The third key
question, if the state puts in equity, is where that equity will
come from. This is linked to the fourth question which is
whether the permanent fund could put in money and, if it does,
where does the money go when it comes out. Whichever path the
state chooses, there is a precedent as there are projects that
do balance sheet finance and there are projects that do project
finance.
2:12:05 PM
MR. TSAFOS moved to slide 7, "Project Finance Well Established
in LNG," emphasizing that project finance is an extremely well
established principle and practice in the world of LNG. He
noted slide 7 provides a list of recent examples of LNG projects
that have secured third party financing. Alaskans may think
that no matter what other projects exist Alaska's project is
going to be bigger than anyone has ever seen and therefore this
type of financing does not apply to Alaska, although it does.
For example, Ichthys [in Northern Australia] raised $20 billion
in third party financing which came from the Japan Bank of
International Cooperation (JBIC), the Korean and Australian
export and import banks, commercial banks, and the project
sponsors. Papua New Guinea, a project in which ExxonMobil is a
partner, took $14 billion in third party financing. Australia
Pacific LNG, a ConocoPhillips project, [took $5.8 billion in
third party financing]. The Tangguh project in Indonesia, a BP
project, [took $3.5 billion in third party financing]. This
list of projects shows that all three of the Alaska LNG Project
partners have quite a bit of experience with third party
financing. A benefit of project financing is that financing
from sovereigns, credit agencies, and multilateral banks tends
to be quite competitive relative to commercial bank rates.
2:14:11 PM
REPRESENTATIVE HAWKER, regarding the absoluteness of statements
being made in the presentation, asserted that while the debt
itself is technically non-recourse under project financing, an
organization must still put the debt on its books due to the
underlying level of risk assumption. An organization cannot
insulate itself automatically from recognizing the liabilities
associated with the project on its balance sheet just because
the financing arrangement is, arguably, non-recourse.
MR. TSAFOS agreed that Representative Hawker is correct in his
observation that enalytica's statements are absolute when there
is finer detail. Mr. Tsafos said it has not yet been determined
what kind of separation there will ultimately be if the Alaska
LNG Project is done using project finance and whether this asset
will be completely off the State of Alaska's balance sheet.
2:16:09 PM
REPRESENTATIVE HAWKER said a classic example is that until
recently the State of Alaska was not required to recognize its
post-retirement benefits in its balance sheet, although the
state chose to do so. Accounting promulgations were recently
changed to mandate that this be done, affecting many
municipalities. It is not only something empirical. Those
issues are subject to future regulatory authority that could
change the character of the project. The classic definition of
mega-project is a project that changes the economic and
regulatory weather around it. When this project gets going, the
accounting world could very well say that this project cannot be
hidden from the world.
MR. MAYER added that this was not included here to set up
something firm and absolute, but rather the opposite -- to set
out the extent of the unknowns in all of this. At this moment
there is only a vision for a project; the vast majority of the
details are yet to be hammered out. One big unknown is how this
might be financed in terms of the overall project and the
individual partners. Later in today's presentation the question
of the midstream and TransCanada will be addressed. A question
raised numerous times by the administration is the state's
overall balance sheet and ability to carry debt for this process
and therefore ability to fund its share, which is a reason why
having a partner like TransCanada is attractive. A vast amount
remains unknown about how this will be financed and therefore
what the implications are for the state and the state's balance
sheet. It may well be that the state is seriously capital
constrained and that for purely financial reasons having a
partner could be very attractive. It could also be that the
inverse is true and large amounts can be financed through non-
recourse debt which would not have to go on the state's balance
sheet. The state might turn to other assets or to a range of
other things by maintaining flexibility in how it seeks to
structure this or to exercise an off-ramp [in the MOU with
TransCanada] if it finds it does have the financing capacity and
wants to pursue that.
2:19:19 PM
MR. TSAFOS, in response to Co-Chair Feige, confirmed that IHS
[slide 6] is a consulting company that he and Mr. Mayer used to
work for.
MR. MAYER added that the report published by IHS is available.
2:19:42 PM
REPRESENTATIVE KAWASAKI, in regard to easier accommodation of
riskier sponsors under project finance, asked if this is Alaska.
In regard to the rate depending on project risk, he asked who
decides that and how would the risk be formulated for the Alaska
LNG Project. He further asked how enalytica thinks the risk of
this project will be perceived.
MR. TSAFOS responded that easier to accommodate riskier sponsors
is a general statement and has nothing to do with Alaska as far
as the state's current financial solvency given Alaska's balance
sheet is definitely strong. Regarding how project risk is
assessed, he recalled that at the LNG 17 industry conference,
ExxonMobil gave a presentation about project finance for Papua
New Guinea. ExxonMobil put up a picture of the closing day on
the $14 billion loan and it showed stacks of papers across the
full length of a 40-foot room, all of which had to be signed,
noting that who determines and how it gets determined is a very
long process. The difference between project finance and
balance sheet finance is that when loaning money to ExxonMobil
the question being asked by the lender is whether ExxonMobil can
pay back the loan and when loaning money to the Alaska LNG
Project the question being asked by the lender is whether the
Alaska LNG Project can pay back the loan. The lender ultimately
cares about how much the project is going to cost, what kind of
contracts are available for selling the gas, and being
comfortable that these contracts will be honored by both the
buyer and the seller. Sovereign risk in the case of LNG
projects usually takes two forms. One is security risk, such as
building something in the Niger Delta or something adjacent to a
war zone. The other type of risk is if the country is bankrupt
it can be expected that that country will take radical steps to
redeem itself and a big asset like an LNG project would be a
prime candidate for a state or sovereign to go after in order to
generate money to get itself out of a tough position. So, the
answer is whoever is willing to loan the money -- the lender
determines the project risk. The lender assesses security,
technical risk, and operational risk, and puts these together to
determine a cost of debt.
2:24:02 PM
MR. MAYER concurred, adding that a lender loaning money to
ExxonMobil for a project cares about ExxonMobil's balance sheet
and credit rating. A lender to the Alaska LNG Project is
thinking about companies, balance sheets, and credit ratings,
but more than anything a lender cares about the "take-or-pay"
contracts that have been signed, who the contracts are with, and
the credit ratings of those buyers. The future cash flows of
the project open the financing and the lender is assessing the
creditworthiness of that contract, how much it absolutely
requires these entities to pay or be in default, and how "good
for it" those entities are.
2:25:33 PM
MR. TSAFOS turned to slide 8 to address the methodology of cash
in and cash out. For the Alaska LNG Project, the state earns
money in two ways: by virtue of being a project owner and being
a sovereign. Project revenue is calculated by multiplying the
volume times the price, minus capital expenditures, minus
operations and maintenance, minus debt service, and minus the
tariff paid to TransCanada. Cash flow from sovereign functions
comes from state income tax and property tax. Thus, as a
sovereign, the money the state makes from the project includes
project cash flows and sovereign cash flows.
2:27:05 PM
MR. TSAFOS looked at four cash flow scenarios, each assuming a
25 percent equity ownership for the state: 1) no debt and no
TransCanada partnership; 2) no TransCanada partnership but the
state finances 70 percent of its share with debt; 3) TransCanada
is a partner and the state exercises its buyback option so the
state has a 10 percent share in the gas treatment plant and the
pipeline and TransCanada has a 15 percent share in those
components; and 4) TransCanada is a partner but the state does
not exercise its buyback option, so the gas treatment plant and
pipeline are 75 percent oil companies and 25 percent TransCanada
and the liquefaction plant is 75 percent oil companies and 25
percent State of Alaska. All the revenue from project ownership
and from sovereign functions is not necessarily available for
the state to spend in any given year, as both restricted and
unrestricted cash flows must be reviewed. Restricted cash flow,
income that must go to the permanent fund and income that will
pay property tax, must be subtracted to determine the
unrestricted funds available to the state.
2:29:27 PM
MR. TSAFOS, in response to Co-Chair Feige, confirmed that the
property tax is the share of the overall property tax that goes
to municipalities. He said enalytica has made an assumption of
putting 80 percent into restricted funds for property tax; thus,
if property tax is $100 then $80 will go to the municipalities.
REPRESENTATIVE SEATON, noting that the State of Alaska's system
has tax credits, inquired whether those would be considered a
capital expense.
MR. MAYER replied the bigger question is not tax credits, but
tax deductions of capital spending, which is upstream spending
on gas and deduction against the oil. That is accounted for in
the model as a cash outlay; it is reduction in revenue that
shows up in the cash flow. The final results are net of all
these, including net of losses in taxes due to expenditure.
2:30:54 PM
MR. TSAFOS moved to slide 9, "SOA'S Cash Calls and Off-Ramps,"
explaining that the y-axis of the graph is in millions of
dollars. The x-axis depicts four sets of different colored
bars, each set representing one of the four phases of the
project -- Pre-FEED, FEED, Construction, and Online. Each green
bar represents the scenario of no TransCanada and no debt, which
is the HOA, the maximum that the state could be on the hook for
paying out and the maximum the state could expect to get back in
return. Each yellow bar represents the scenario of no
TransCanada and the state borrowing 70 percent of its share.
Each red bar represents the scenario of TransCanada as a partner
and the state buy back of its share so that TransCanada ends up
with a 15 percent share and the state a 10 percent share. Each
blue bar represents the scenario of TransCanada owning 100
percent of the gas treatment plant and the pipeline and the
state does not exercise its buyback option and remains purely an
owner in the liquefaction. The text at the bottom of the chart
explains how to get from the first phase to the second phase,
from the second phase to the third phase, and from the third
phase to the fourth phase.
2:33:25 PM
MR. TSAFOS, responding to Representative P. Wilson, said the
"70/30 D/E split" for the red bar means 70/30 debt/equity, which
is 15 percent for TransCanada and 10 percent for Alaska, which
comes from the state buy back of 40 percent of the 25 percent
that it has given TransCanada.
2:34:17 PM
MR. TSAFOS addressed the set of negative bars representing the
[Pre-FEED] phase, specifying that the negative for the state
could be anywhere from $55 million to $104 million, depending on
which structure the state chooses. In an option where there is
no TransCanada (green and yellow bars), the number is negative
$104 million; if TransCanada is brought in (red and blue bars),
the number is negative $55 million because TransCanada is
covering the state's share for a portion of the studies. At the
end of the Pre-FEED process, the state has three options, one
option being to abandon the project and, if TransCanada is a
partner, reimburse TransCanada $50-$60 million per the terms of
the MOU.
CO-CHAIR SADDLER announced that Co-Chair Feige has passed the
gavel to him.
MR. TSAFOS continued his explanation of slide 9, explaining that
if TransCanada becomes a partner it pays for the state's share.
So, if the state drops TransCanada or abandons the project, the
state must reimburse TransCanada for carrying the state's share
into the project, as per the MOU. Another option for the state
is to adjust its equity, which it can do throughout the phases
of the project. The state could, for example, reduce its equity
from 25 percent to 20 percent by selling 5 percent. The third
option is for the state to keep things as they are and proceed
to the FEED stage.
2:37:06 PM
MR. TSAFOS said if the project goes to the FEED stage, the state
will be required to pay its share of the FEED study, from $500
million to $270 million. He reiterated that the green and
yellow bars represent not having TransCanada as a partner and
the red and blue bars represent having TransCanada as a partner.
At the end of the FEED stage, if TransCanada owns 100 percent,
the state will have spent [$266] million (blue bar in FEED
stage) plus $55 million (blue bar in Pre-FEED stage) for a total
expenditure of between $310 million and $320 million. If
TransCanada is not a partner, the state will have spent $486
million plus $104 million. After the FEED study is completed in
2017 or 2018, the state [again has three options]. One option
is to abandon the project in which case the state would need to
reimburse TransCanada for paying the state's share. Another
option is to adjust the state's equity by selling some of its
share. The third option is that the state can keep things as
they are and proceed to the construction phase.
MR. TSAFOS pointed out that the construction phase is when the
large amounts of money are invested. The green bar in the
construction phase represents the state taking no debt [and not
having TransCanada as a partner], in which case the state would
be on the hook for about $11.7 billion.
2:40:12 PM
REPRESENTATIVE HAWKER expressed his concern and asked what the
probability is that these are in fact the numbers, slide 9,
given that Pre-FEED and FEED are about identifying the cost of
this project. He queried whether the consultants are privy to
information that legislators are not.
MR. MAYER answered that the numbers on the slide are not a
precise measurement; the aim is to be illustrative and to give a
very rough idea. For example, enalytica's numbers are similar,
but by no means identical, to the numbers presented by the
administration's consultant, Black & Veatch, as each has done
its own modeling with its own assumptions. These numbers are an
order-of-magnitude indication, and are not precise forecasts of
what will happen as the project has not been scoped in any
detail. These numbers are very, very rough indications of what
could happen.
2:42:40 PM
REPRESENTATIVE HAWKER expressed his concern that enalytica sees
the world differently than Black & Veatch. He said enalytica
works for and is providing counsel to the legislature while the
administration is providing its perspective to the legislature
based on the work of its consultants, Black & Veatch. Hearing
that there is such a material differential between the two
consulting firms is a bit of concern. He said he hopes there
will be clarification of the differences and recognition of a
common answer.
MR. MAYER responded that when the numbers are compared
directionally, the two consulting firms come to very similar
conclusions on many of the core issues. But, he allowed, when
it comes to specific revenue amounts there is a wide range of
difference, including that enalytica presents its analysis in
real, constant dollar terms as opposed to looking at the impact
of inflation over time.
2:43:40 PM
REPRESENTATIVE HAWKER inquired whether Black & Veatch is using
discounted dollars while enalytica is using whole dollars.
MR. MAYER replied that, in regard to recent presentations, he
does not know. However, he continued, in the timeframe being
talked about, the differences are not enormously material and he
takes a lot of confidence that [the two consulting firms] have
approached this entirely separately, come up with entirely
separate sets of assumptions and models, and yet come up with
analysis that, on core issues, is directionally very similar.
CO-CHAIR SADDLER commented that the committee has the time to
hear the two and compare the conflicting models and conclusions.
2:44:40 PM
REPRESENTATIVE HAWKER, regarding slide 9 and the assumption of
25 percent equity for the state, inquired whether that equity is
referring to the state's "pipe within a pipe". Regarding the
cash splits depicted on slide 9, he inquired what the assumption
is for the equity split between TransCanada and the state.
MR. MAYER answered that it assumes a 25 percent gas share. The
green and yellow bars depicted in each scenario represent 25
percent equity across the entire value chain. The red and blue
bars [depicted in each scenario] represent the world of the MOU
and TransCanada. In the buyback option [red bar], the State of
Alaska has 10 percent and TransCanada has 15 percent in the gas
treatment plant and the pipeline [for a total of] 25 percent in
the midstream. The blue bars represent the full 25 percent to
TransCanada in the gas treatment plant and the pipeline, and 25
percent to the state in the liquefaction.
2:46:01 PM
MR. MAYER, responding to Co-Chair Saddler, confirmed that the
cash outlay depicted for each phase is the dollar amount for
that phase only and not a cumulative number.
2:46:28 PM
REPRESENTATIVE SEATON, regarding the state selling down its
equity, asked whether that means the state would be partnering
with the entity that purchases the equity. For example, could
the state split its equity, or sell the entire portion and
become a revenue receipt partner so that the state is back into
its normal receipt of tax and revenue share.
MR. TSAFOS responded the answer is half yes. The half that is
yes is that the state could sell, say, 5 percent of its 25
percent share in the liquefaction to, for example, Mitsubishi.
Depending on what the state sells determines what the state is
left with. The state could sell all of its gas at the wellhead,
but that would not necessarily push the state back into the old
world of traditional tax royalty because the state is already in
the new world. It is just a matter of where the state sells its
25 percent of gas. For example, the state could sell its gas up
on the North Slope, or in Nikiski, or in Japan. So, the answer
is the state can bring a partner but there are many different
ways in which the state can bring that partner that determine
what the state ends up receiving over a long period of time.
Normally, a lump sum is received up front, but what is received
afterward depends on what exactly was sold.
2:48:44 PM
REPRESENTATIVE SEATON recounted that the committee has often
heard that when a percentage of gas is sold, the gas buyer
generally wants to have that same percentage all the way up the
chain. He posed a scenario in which the state has 25 percent in
gas and 25 percent in liquefaction, and inquired whether the
state could return itself to a more traditional governmental
position of revenue receiving by selling both of those ownership
positions.
MR. MAYER replied that, in principle, the idea of the state
selling its share of the gas is exactly as Representative Seaton
said, in that the state would be trying to monetize the present
value of the future revenue stream and claim that now. In a
traditional project where the state has full ownership,
including the upstream, that would be relatively
straightforward. In this case, where the state has that gas
share by virtue of royalty and tax, some specific contractual
structures might need to be put in place to enable a sale of
that future gas stream along with the corresponding equity
stake. Mr. Mayer imagined there are a number of ways the state
could do that, but said many details would need to be worked out
to determine how to implement that and whether there are,
indeed, any limitations.
2:51:28 PM
REPRESENTATIVE SEATON requested enalytica to run those scenarios
to see whether any provisions in the bill would prevent the
state from exercising its more traditional governmental role and
receiving a revenue stream, not necessarily all up front as a
net present value but a sale with revenue stream over time
instead of the participation.
2:52:01 PM
CO-CHAIR SADDLER noted there are limitations in this deal that
Alaska cannot sell its share to a TransCanada competitor. He
asked whether that could limit the state's ability to meet its
obligations should it find itself short of cash.
MR. MAYER agreed this is a good point and said it is certainly a
limiting factor under the MOU. Unlike selling an overall equity
share in the project along with the share of gas that goes with
it, if one sought to allocate that participation to another
partner, the basis on which that participation was allocated
would usually be one of trying to get the lowest possible bidder
on tariff because ultimately what is being sold is a share of
something that is just the right to recover the future cost
through a tariff, not the right to gas and revenue that comes
from the gas. So, in that sense, it is not something that would
be looked at to sell as a revenue-generating item as would be
the case for the overall gas share and sharing the
infrastructure.
2:53:39 PM
MR. TSAFOS addressed Representative Hawker's comments, saying
enalytica's awareness of the uncertainty is why a stress-case
scenario was modeled in which capital expenditures are 25
percent higher to provide a sense of the range of uncertainty.
He noted this will be discussed later in the presentation.
2:54:27 PM
MR. TSAFOS resumed his discussion of slide 9, drawing attention
to the portion of the graph for the construction phase. He
reminded members that the idea of the graph is to understand the
total numbers if: 1) the state pays for everything out-of-
pocket and has no debt (green bars); or 2) the state takes on
debt (yellow bars); or 3) the state takes on TransCanada as a
partner (red and blue bars). He noted that the depicted numbers
come with the caveats relating to precision as previously
mentioned by Mr. Mayer. In the construction phase, the state
could be on the hook for about $12 billion if it takes on no
debt. If the state finances with 70 percent debt, it would be
on the hook for about $5 billion. The addition of TransCanada
as a partner could bring the state's cost down to about $4
billion or $3.5 billion. He said he is trying to give the
committee a sense about capital constraints and TransCanada at
this stage of the project, and the flexibility the state has in
its equity share and its upfront spending.
2:55:56 PM
REPRESENTATIVE TARR remarked that while several options are
being evaluated, the options that really are on the table are
the two TransCanada options due to the documents. She sked how
committee members can appropriately evaluate the risk between
the blue bars versus the yellow bars [the scenario of
TransCanada 100 percent gas treatment plant and pipeline and
70/30 debt/equity split versus scenario of no TransCanada and
70/30 debt/equity split]. She observed that these two scenarios
are closer financially in terms of the state's overall
commitment ($3.5 billion versus $5 billion, respectively).
MR. MAYER responded future slides will look at this question and
will help with that answer.
MR. TSAFOS added it also becomes quite different when the stress
case scenario is looked at, which is where the difference
between having TransCanada and not having TransCanada becomes
quite interesting.
2:57:41 PM
MR. TSAFOS wrapped up his discussion of slide 9 by bringing
attention to the online phase of the project. He pointed out
that once construction starts it is now too late to stop [and
not proceed to online]. The only question at this point is
whether the state is still comfortable with its equity share.
Once online, the revenues to the state will range from $4
billion to $2.9 billion annually. He reiterated that the idea
of the chart on this slide is to see what the state's
commitments are at each stage of the project, what is the
directional change between one option versus the other so
members can start asking questions, such as what the difference
is between having TransCanada or not having TransCanada and how
much that partnership helps upfront but how much revenue is
foregone later on.
2:58:58 PM
CO-CHAIR SADDLER inquired what the state's total expenditure
will be over the initial project term of 25 years.
MR. TSAFOS replied that the cumulative cash flows, as well as
the split between the different partners, will be provided later
in the presentation.
CO-CHAIR SADDLER asked whether that will be in net present
value.
MR. TSAFOS answered it will be net present value as well as
undiscounted when addressed later in the presentation.
2:59:43 PM
MR. TSAFOS turned to the graph on slide 10, "LNG Income Includes
Restricted Revenue," explaining that not all of the revenues
will be available for spending because some of it is permanent
fund and some is property tax. He pointed out that the set of
four bars on the far left of this chart represent the state's
total annual income and is the same set of bars depicted on the
far right of the graph on slide 9. The middle set of four bars
represent the state's total income minus the permanent fund.
The set of four bars on the far right of the graph represent the
state's total income minus the permanent fund and minus the
property tax due the municipalities. Responding to Co-Chair
Saddler, he said enalytica made the assumption for allocating 80
percent of the total of property tax to municipalities, but
qualified that this assumption is not a forecast or statement
that this is going to happen. He said [the graph] is to give a
sense of the orders of magnitude of how these numbers differ
when going from total revenue versus revenue that is available
to spend unrestricted.
[Co-Chair Saddler returned the gavel to Co-Chair Feige.]
3:02:14 PM
REPRESENTATIVE HAWKER inquired whether the aforementioned
numbers in the overall model include the state's royalty share.
MR. MAYER responded yes, the entire model is built on the basis
of a 25 percent share of the gas, which comes from the royalty
and the production tax.
3:02:50 PM
CO-CHAIR FEIGE recessed the House Resources Standing Committee
until 6:30 p.m.
6:35:19 PM
CO-CHAIR FEIGE called the House Resources Standing Committee
meeting back to order at 6:35 p.m. Representatives Hawker,
Johnson, Seaton, P. Wilson, Saddler, and Feige were present at
the call back to order. Representatives Tarr, Kawasaki, and
Olson arrived as the meeting was in progress. Representative
Isaacson was also present.
6:35:33 PM
REPRESENTATIVE HAWKER addressed slide 11, "Stress Testing SOA's
Cash Calls and Revenues." He drew attention to the far left set
of four bars depicting the base case construction for the years
2019-2023 and compared them to a handout in the committee packet
which he believed came from the administration. He observed
that for the scenario in which the state goes it alone with no
debt (green bar), enalytica's graph has an expenditure of $11.7
billion while the administration's expenditure is $13.2 billion.
For the scenario of 40 percent state buyback, enalytica's
expenditure is [$4.05] billion while the administration's figure
is $9.3 billion. He asked what accounts for these differences.
MR. MAYER replied he would expect to see differences because
enalytica arrived at its numbers through its own assumptions and
exercise. These numbers are actually very close from the
perspective of just how little is known about this project and
the Pre-FEED process has not even been commenced. Any numbers
will be an abstract effort what the possible future looks like.
In a year and a half there will be substantially tighter numbers
with potentially better assumptions and substantially better
estimates. By the time it comes to make the final investment
decision there should be some very accurate numbers as to what
those costs actually are. Any number at this point is about
direction of analysis in coming to understand whether the
structure makes sense and whether the range of things makes
sense. The only thing that can be said about the actual precise
numbers is that they are all certainly wrong.
MR. TSAFOS added that part of the question is how the capital is
spread across that construction period. Crucially, it is how
that capital expenditure is spread on the different years, and
also whether it is assumed that the day the project comes online
all the capital has been spent. For example, enalytica has some
spending on the first year of operation, the reason being that
this is a massive project with three different trains. So, even
when the project comes online, there will still be some capital
expenditure. In looking at the construction phase, it does not
mean that is all the money the state spent for the project; it
is the money the state spent before it has any income, and the
entirety of the $1.5 billion could be attributable to that.
Even a simple difference in approach in terms of what is
calculated [affects the resulting numbers]. For example, the
diagram referenced by Representative Hawker is likely counting
just the total capital expenditure, while enalytica's number is
recognizing that some construction capital may be spent after
2023 during the first year of operations, which could account
for that difference.
6:40:32 PM
REPRESENTATIVE HAWKER qualified he is not indicting enalytica's
work, but questioned the figure of $3.9 billion for the green
bar depicted under the base case online phase. He asked whether
the $3.9 billion in revenue is a net number after capital costs
still being incurred in that period.
MR. MAYER answered the number is an average across the project
life, with some years the revenue being higher than that number
and some years lower. The way enalytica has modeled it in the
first year the number is lower [than $3.9 billion] due to that
additional spending. However, on average over the project life,
[$3.9 billion] is the range of net annual cash flow after all
expenses are taken out.
MR. TSAFOS added that [the $3.9 billion on slide 11] comes from
using the formula on slide 8. It equals all of the revenue,
minus capital expenditures, minus operation, minus debt service,
and minus tariff, plus state income tax, and plus property tax.
Thus, the first year would not be as high. He allowed enalytica
could have also shown the cash flow for every single year for
the next 20-25 years, but opted for this approach rather than a
yearly cash flow because this method was more intuitive even
though using averages loses some precision over time. The goal
was to create something that is more intuitive for people to
understand the trade-offs, recognizing that some precision is
lost through that approach.
6:43:32 PM
REPRESENTATIVE HAWKER said that is $1.5 billion of precision.
He related that when reading these numbers in enalytica's
previous testimony, his take away was that this was the first
year of operations. Thereafter, it was not at all clear to him
that this was an averaged annualized return for about 20 years
of project life. He inquired whether that return is skewed
heavily to either end or whether it is just the front-end year.
MR. MAYER responded it is overall very even over time. He
allowed there is certainly variation for a range of reasons in
given years and said he would have to go back to see if there is
more than a billion dollars in variation in any given year, but
reiterated that overall it is a very even cash flow.
REPRESENTATIVE HAWKER asked whether it is enalytica's number or
the administration's number that is closest to right.
MR. MAYER replied both of these numbers are definitely wrong, as
he had said before.
REPRESENTATIVE HAWKER said that answer just made his point.
6:45:22 PM
MR. MAYER, in response to Co-Chair Feige, confirmed enalytica's
flow charts are for the entire project, the liquefaction plant
as well as the midstream.
MR. TSAFOS added that when looking at the flow chart, he
believes all the other numbers are fully 100 percent equity, so
none of the other options are directly comparable with
enalytica's numbers because these do not include any debt, "like
the 6.9 and 9.6."
6:46:18 PM
REPRESENTATIVE HAWKER inquired why debt would make a difference
given it is the cost of building the project that is being
talked about, unless enalytica is including capitalized interest
on the project from an accountancy basis. He further inquired
whether enalytica is talking about the cash cost of constructing
the project. Noting that interest is capitalized into the
project, he inquired whether that is in enalytica's numbers but
not in the administration's numbers.
MR. MAYER answered the green bar assumes no debt whatsoever by
having the entire cash outlay be reflected as such; then, the
corresponding green bar shows all the revenue that would come in
that scenario. The yellow bar reflects the 70/30 debt/equity
ratio -- what that would mean in actual cash not including debt
that the state would need to provide; [then, the corresponding
yellow bar] is the actual cash net of debt payments that the
state would receive.
6:47:39 PM
CO-CHAIR SADDLER understood the green bar is all equity so there
is no debt and no financing. He further understood that the
yellow bar labeled $3.445 billion is net of the debt expense.
CO-CHAIR FEIGE noted it is 70 percent debt.
MR. MAYER responded yes.
6:48:03 PM
REPRESENTATIVE HAWKER asked whether the administration's figure
of $13.2 [billion] for construction includes capitalized
interest.
MR. MAYER replied either he or the administration would have to
get back to the committee with an answer.
REPRESENTATIVE HAWKER asked what basis was used by enalytica for
the Pre-FEED, FEED, and construction cost numbers, given it did
its own modeling. He recalled that earlier testimony by the
administration that its numbers were based on the old Alaska
Gasline Inducement Act (AGIA) proposal and not the new cost data
coming from the new project and the new players.
MR. MAYER answered enalytica assumed a total project cost of
about $49 billion for the base case scenario: about $45 billion
for liquefaction, pipeline, and gas treatment plant, plus $3-4
billion for upstream costs primarily at Point Thomson. The
stress case scenario increased those numbers 25 percent. He
reiterated that the only purpose of any of this quantitative
numeric analysis, at this point, is to have a directional
understanding. For example, how does having a gas share and
equity compare with being a taxing entity in-value? What is the
role of TransCanada in all of this in terms of its relative
impact as opposed to absolute numbers where there is not yet a
project with any concrete details to really know what these
numbers actually will be? The purpose is to understand,
relatively speaking, whether one structure makes sense versus
another and what the impact is of a particular intervention; it
is not to be able to say that it is known what income the state
will be receiving in any given year.
6:50:31 PM
REPRESENTATIVE HAWKER understood Mr. Mayer to have said the
numbers do not make any difference because what is being talked
about is structure. However, there are numbers on the page and
they are big numbers, and they are numbers that legislators are
being asked to make judgments on. He inquired what foundation
was used for the $49 billion in enalytica's model.
MR. MAYER responded it is a combination of publically available
producer estimates with enalytica's own understanding of what a
well at Point Thomson costs to what might be a reasonable
assumption for a range of different components.
6:51:22 PM
REPRESENTATIVE SEATON understood that on [slide 11] as well as
others, the Pre-FEED is the years 2014-2015, FEED is 2016-2018,
construction is 2019-2023, and revenue begins in 2023, rather
than 2024. He inquired whether this is a nomenclature problem
or that revenue will be coming in during the [last year of
construction].
MR. MAYER replied there is an overlap because the new project
comes online partway through 2023. He allowed it would have
been clearer for ease of understanding had enalytica drawn a
firm line on January 1.
REPRESENTATIVE SEATON maintained it does make a difference in
the calculations as to whether or not it is a full year of
revenue in the year the revenue begins, and the chart makes it
look like it is a full year of revenue [in 2023]. He requested
the chart be rewritten.
MR. TSAFOS agreed to rewrite the chart [to show the online phase
beginning] in 2024. He qualified, however, that enalytica does
not want that change to imply a precision or a certainty that
the state should be expecting money in 2024. What is trying to
be shown in this chart is the average cash that the state can
expect to get, based on these assumptions, when the project is
online. Thus, it is more the year after construction ends
rather than to say to count on this amount of money in 2024.
6:53:50 PM
MR. MAYER, at Co-Chair Saddler's request, repeated enalytica's
assumption for the total project cost: about $45 billion for
liquefaction, pipeline, and gas treatment plant, plus $3-4
billion for upstream costs. In further response, Mr. Mayer
confirmed that enalytica's information source was publicly
available producer estimates plus enalytica's own analysis based
on experience for what would be reasonable costs for a range of
components. He added that the entire purpose of the next one
and a half years is to start to get a better handle on all of
these things and to start to be able to make much more detailed
and informed decisions. Once the entire FEED process has been
gone through there will be a final investment decision that the
state needs to make on the basis of some very real numbers. At
this point, these are numbers to run for a model to get a sense
of how value in the project is shared between the partners, the
role of TransCanada and how much value that takes. These are
the things the legislature is being asked to decide on at the
moment. The legislature is not being asked to take sanction on
a $50 billion project; if it were it would need much more detail
and much more concrete, reliable, accurate figures than any of
these numbers. Any numbers presented by anyone at this time can
only be a best guess that will almost certainly change as more
is discovered.
6:55:52 PM
MR. TSAFOS added to Mr. Mayer's comments by pointing out that
when the LNG project in Norway was undertaken, the company did
not have a full grasp of the total cost until a year after the
project was running. He qualified he is not saying this to
scare committee members, but to say that it is an inevitable
"chicken and an egg" problem -- more information is needed to
make a decision, but until some decisions are being made no one
wants to spend the money to get better data. The hope is
twofold: 1) as more study is done the cost can be narrowed down
along with identifying places where the cost can be lowered; and
2) to look at whether this project is viable at all because if
it does end up in the realm of $65 billion it is quite possible
that the partners and the State of Alaska will say they need to
go back to the drawing board and rethink this. The challenge is
that the decision point cannot be arrived at until money is
spent based on a hunch that this might work. In this sense,
there is nothing different about the State of Alaska than any
other company and sovereign that has ever undertaken a project
of this magnitude. A risk faced in all projects is the spending
of more money only to find the project is a no-go. He
reiterated that enalytica is trying to give committee members a
sense of how these things move as the assumptions are moved
around and, hopefully, that, rather than the specific revenue
numbers, is the key takeaway.
6:58:22 PM
CO-CHAIR FEIGE offered his understanding that the stage-gated
process has far less risk than simply making the decision to go
forward without a process of refining the project design. He
understood enalytica's intention here is not to say that if the
state goes it alone it will cost $11.727 billion, but to show
that the relative cost of going it alone is much more than the
yellow bars which are more than the red bars which are more than
the blue bars. It is to give committee members a relative idea
that one particular option is going to cost more than another
one, not what the specific costs and commitments are at a
particular time.
6:59:26 PM
MR. TSAFOS, in response to Co-Chair Saddler, confirmed that the
cost of $45 billion [for gas treatment plant, pipeline, and
liquefaction] includes the marine terminal because the
liquefaction plant is a marine terminal.
MR. MAYER, in response to Co-Chair Saddler, confirmed that the
$45 billion also includes the transmission lines from the gas
fields.
7:00:02 PM
REPRESENTATIVE HAWKER recalled that earlier today enalytica
stated that the transmission lines were not included as an
element in the conceptual ownership graph. However, it was now
just stated that the transmission line cost is included in the
$45 billion. He further recalled that the additional cost of
$3-4 billion for upstream costs does not include the
transmission lines. He asked whether that $3-4 billion is
paying industry's development of Point Thomson or other fields.
MR. MAYER replied that is an assumption on what is required for
additional gas-related development, primarily for a number of
additional wells at Point Thomson as well as initial gas
processing that occurs on the upstream before gas enters the
transmission line to the gas treatment plant. That is a total
amount for the total project. The state would make a
contribution to that through the tax system under which there is
a 35 percent production tax on oil. As the legislation is
currently written, all upstream costs, regardless of whether
they are for oil or for gas, are deductible against the oil
production tax. In other analyses, enalytica has shown the
possible impact of that. During construction, the state will be
receiving lower oil tax revenues, 35 percent of the upstream
cost that is being spent in those years.
7:02:15 PM
REPRESENTATIVE HAWKER asked whether anyone has done an analysis
on exactly how much the state is going to be paying to develop
the infrastructure for the upstream of Point Thomson that is not
a state asset, and not part of this project, as it is an asset
of the producers.
MR. MAYER responded it can be thought of as 35 percent of $4
billion, but there will be a better view of that down the road.
CO-CHAIR FEIGE interjected "lease expenditures."
7:03:01 PM
REPRESENTATIVE HAWKER understood that $4 billion is what Point
Thomson is going to cost as it sits at the moment and that
amount does not include any of the additional development to
bring gas online. He said he is not trying to pick problems
with enalytica's methodology, but the discrepancies between the
administration and enalytica are causing him much consternation.
MR. MAYER answered that enalytica and the administration have
approached these things independently, yet have come to similar
conclusions on the core issues. If there are areas on which it
disagrees with the administration, enalytica will let members
know. If he were a legislator looking at this, he would take a
great deal of comfort in that two different groups of people
with two different approaches and assumptions looked at this and
came to very similar conclusions in the directional analysis,
despite the independence of their approaches.
MR. TSAFOS added that the number enalytica has for upstream
developments and the state contribution through the tax system
does show up in Black & Veatch's analysis. He recalled a Black
& Veatch chart that shows oil only and then oil and gas, and
when looking at these two things it can be seen that the oil and
gas turns below the oil in the beginning years because there is
a tax deduction for lease expenditures, and that is primarily
for Point Thomson.
7:05:36 PM
REPRESENTATIVE HAWKER said he thinks the cost to develop Point
Thomson is more like $10 billion rather than $4 billion. While
Mr. Mayer said the numbers do not matter because the numbers are
close, the issue is that they are close enough to illustrate
enalytica's concurrence with the approach and the mechanism that
is brought forward by the administration for how this all works
together. He asked whether he is supposed to take away that
enalytica is endorsing the administration in the MOU and the
project proposal.
MR. MAYER responded enalytica has areas of agreement and areas
of difference. However, when it comes to the quantitative
analysis, Black & Veatch and enalytica get very similar numbers
for such things as how much equity does the state need to have
to be equivalent to the status quo, or how does in-kind compare
to in-value, or how much value does TransCanada consume of the
project total and that compares to other options available to
the state. He would draw comfort from this given that there
are, in fact, no accurate numbers available anywhere. It is not
a question of accurate enough, it is simply a question of
numbers at this point are best guesses based on very little
information. In a year and a half there will be much better
information and a few years later there will be substantially
better information. In the meantime, the purpose of
quantitative analysis is not to forecast the future, not to say
it is known exactly what will be spent and what revenue will be
received. The purpose of analysis is to declare the fundamental
things the legislature needs to understand and grapple with as
those tend to center around a few big things like whether to
take value as a taxing entity or gas in-kind and an equity
stake, and how those things compare across a range of different
prices. In looking at the MOU, what does TransCanada's
participation actually mean? How much potential value could the
state be foregoing under that option? What might some other
options be? How do these things compare? Having initial
approximate numbers to view as a model provides some
understanding for how these variables move against each other
and where relative value lies. Understanding where relative
value lies is very different from being able to say it is known
exactly in this year what the state should expect because none
of us know that.
7:08:50 PM
REPRESENTATIVE P. WILSON understood what is being looked at is
the different options that the state has and what it would look
like in one option and what it would look like in another so
members can make a general decision about what is the best thing
for the state to do at this point in time.
MR. TSAFOS concurred, adding that a lot of these paths are still
open to legislators even if enabling legislation is passed.
Legislators would not be 100 percent tied to one of the four
bars depicted on the charts. The legislature would still have
the opportunity to go anywhere from the green bar all the way to
the blue bar. Legislators are not even being called to make a
choice regarding which of the four options. Clearly, there are
things legislators can do that push the state into one direction
or the other. However, even if the legislature approves
everything before it, it could still go to a world with no
TransCanada because the MOU provides a way for doing that.
Clearly, the enabling legislation sets in motion a certain path,
but it does not close off all the roads. There is a certain
amount of technical analysis that can be done and there is a
certain amount of philosophical gut-feeling. What enalytica is
trying to do is highlight the numbers and articulate the trade-
offs. In a project of this magnitude there is always going to
be an element of gut feeling because even when at the point of
taking final investment decision, it is a decision in which no
money will be seen for 5 years and making a bet of what the
world looks like for another 25 years. Even when all of the
available information is had, legislators will still find they
do not have quite as much information as they would like. That
is the nature of a long-term, long-lead business. An investment
is being made today that is going to pay off over the next 25
years. There is an inherent uncertainty to this project that
the state will have to become comfortable with if it is to
choose this path.
7:13:33 PM
REPRESENTATIVE TARR calculated that with an oil production tax
rate of 35 percent, the state could potentially lose almost $1.5
billion in revenue. She asked whether the revenues depicted [on
slide 11] for when the project goes online include that annual
loss of $1.5 billion.
MR. MAYER answered any relevant ongoing spending is captured in
these numbers, but the majority of the development spending
happens before the project comes online. Reminding members that
enalytica has provided this analysis in other forums, he said
between $200 million and $300 million in capital spending will
happen each year over a number of years, totaling about $1
billion of capital spending over that time. The $200-$300
million annually will be foregone oil taxes to the state.
According to the administration's modeling forecast, revenue to
the state from production tax and royalty base will be reduced
around [$4.5] billion. Costs will be deducted and written off
against oil taxes.
MR. TSAFOS pointed out that "those numbers are included in ...
the minus in the construction phase." So, it is not just what
is spent, it is also what the state does not receive from the
oil taxes. That is why Mr. Mayer said that any ongoing spending
is in the online world, but during the construction phase that
is embedded into these numbers.
REPRESENTATIVE TARR regarding the average [revenue] numbers
depicted on [slide 11], part of the consideration for
legislators is what the state has in savings if the state is in
a deficit-spending world and how many years that will last. She
requested from enalytica that these numbers be broken out into a
10-year timeframe so it can be seen whether the state will be
running out of money before new revenue comes in and where those
time periods overlap to show how the state will transition
through these time periods.
7:17:36 PM
REPRESENTATIVE HAWKER commented that when he is looking at the
charts he is looking for the anomalies and what sticks out as
something that creates an obvious relational difference. He
noted a "cash call" is the cash that is needed to put into the
project and that this does not mean it is because of an overrun
or something bad. A cash call is how the state steps up to the
plate with the checks it must write. [Regarding slide 9], he
observed that for the Pre-FEED and FEED phases there is little
difference between the height of the option bars, but for the
construction phase there is a mega-difference between the green
and [yellow] bars, which represent the state participating
without debt and with the debt/equity split, respectively. When
the state has no debt it does not have to answer to a cash call.
The difference between the $11.7 billion green bar and the $4.9
billion yellow bar is the debt component. He observed that
under the no-debt option, the construction cost is $11.7 billion
and, once online, the average annual revenue is $3.9 billion;
under the [70/30] debt/equity option, the construction cost put
out by the state is $4.9 billion and, once online, the average
annual revenue is $3.4 billion. He inquired whether the $3.4
billion is net of the state's debt service costs.
MR. TSAFOS responded it is net.
MR. MAYER added the difference is the debt service cost.
7:20:35 PM
REPRESENTATIVE HAWKER observed from slide 11 that if the state
were to undertake this project without TransCanada and with a
70/30 debt/equity split ([yellow] bar), the construction cost
would be $4.9 billion and payback would begin one and a half
years after that.
MR. MAYER replied yes, but advised members to bear in mind that
the reason the state's economics look quite good is because the
state is both a project participant and a sovereign receiving
other forms of cash, such as property and state income taxes.
So, when all of those are included in the analysis the state's
payback is relatively quick.
REPRESENTATIVE HAWKER remarked "we are the sovereign" and he
sees why the state would want to use a debt/equity split for all
kinds of reasons, including that there is a four-year payback.
He questioned what it is that TransCanada really brings to the
table when the state can get a total cash payback in one and a
half years and after that be free and clear and getting all the
cash to itself.
MR. TSAFOS answered that the aforementioned is the base case and
advised members to look at the stress case to see how easily the
numbers and payback can look different when some of the
assumptions are changed. He requested the committee allow him
to answer the question when he gets to the last section of his
presentation, which is about the midstream and TransCanada and
includes what enalytica has to say about the financial and non-
financial benefits of TransCanada.
7:23:15 PM
REPRESENTATIVE TARR, regarding the scenario on slide 11 of no
TransCanada and no debt (green bar), expressed her surprise that
the reward under that scenario is not proportional to spending
twice as much relative to the other scenarios. She asked
whether the amount of return reflects how much the fixed costs -
in terms of capital expenditures - influence this project versus
a change in the market price.
MR. MAYER queried whether Representative Tarr's question is
about the difference between the green and yellow bars in terms
of the big difference in the upfront cash but relatively smaller
difference in the [revenue] that follows.
REPRESENTATIVE TARR said she is referring to the green bar and
why the reward is not proportionately equal.
MR. MAYER responded that in both the green and yellow scenarios
the state is taking the full 25 percent throughout the value
stream. The only difference between them is the choice of
financing: financing entirely with the state's own cash versus
financing through some form of debt. The difference between
these two is the difference in upfront capital cost being spread
over 20-25 years of the project and the corresponding 5 percent
rate of interest. That difference of half a billion dollars is
not just for one year, but for every year of the project life
and is paying back that initial upfront capital cost.
MR. TSAFOS added that oil companies really like LNG projects
because, once over the upfront hump, LNG projects generate money
for a very long time. The challenge is getting over that hump
in the beginning. Key to remember is that while the capital is
huge up front, the ongoing operating capital is tiny relative to
that upfront investment. This goes back to a previous statement
he made before the committee that LNG projects generally do not
lose money; they may not make as much as was anticipated, but
once a project is running things have to turn really sour to
actually lose money. The low annual operational cost is what
really drives the economics. That is why the overarching
question is whether the project can actually be built at the
projected cost; once built, this project returns a huge amount
of cash. For example, the pipeline in Kenai came online in 1969
and now the economics of exporting this cargo from Kenai look
great -- all the capital has been spent, the asset has been
amortized, and that is essentially the logic.
7:27:30 PM
MR. TSAFOS returned attention to slide 11, explaining enalytica
approached a stress case in three different variables. [The
first variable], capital expenditure, was raised 25 percent
higher than the projected $49 billion. The figure of 25 percent
was chosen as reasonable based on the list of worldwide LNG
projects that was provided in enalytica's previous presentation
to the committee in which project cost overruns varied from 0 to
125 percent, and 25 percent is the average of those overruns,
including the zeroes. He qualified that cost could be higher
not because of overruns but because cost rises between now and
construction. [The second variable], sales price, was dropped
to $7 per million British Thermal Units (MMBTUs), which is
equivalent to about $50 per barrel oil. Currently, the cheapest
gas coming into Japan is at $11-$12. If oil were to drop to
$50, this Alaska project would have finance problems in addition
to LNG plant problems. Therefore, enalytica believes this model
to be quite an aggressive stress case. He submitted that if the
price of gas was to decline to $7, the overwhelming majority of
proposed projects throughout the world would not be sanctioned.
He further submitted the price would not stay at $7 for very
long because no one would build a project to feed the market at
$7. Another benchmark for comparison, he specified, is gas in
the Lower 48 at $3 Henry Hub. About $5-$7 is needed to ship
that gas to Asia. So, even at $3 Henry Hub, gas delivered to
Asia would be at a price higher than $7, which is another way of
saying that $7 is a low price. [The third variable], average
utilization, was put at 80 percent rather than 100 percent.
Utilization reflects two things, he explained. First, in Alaska
the amount of gas that can be produced depends on the
temperature -- the colder it is, the more gas that can be put
through the infrastructure; depending on the temperature, Alaska
may be unable to produce at 100 percent. Second, when looking
at new LNG projects around the world, it is seen that projects
without problems tend to operate at 95-100 percent. [Average]
global utilization is in the high 80's because new projects
operating at 100 percent are added with infrastructure that has
been online for 40 years. Older projects operate at a low
utilization because the gas they were developed to export has
been depleted. Therefore, 80 percent global utilization is
really an average of two extremes, rather than projects actually
operating at that level. Continuing, Mr. Tsafos noted that a
number of things can lead to low utilization, some of which are
not relevant for Alaska. Most common is a domestic gas
diversion in which the sovereign reduces export to meet the
demand of its people. He submitted, however, that no matter how
much Alaska might try to do that, Alaska would be unable to
consume enough gas to push the utilization that low. More
realistic for Alaska would be outages or accidents; thus, Alaska
likely would not have 80 percent utilization over a 10-year
period but may have low utilization over a 1-year period.
7:32:44 PM
MR. TSAFOS said enalytica added together the three events of
higher capital expenditure, lower price, and low utilization to
create a perfect storm. He explained that the two sets of four
bars on the left side of the graph on slide 11 are the base case
construction costs discussed earlier and the stress case
construction costs, which are a 25 percent escalation of the
base case. The only variable changed during the construction
period is the construction cost; price and utilization do not
matter because no gas is being sold during this period. The two
sets of four bars on the right side of the graph represent the
base case online revenue discussed earlier and the stress case
online revenue, in which all three of the variables are playing
a role. Sales price is playing a role because less is being
earned per molecule of gas, utilization is playing a role
because less gas is being sold, and capital expenditure is
playing a role insofar as borrowed debt. If money was borrowed
and the cost went up 25 percent, then 25 percent more would
probably have been borrowed and that money would have to be re-
paid. In the stress case for the green bar scenario (no
TransCanada and no debt), construction cost may be $14.7 billion
and revenue may be $1.6 billion per year, which is a 10-year
payback period, ignoring the time value of money and that money
further out is worth less than money today. Mr. Tsafos pointed
out that even if all these stress case variables happened, the
Alaska LNG Project would not quite turn negative and the project
would not come to the legislature to ask for more money. But,
in retrospect, the project would look like a bad investment
because the state would be earning a low return for a high
upfront capital investment. This stress case scenario is a
caution to the best-case scenario (slide 10) which looks quite
positive with a quick payback period. He noted that the stress
case figures on slide 12 are an average because at some points
the price might be lower and at some points the utilization
might be lower.
7:35:58 PM
CO-CHAIR SADDLER inquired whether the model was created for each
variable happening by itself or for all three variables
happening together.
MR. TSAFOS responded that individual modeling was not done, but
he offered to do so.
CO-CHAIR SADDLER understood the initial cost estimate for the
Trans-Alaska Pipeline System (TAPS) was $800-$900 million, but
the final cost was $8 billion. He asked whether enalytica can
give him, as well as the public, any comfort that the final cost
for this LNG project will not be 10 times the current estimate.
MR. TSAFOS replied he is not in a position to give that comfort.
However, he would say that if construction has not started, and
the cost estimate is $450 billion, that would be good reason not
to do this project. The most extreme case of cost escalation he
has seen is Russia's Sakhalin LNG project at 120 percent.
Qatar's Pearl gas-to-liquids project began at $4-5 billion but
ended up costing over $20 billion. No one can give a guarantee
that the cost started with will be the cost ended up with.
Comfort can be taken somewhat in that Alaska's partners are
probably as good as one could get in terms of keeping the cost
down. While good partners do not insure against cost escalation
or against things going bad, the best that can be done is to put
people in charge who know their jobs quite well.
7:38:47 PM
CO-CHAIR SADDLER inquired whether the Sakhalin and Pearl
projects had single players or partners. He said he is asking
this question in an effort to know whether it was the absence of
partners that led to the cost overruns.
MR. TSAFOS explained that the Pearl gas-to-liquids project went
from the standard practice project of 30,000 barrels a day to
140,000 barrels a day, so it was really a technological overrun
rather than a project overrun. Sakhalin had some very Russia-
specific challenges. Sakhalin had a 500-mile pipeline through
territory similar to Alaska's and had many challenges for
environmental permits. The biggest challenge was stark
disagreements with the sovereign. Shell and its partners sold
the 50-plus-one share stake in the Gazprom project, Gazprom
being one of the state-owned companies in Russia, and at that
point some of the problems went away and the project was able to
progress. Speaking generally about cost escalation, he said it
can be related to global commodity factors, such as steel or
cement being more expensive. Cost escalation can also be
related to the specific country. For example, someone wanting
to build an LNG project in Papua New Guinea would also have to
build roads and infrastructure where none exist. Other times,
cost escalation can be a factor of competition for laborers.
For example, Australia has a large number of mining and LNG
plants competing for the same labor.
7:43:29 PM
REPRESENTATIVE JOHNSON calculated that under the [yellow] bar
scenario [no TransCanada, 70/30 debt/equity split] the state
receives a 15-16 percent return on investment. He further
calculated that under the red bar scenario [TransCanada and 7/30
debt/equity split] the state receives a 13 percent return on
investment. He said he wants "to ask Representative Hawker's
question again."
MR. MAYER responded that a very important point is being raised,
which is the basic nature of fixed claims. Fixed claims can
come from debt on the project or fixed claims can come from
participation of a partner that takes a tariff. It is a bigger
impact with a partner that takes a tariff, like TransCanada,
because the implied financing cost is a little higher. The
basic nature of fixed claim on the project cash flow is that
when prices are low, and revenues are lower than anticipated,
the effect of that change is amplified because someone else has
a fixed claim on the project cash; thus, the relative movement
is borne by the state.
REPRESENTATIVE JOHNSON said his basic premise is the state still
makes less money in a worst case scenario with TransCanada as a
partner.
MR. MAYER replied that the worse the scenario, the less
attractive TransCanada looks. In an optimal world there are
many reasons the state might like having TransCanada and other
reasons the state might not, but overall the share taken by
TransCanada is really very small. Definitely, however, in lower
price environments and lower utilization environments, the basic
nature of any fixed claim is that it has a disproportionate
impact when prices are low, when utilization is low, when
revenue is low in the future. That is also true, he pointed
out, when taking higher debt on the project, but that is true to
a slightly lesser extent because the cost of that debt is
slightly less.
REPRESENTATIVE JOHNSON remarked he looks forward to enalytica's
future slides, but he remains unconvinced.
7:46:29 PM
CO-CHAIR SADDLER requested further elaboration of the term
"fixed claims."
MR. MAYER answered the basic idea is that the state, as an
equity holder in the project, has an entirely variable claim on
the project cash flows. When the project does well and rakes in
lots of cash, the state rakes in lots of cash; when the project
does poorly and has very little cash, the state takes only a
little bit of cash. An entity that is not an equity holder but
that loans money to the project or to the state, or an entity
that is a pipeline company that has a tariff, is entitled to a
known fixed amount of money each year into the future. That
fixed claim is a small percentage of the overall total project
when times are good and there is lots of revenue, but when times
are bad and there is substantially less revenue, that fixed
claim takes up more and more of the total.
7:47:34 PM
REPRESENTATIVE HAWKER understood the point of the chart is to
show that these projects never turn negative once started.
However, he said, it is still relevant to legislators as to how
much the state is going to get in a negative situation. He
further understood there is not much difference [in the effect
on revenue] between the state choosing to do a debt/equity basis
without TransCanada or a debt/equity basis with TransCanada.
Regarding a systemic low market price environment of $7, he said
the Alaska LNG Project would be a non-starter. However, he
pointed out, it could be possible to have the project get as far
as being sanctioned or final investment decision with a 25
percent increase in capital expenditure and/or sub-utilization
once the project comes into operation. He asked whether it
would it not be more realistic for members to instead be
considering a chart that shows only increased construction cost
and sub-optimal utilization, with no decrease in market price.
MR. TSAFOS responded enalytica will be breaking the three risks
down as per Co-Chair Saddler's request. He concurred that, if
at the point of final investment decision, the sales price is $7
the project would not be sanctioned. However, he said, that is
not really the risk. The risk is that the project is sanctioned
and four years later the price of oil crashes and the price of
gas drops to $7. The state is basically taking a 25-year bet
because it is going to be 5 years before the project comes
online and then has to run for 20 years after that.
7:50:36 PM
CO-CHAIR FEIGE inquired whether that bet is being taken given
that the sales price is locked in at the start with a marketing
contract, which is before the final investment decision.
MR. TSAFOS replied that if the contract is written as things are
in today's world, it will be linked to oil so that the gas price
will go up and down together with the price of oil. How much
the gas price goes up and down will be known at the time of
signing the contract, but the price of oil will not be known.
As enalytica has explained in the past, the state is not taking
on price risk in the conventional way of thinking about oil
price risk, which is that if a new supplier starts selling gas
into Asia for $10 it will not matter for the state because the
state already has its contract and price. Instead, the state's
contract price is going to be indexed to something. In Asia
today that something is oil. So if the price of oil goes up,
the state's gas price will go up, and if the price of oil goes
down, the state's gas price will go down. There are ways in
which the state can limit what that high number and what that
low number may be. The state might be able to say that because
$7 looks so bad it does not want the price to ever go below $10.
The buyer may agree to that as long as the state also agrees
that the price may never go above $15, because that is how the
trade works. The state will absolutely be taking on price risk
if not selling at a fixed price. The state will understand what
that relationship, that exposure, looks like before it makes a
decision; and the state can also take measures to reduce its
exposure by giving some upside to protect against the downside.
7:53:36 PM
REPRESENTATIVE KAWASAKI asked whether marine transportation is
included in the estimated costs of $45 billion, a $4 billion gas
treatment plant (GTP), and $3 billion upstream.
MR. TSAFOS answered marine transportation is not in the total of
$49 billion. The reason it is excluded from these calculation
is because sometimes the buyers arrange the transportation and
sometimes the sellers, and sometimes the seller builds its own
ships and sometimes the ships are leased. A number of things
will be discussed during the contract bid; if the state decides
to build its own ships it would probably look at ordering the
ships around 2020.
MR. MAYER added that there is, instead, a tariff subtracted from
the revenues; the cost of shipping is netted off the cash flow.
7:54:50 PM
REPRESENTATIVE KAWASAKI requested the committee be provided a
chart that models a higher capital expenditure, given the
overrun examples of TAPS and other countries. Regarding a
utilization of 80 percent and the state as sovereign possibly
taking some gas for in-state use, he asked when the best time is
for making that decision. He asked whether any of the other
partners might decide to sell in-state.
MR. TSAFOS responded utilization could be 100 percent and the
Alaska market still be flooded, so it is not about whether
Alaskans are or are not getting gas. For example, Egypt could
develop fields that produce seven million tons and build a
facility that exports five million tons and have two million
tons going to the domestic market. Then Egypt has a revolution
and the government decides to push gas to the market, so now
five million tons go to the domestic market and two million go
to export. Another example could be a country producing seven
million tons equivalent that goes down to five. No sovereign
would decide to export all that and deliver no gas to its
electric utilities; the sovereign would at least prioritize the
domestic market. This does not imply that supplying Alaskans
with gas is going to lead to a lower utilization. The structure
and the size of the Alaska project embeds a cushion of Alaskan
gas, so it would be very hard for the state to divert so much
gas as to actually hurt the utilization of this project, with
the exception of perhaps an extremely cold winter where for a
month there may be less utilization because of having to meet
in-state demand. He clarified that what he was suggesting
earlier is that when looking at utilization and why it may
deviate from 100 percent, domestic gas diversion tends to be a
pretty common reason. However, that would not be a number one
reason for concern in Alaska.
7:58:37 PM
REPRESENTATIVE TARR said she would like to add tax as gas (TAG)
and royalty-in-kind to the topic of oil linked to gas prices.
She surmised that in a low price environment the state would
receive more revenue by taking production tax based on per-unit
volume than it would by taking tax as gas. She asked how this
could be evaluated in a stress case scenario.
MR. MAYER replied it is an excellent question and enalytica has
modeled and presented this to the committee previously. While
the aforementioned phrasing of the question is what one would
intuitively think, in reality it is exactly the opposite, which
is the reason why modeling is done. It comes back to the idea
of fixed claims on cash flow. When last before the committee,
enalytica presented a working of production tax and royalty to
compare them to oil and expressing everything in oil equivalent
terms. He posed a scenario of $100 for oil price, $10 for
combined total tariff on transportation for TAPS and marine
tariff combined, which results in $90 at the wellhead on the
North Slope. In a world of gas and LNG, that oil price of $100
would lead to about $80 per barrel of oil equivalent of LNG
delivered to Tokyo. Because the midstream is so much of this
project, the tariff would be more like $60-$66 than $10. The
result is about $15 in value at the wellhead and a small
movement in oil price would completely wipe that out. The state
is the shock absorber, everything else is fixed to get its fixed
claim of the value. It is correct that if the state did reach a
circumstance where project cash flows are actually negative,
then there is a weakness that comes from being in-kind because
with royalty the state would at least effectively have a floor
of zero, although zero is not strictly true when it comes to
profit-based production tax on oil. In a truly catastrophic
world, the state could actually lose money, but short of that,
overall in low-price cases the state does as well or slightly
better at high prices. If it were certain that the price of LNG
was going to stay where it is for the next 20 years and it was
possible to have a project through the in-value structure, then
the state would probably rather take in-value. But, if it is
thought that the price could go down to $10/MMBTU, value to the
state looks much better in the equity and in-kind world than in
the in-value taxing world because the state is not the shock
absorber absorbing all of the price risk while the midstream
gets its fixed cut, instead everyone rises and falls together.
MR. TSAFOS added that another way to think about it is $7 in
Japan and taking out transportation, liquefaction, pipe, and gas
treatment plant. This would leave the state with less than
zero. Royalty and tax would be multiplied by zero so there is
nothing left, which is what Mr. Mayer was describing. [As the
project is proposed], the state would still make some money if
prices go low because the state is not taking what is left over
after subtracting these other things, but rather the state has a
piece of all these things.
8:03:52 PM
REPRESENTATIVE TARR inquired whether that would be true in all
four of the scenarios being talked about. She surmised it would
be true in the scenarios involving TransCanada because of its
fixed claims.
MR. MAYER answered the fixed claim he is talking about is the
implied tariff of not being an equity holder, not the
involvement of TransCanada -- having value solely at the
wellhead that is determined by subtracting a tariff, whoever and
however that is calculated. The other uncertainty in this case
is transparency in how that tariff is calculated, particularly
on the midstream. When the state takes value solely by taking
tax or royalty in-value at the wellhead, the variable claim in
the system and everything else gets its fixed share of the value
because the state subtracts that fixed amount before it assesses
its value.
CO-CHAIR FEIGE understood that if the state is taking its
royalty and taxes in-kind, then as long as the pipe is putting
out something the state is always getting something. If the
state takes in-value and the price gets too low, then by the
time all the costs are pulled out the state could go negative.
MR. MAYER [indisc.] zero.
MR. TSAFOS added it is the equivalent of $10 TAPS and an oil
price of $9.
8:05:56 PM
REPRESENTATIVE SEATON noted the project cost estimate has been
presented as $45-$65 billion. But in these slides, he observed,
the depicted stress case cost is $61 billion. He therefore
asked whether $61 billion is a reasonable stress case figure.
MR. MAYER responded that when running the economics on this
project, he and Mr. Tsafos struggled to see an initial case of
the cost being in the range of $65 billion and the project being
sanctioned at that range. The project is attractive at $50-$55
billion, so enalytica added the 25 percent on top of that.
8:07:09 PM
MR. TSAFOS moved to slide 12, "Stress Test: Restricted vs.
Unrestricted Revenues," explaining that the three sets of bars
on the graph depict the total income, total income minus the
permanent fund, and total income minus the permanent fund and
minus property taxes due to municipalities. He pointed out that
the revenue to the state is positive, but once the money is
taken out for the permanent fund and the property taxes the
state would have to put in an approximate $63 million [under the
scenario of TransCanada 100 percent gas treatment plant and pipe
and 7/30 debt/equity split].
8:08:37 PM
MR. MAYER addressed slide 13, "SOA Needs to Carefully Weigh Key
Questions," noting this slide was presented when enalytica was
previously before the committee. The slide is a non-financial
standpoint of TransCanada's involvement as written in the
Memorandum of Understanding (MOU) and it compares [four]
possible ways of doing the project. During that presentation,
enalytica said the state clearly would not want to have a
project that is purely a producer project with no interest by
the state or by a third party. This is because of the question
of alignment and possibilities for disputes over where value
could be, and, in particular, when it comes to third party
expansion and wanting to have someone in the mix that has a
clear interest or that makes money from expansions and pursuing
expansions. A project consisting solely of the existing
producers would be executed very well, but the producers would
not have a clear and compelling interest in wanting to expand
the project to accommodate other people's gas. The producers
are companies that make money by moving molecules to market, not
by moving other people's molecules through a pipeline. In a
scenario of the producers with the State of Alaska, which is the
world anticipated by the Heads of Agreement (HOA) without the
MOU, there is better alignment between the producers and the
state in terms of the question of possibilities of dispute over
tariff and so forth. In this scenario there is a question about
what things would look like at a later date for expansion. This
is because all of the impetus would be on the state to pursue
expansions either by itself or by a producer trying to bring in
a pure midstream company as a partner to pursue those expansions
assuming that the other producers were not interested in
undertaking expansions.
8:11:12 PM
REPRESENTATIVE SADDLER requested an explanation of the x marks
and check marks on slide 13 and whether the lines and text on
the chart align with the charts that follow.
MR. MAYER replied there is no correlation with the charts that
follow; it is a summary. The check marks represent positive
aspects, x marks represent negative aspects, and question marks
represent things that are indeterminate or difficult to weigh.
8:12:00 PM
MR. MAYER resumed his discussion of slide 13, reiterating it
looks at the non-financial aspects of the MOU and bringing
TransCanada into the pipeline and gas treatment plant. He
reiterated that in a scenario of producers only there would be
clear ability to execute the pipeline and gas treatment plant
without an additional dedicated midstream party. The question
becomes one of ability to execute future expansions to get other
people's gas in the pipeline and encouraging other people to
explore the North Slope. Another question asked for each of the
four scenarios is whether there is a cost and a benefit
associated with continuity and momentum in this project and, if
so, what are the potential costs of postponing the project or
not going ahead with what is being proposed. In looking at the
scenario of producers, State of Alaska, and TransCanada as
suggested in the MOU, enalytica saw many of the same strengths
seen in the scenario of producers and the State of Alaska, but
also seen are substantial benefits in third party expansion and
ability to execute on those third party expansions. In the
scenario of producers, the state, and a third party other than
TransCanada, the primary difference is the question of alignment
of interest and disputes around tariff and allocation of value,
and what the tariff would be if the third party is not
TransCanada. The answer is unknown and can only be found out by
going to a competitive bid. In this last scenario there is also
the question of whether continuity and momentum would be
maintained with a third party that is not TransCanada.
8:14:41 PM
MR. MAYER said an important question the state needs to weigh is
the exit from the Alaska Gasline Inducement Act (AGIA) process
if the state does not want to go down the path of the MOU and
what compensation the state might have to pay and what
intellectual property the project would retain. A second
important question for the state is whether the HOA process in
the broader project framework might slow down if there was
substantial dispute around the midstream. A third important
question is having either a different midstream player or an
open competitive process and whether this process would deliver
better terms than those under the MOU. Related to that is the
scarcity of bidders involved in the AGIA process and, in
particular, the very few that actually made qualifying
competitive bids. The question is whether that was
representative of the industry's interest in an Alaskan pipeline
in general or whether it was specific to what happened then, and
might there be more interest today. The last key question is
the possibility of a better tariff being offered under a
competitive bid process and how to weigh the possible, but very
uncertain, benefit and possible cost against the questions of
benefits that come from momentum and the potential costs of
dissolving AGIA. These are questions that need to be considered
further in regard to the non-financial aspects of TransCanada's
participation.
8:17:01 PM
MR. MAYER turned to slide 14, "TransCanada Tariff Offer Within
Market Norms," to begin addressing the questions of how much
value of the overall project does TransCanada take up and
whether that is a good deal. The first question is about what
is proposed under the MOU in terms of tariff and how that
compares to trying to bring in a different third party through a
competitive process. The best way to begin understanding the
answer to this question is to benchmark against market norms.
To do this, enalytica analyzed all of the 2012 data presented to
the Federal Energy Regulatory Commission (FERC) on Form 2, which
is the annual report that FERC regulated U.S. pipeline companies
are required to submit. The cost of debt, cost of equity, and
the relative share between the two are regulated by FERC, and
this is what enalytica is presenting in the charts on slide 14.
The left chart is the capital structure for proportion of debt
to proportion of equity. The right chart is the cost of debt,
the cost of equity, and the overall weighted cost of capital.
Mr. Mayer explained the charts consist of "box plots," which are
the way of showing the distribution of a variable. The vertical
lines above and below the boxes are the maximum and minimum of
the dataset. In the chart for capital structure, it can be seen
that the proportion of debt varies from no debt to 68.1 percent
debt. Between those two numbers are the box plots which depict
the twenty-fifth percentile, the median, and the seventy-fifth
percentile. The bottom quarter of all data observations are
below the level of 34.7 percent debt in the capital structure.
The bottom half, or those observations below the median, are
below 40.2 percent debt in the capital structure. The bottom
three-quarters are below 46.7 percent debt in the capital
structure. The top quarter, or the highest ratio of debt in the
capital structure, is between 46.7 and 68.1 percent.
8:20:16 PM
CO-CHAIR SADDLER understood the top line of the box is three-
quarters and above, the middle line is 50 percent, and the lower
is 25 percent.
MR. MAYER answered yes, clarifying that this is in terms of
proportion to the total sample that is being represented in each
of those areas.
CO-CHAIR SADDLER inquired about the source of the data.
MR. MAYER responded it was the most recent year available of
FERC-reported data that pipeline companies regulated by FERC
report on FERC's Form 2, and opined that the data year was 2012.
CO-CHAIR SADDLER offered his understanding that the chart is for
comparing the costs for the proposed Alaska project versus other
FERC-regulated projects.
MR. MAYER replied yes. In further response, he said the overall
dataset was all of the Form 2 reports available, which were 45-
56 observations for those companies that submit a Form 2 and
that on that form report cost of debt and cost of equity. He
further explained that Form 2 is a regulatory filing with FERC
that contains a wealth of information about pipeline companies
and includes on one page the cost of debt and cost of equity.
8:22:09 PM
REPRESENTATIVE HAWKER inquired whether the charts on slide 14
are relevant to this discussion given the slide's title is about
TransCanada's tariff being within market norms. He said he is
unsure that a FERC pipeline is comparable to this pipeline
because everything heard to date is that this will not be a FERC
regulated pipeline. This pipeline is essentially one big gas
gathering line feeding a proprietary industrial process, not a
classic FERC pipeline with multiple customers that crosses state
borders. It would seem reasonable that should the state become
involved in developing proprietary gathering lines that there be
a tariff structure that is not necessarily representative of an
average FERC-type line. He asked what the grounding is for
using a FERC regulated pipeline to benchmark this project that
was presented as having no desire to be a FERC regulated
pipeline.
MR. TSAFOS explained that this reflects data availability and
the market. There is no intent for FERC data to be shown
because this pipeline will be regulated by FERC. TransCanada
has made an offer to charge a tariff to the State of Alaska that
is based on 75 percent debt and 25 percent equity, cost of
equity 12 percent, cost of debt 5 percent, plus a rate tracker
to the yield of the U.S. Treasury. The question is how to
assess this offer. One way is to go to bid and see if there is
a better offer. The other way is to look at what pipeline
companies typically make, what the market is for these things.
Is there a market for an 800-mile pipeline in Alaska? No,
because no one has built one yet; so there is absolutely unique
character to this project that cannot be benchmarked as there is
not anything to benchmark against. While there may not be other
pipelines of this length to compare, there is a market for
building pipelines and charging companies to transport gas
through them and that market can be reviewed. Does this mean
that the offer on the table is the best possible offer? The
analysis is how that offer compares relative to what pipeline
companies are expected and able to make in a market that is
regulated similar to the U.S. This analysis is not intended to
say that FERC is going to regulate this pipeline; it is to use
benchmarking instead of a completely arbitrary analysis. Slide
15 reflects rates of return (ROE) for FERC versus the National
Energy Board (NEB) Canada, as TransCanada is a Canadian company.
It is not because that number is the relevant price, but it is
to give members information to put in context for this deal.
8:27:01 PM
REPRESENTATIVE P. WILSON requested further explanation to the
charts on slide 14.
8:27:41 PM
CO-CHAIR FEIGE drew attention to the line between 0 percent and
34.7 percent on the left chart, explaining that if there were
100 projects, 25 of those projects would fall within that range.
The next 25 projects would fall between 34.7 and 40.2 percent.
The next 25 projects would fall between 40.2 and 46.7 percent
and the final 25 projects would fall between 46.7 and 68.1
percent. The chart shows the distribution of these projects.
MR. MAYER confirmed Co-Chair Feige's explanation is correct. In
further response to Representative P. Wilson, he confirmed that
this same principle was used for the box plots on the two charts
on slide 14.
8:28:29 PM
MR. MAYER continued his review of slide 14, noting that debt and
equity on the left chart are directly proportional to each
other; if there is 40 percent debt there is by definition 60
percent equity. The MOU proposes a 75/25 debt/equity split. It
can be seen from the left chart that 75/25 is out of the sample
in terms of U.S. FERC regulated pipelines; the state is at a
higher level of debt relative to equity than anything that has
been reported to FERC through [Form 2].
8:29:16 PM
REPRESENTATIVE HAWKER noted it had been said earlier that there
is nothing to benchmark this project against, yet these charts
are benchmarking this project against FERC regulated pipelines
in the Lower 48. He expressed agreement with enalytica's
question of whether TransCanada's offer makes sense, but argued
that the real decision and the real benchmark are comparing the
TransCanada offer to what else Alaska might be able to
accomplish, irrelevant of what goes on with FERC regulated
pipelines in the Lower 48. Basically, it is what the state
could come up with in the open marketplace for a debt/equity
structure. He said this chart bothers him, suggesting it might
actually point legislators in the wrong direction when comparing
FERC regulated projects to a completely unique, stand-alone
Alaska project that has nothing to do with FERC regulation.
8:31:13 PM
MR. MAYER, in response to Representative Hawker, said there were
two questions for how this compared: what we could do on our
own, or if we tried to seek a different partner through a
competitive process. He said that it did not help to answer the
first question for comparison if the state went ahead on its
own. He explained that the slide aimed at the second question
to how this might compare with other offers if there were an
open and competitive process. He said there was not a perfect
answer without a competitive process, as it could be better or
it could be worse. He offered his belief that to establish
whether this was a direction to pursue, the first question was
to ask for the available data points for the capitalization
structures and cost of debt and equity for other pipelines.
These would give a basic idea for the reasonableness of the
offer, as any other bidding company would also be subject to
either FERC or NEB (Canadian) regulations and would have certain
standards for cost of debt and cost of equity.
8:32:51 PM
MR. TSAFOS added that he accepted the limitation to the utility
of the chart. He directed attention to the weighted cost of
capital, and theorized that the maximum for all the U.S.
pipelines in this analysis was 5, in comparison to the weighted
cost of capital from TransCanada of almost 7. He pointed out
that they were trying to figure out how the offer on the table
compared to other pipelines in the world for expected and
attained returns and capitalization structures. He acknowledged
that the utility of the chart was somewhat limited, although
there would not be a clear answer unless there was another
competitive bid.
8:34:37 PM
REPRESENTATIVE HAWKER asked why there was a comparison with all
the FERC pipelines, instead of only comparing the benchmarks of
all the other TransCanada projects.
MR. MAYER offered to discuss data points relevant to the
TransCanada projects.
MR. TSAFOS, in response to Representative Hawker, read from
Section 9, page 121, of the recently published TransCanada 2013
annual report. He spoke about a recent decision by the National
Energy Board (NEB) of Canada, which allowed a rate increase for
the Canadian Mainline pipeline, one of the largest in Canada.
This decision established a return on equity of 11.5 percent on
a deemed common equity of 40 percent. Moving on to page 122, he
relayed that another settlement with the National Energy Board
of Canada had established a 10.1 percent return on equity on
deemed common equity of 40 percent. He directed attention to
the A & R Pipeline in the U.S., owned by TransCanada, which
reported a 9 percent cost of debt and a 12.25 percent cost of
equity. He declared that the challenge was to distinguish the
difference between a long established pipeline and a new
pipeline with risks similar to an Alaska pipeline. He explained
they offered all the data, instead of limiting to only
TransCanada, as TransCanada invested in Canada, the Lower 48,
and Alaska.
8:40:00 PM
REPRESENTATIVE SEATON asked how dependent the weighted cost of
capital was to the "75 - 25 debt equity."
MR. MAYER replied that it was very dependent, and using the
parameters from the MOU, the 12 percent cost of equity was
multiplied by 25 percent, the 5 percent cost of debt was
multiplied by 75 percent, and these totals were then added
together for the 6.5 percent weighted cost of capital.
REPRESENTATIVE SEATON referenced earlier discussions which
stated a goal of 70 - 30 on pipeline issues, as it would save
money, although there were difficulties in those negotiations.
He asked if 75 - 25 was considered very good.
MR. MAYER expressed his agreement that this was very good for
the pure debt equity split, and he pointed out that getting
below 70 percent debt was unusual and aggressive. He noted that
there could be separate discussion for the cost of debt and the
cost of equity, but for the pure capital structure used, he
declared that 75 - 25 was quite aggressive.
CO-CHAIR FEIGE asked if the tariff was based on the 75 - 25
equity split, in this case. He asked about the effect on the
actual rate of return for TransCanada if they could not borrow
75 percent of their commitment.
MR. MAYER, in response, said that there were two ways to answer.
The first was to explain that structure and cost of capital for
rate making purposes was intended to have some bearing on the
actual structure and cost of capital of a pipeline company,
although, to some extent, it was a regulatory fiction. He
pointed out that there could be a difference between the allowed
structure and the allowed cost of capital in comparison to the
actual underlying costs which the company used. In the majority
of cases, although there was a 60 - 40 structure, many companies
were able to finance at 70 percent above debt and maintain their
cost of equity, which would increase the actual return on equity
versus the regulatory allowed return on equity. He noted that
although most tariff setting did not involve more than 70
percent debt, it was possible to raise that much debt even with
the limits and risks for higher amounts. He pointed out that
the lower percent of debt would reduce the actual return on
equity. He declared that the financing risk was limited by an
option to terminate in the MOU, if satisfactory financing could
not be arranged. In this circumstance, the State of Alaska was
still required by the MOU to repay the development costs, with
7.1 percent interest.
8:44:51 PM
MR. MAYER resumed his review of slide 14, "TransCanada Tariff
Offer Within Market Norms," noting that to the extent that this
was a useful comparison, there was a substantially higher level
of debt in the rate setting capital structure, which was an
advantage to the state. He said that an overall review for cost
of equity, cost of debt, and the weighted average cost of
capital revealed terms toward the bottom of "what was out
there." Directing attention to the weighted average cost of
capital with a median of 9.8 percent [graph on bottom right of
slide], the lowest data point in this sample was 6.5 percent and
the resulting cost of capital under the MOU during the period of
pipeline operation, not including the time of development and
time for future expansions, would be 6.75 percent, which was at
the lowest end of the sample. He allowed that it could be
useful to make comparisons of FERC regulated pipelines with the
allowable returns, the weighted cost of capital, and the returns
on equity under the NEB in Canada.
8:46:20 PM
MR. MAYER moved on to slide 15, entitled "FERC ROE HISTORICALLY
EXCEED NEB (CANADA) ROE". He pointed out that the return on
equity allowed by FERC was above those historically allowed by
the NEB. He directed attention to the FERC settlement cases,
the end result of a dispute. He stressed that, to the best of
enalytica's knowledge, most of the sample projects had a 60 - 40
debt equity split. He explained that an 8.5 percent return on
equity would result in a 6.4 percent [cost of capital], still
near the 6.75 percent range previously discussed. He shared a
caveat that Canadian pipeline companies had been fiercely
contesting these very low returns on equity in recent years. He
directed attention to the NGTL system in Canada, which had a
settlement with the shippers, approved by the NEB, which raised
the allowed return on equity to 10.1 percent. He reported that
the Canadian Mainline pipeline had a return on equity revised
upward by the NEB to 11.5 percent. He said that these more
recent returns reflected a much closer return to those allowed
by FERC, and he noted that both of these projects had a 60 - 40
percent debt to equity ratio.
8:49:57 PM
MR. MAYER addressed slide 16, entitled "SOA EQUITY LEADS TO
HIGHER GOV'T TAKE ON AVERAGE" and referenced the overall shares
of cash flow to the State of Alaska. He referred to an earlier
question by Representative Tarr for the comparison of overall
value to the state if the state was a taxing entity for royalty
and value at the wellhead versus having a share of gas and
equity. He compared the overall split of the project cash flow
for in value versus in kind with 20 percent and 25 percent
equity as entailed by the HOA. If it was guaranteed that the
higher prices in Asia would continue, then there was an argument
for the state project to remain with in-value, as long as the
price remained high. However, he pointed out that as the price
declined and the tariffs remained static, the revenue would also
decrease quite dramatically. He acknowledged the benefit to a
higher share of equity, especially an equity share that was
proportionately better across the prices to an in value share.
8:53:09 PM
CO-CHAIR SADDLER asked if the graph reflected property tax and
corporate income tax.
MR. MAYER replied that the graph depicted everything, including
cash flows to the state from being an equity participant with
saleable gas.
CO-CHAIR SADDLER directed attention to the graph for in value,
and asked if that included production tax value, corporate
income tax, and royalty.
MR. MAYER expressed his agreement.
CO-CHAIR SADDLER asked for clarification for what was included
on the remaining two graphs.
MR. MAYER explained that the two other graphs also included
revenue to the state from the sale of LNG, net of the costs,
plus property tax and state income tax.
MR. TSAFOS clarified that the graphs were adding up the annual
revenues presented earlier and included the other partners.
8:54:25 PM
REPRESENTATIVE SEATON asked for clarification that the graphs
reflected the decline of the percentage of revenue, noting that
the state only had 25 percent of the gas sales.
MR. MAYER explained that this was a proportion of gas flow
rather than revenue, although, in absolute terms, the total was
also dropping. When the price dropped, the cash flow to all the
parties would also drop.
REPRESENTATIVE SEATON asked for clarification that with a price
increase, there was a percentage drop.
MR. MAYER expressed his agreement, stating that the overall
shares of cash flow were highest in the low price environment.
8:55:54 PM
MR. MAYER directed attention to slide 17, entitled "TC'S SHARE
OF CASH IS HIGHEST AT LOW PRICES," which described the equity at
25 percent and compared it to two of the MOU options. The first
was for the no buyback option and the second included the
exercise of the buyback option by the State of Alaska.
CO-CHAIR SADDLER asked if the definition of the TransCanada
share of cash included cash flow, all the revenue going through
the pipeline.
MR. MAYER explained that this was the percentage of net cash
flow of the entire project over its lifetime. He pointed out
that the net cash flow, net of all costs for developing and
running the project, could go to one of the three producers, the
federal government through federal income tax, the State of
Alaska, or TransCanada as a tariff.
CO-CHAIR SADDLER asked for an estimate of the three producers'
share of the net cash flow over the life of the project, net of
all expenses.
MR. MAYER said that, without TransCanada, and its 25 percent
equity, there would be 40 - 50 percent of the total project
value to the State of Alaska.
8:58:33 PM
CO-CHAIR FEIGE asked what percentage of the value would go to
debt service, if the state had to borrow money without the
TransCanada option.
MR. MAYER replied that this would be better addressed in
upcoming slides, but it would be expected that the state would
have a 4.5 to 5.5 percent cost of debt, as opposed to the 6.75
percent weighted average cost of capital. He stressed that the
weighted cost of capital included a 12 percent return on equity,
and was an after tax return. He suggested that there would be
"an effective cost of somewhere in the 8's" under the
TransCanada option, as tax was not included in the 6.75 percent
weighted average cost of capital.
9:00:43 PM
REPRESENTATIVE HAWKER, addressing the cost of gas on the graph,
mused that $8/MMBTU was a project non-starter and consequently
an irrelevant number; whereas, the $18/MMBTU was a higher end
benchmark. He reflected that the difference between no
TransCanada and the TransCanada involvement with no buyback only
projected an increased cumulative return to the state of a
couple percent. Moving on to the graph of TransCanada with the
buyback, he surmised that the return was only one percent higher
to the state. He opined that a state buyback of ownership, with
its commensurate risks and costs, would only have a cumulative
return of a fraction more while assuming all the risk. He asked
if it was possible to see quantifiable numbers, as this appeared
to be at odds with his perception of the return on an annual
basis. He questioned the additional risk for such a small
return.
MR. MAYER, in response, said that these were the same numbers as
expressed previously. He offered his belief that there were two
fundamentally counter intuitive issues relative to the HOA and
the MOU. First, the assumption for taking gas in kind along
with a 25 percent project share actually allowed the state for
between 40 - 50 percent of the project value, as the state was a
project participant and a sovereign entity that actively charged
state income tax and property tax from the other participants.
He pointed out that the municipalities were included in the
analysis as part of the state as a whole. Regarding
TransCanada, he pointed out that, although a 25 percent share of
the project to TransCanada was half the capital value of the
project, there were different ways for each party to generate
value through the project. To generate full value, it was
necessary to have an equity stake in the project as well as gas
and the revenues generated from its sale. He pointed out that
it was possible to have a tariff that only allowed for the
initial outlay of capital, with no net cash flow return for debt
or equity. He reported that the tariff structure on the chart
allowed for a return on debt and a return on equity, which
provided a portion of the project cash flow. This portion was
greater at low prices because it was a fixed claim on the
project cash flow, so it represented more at low cash flow.
However, in a higher price scenario, assuming the state
exercised its buyback, it would be 1 percent of the total
project cash flow. In this same scenario, assuming the state
did not exercise its buyback, it would be closer to 2 percent of
the total project cash flow. He reported that this could
increase to 7 percent if prices were lower and the state did not
exercise its buyback. He expressed agreement that the overall
share of total value created on an undiscounted basis over time
did not take a big portion of the value.
9:06:24 PM
MR. TSAFOS drew attention to the graph on the far right of slide
17, "TC [TransCanada] with Buyback," and explained that,
although there was payment of a tariff to TransCanada in
addition to the sales price for its share, there was not any
payment for the gas that the state shipped using its own
capacity. He pointed out that this lowered the realistic
tariff, and that it was necessary to place the relative cost of
these components in perspective. As the tariff was a fixed
amount, the higher the cost of the gas, the lower the tariff as
a percentage.
9:08:20 PM
REPRESENTATIVE HAWKER relayed that it was necessary to remember
that the gas going through the pipeline was the state's royalty
and tax. He suggested that the graphs include a straight bar
line illustration which would remain a constant no matter the
price of gas. He declared a need to evaluate the gain versus
the assumption of risk with the addition of TransCanada as a
business partner. He opined that the chart revealed "very
marginal, cumulative, ultimate, hypothetical cash returns over
the project life." He asked for the number of years this was
projected.
MR. MAYER, in response, said it was 25 years.
REPRESENTATIVE HAWKER declared that these returns were marginal
for the assumption of a great deal of risk with state ownership.
MR. TSAFOS asked what Representative Hawker was comparing to
state ownership.
REPRESENTATIVE HAWKER referenced the charts on slide 17, and
compared the bar depicting $18/MMBTU on each chart. He said
that the percentage of cumulative cash flows to the state over
the project life was only minimally increased by a partnership
with TransCanada versus having no equity position. He pointed
out that there was risk with an equity position.
9:10:27 PM
MR. MAYER acknowledged the small portion of royalty that was
foregone with TransCanada owning all the equity. He expressed
disagreement that there was not any risk without equity;
reporting that companies accepted fixed, highly regulated
returns as they were low risk, low reward, and low return
relative to other investments. He shared that a pipeline would
have a tariff, and that according to the MOU, there was very
little risk for TransCanada between now and the final investment
decision (FID), as they were able to "walk away at a number of
points and be fully reimbursed." He stated that TransCanada
would need a substantial outlay of capital at some point to
build the pipeline, at which time they would charge a tariff
proportional to the capital outlay. He said there were benefits
for TransCanada involvement, including being expansion capable
and expansion minded as a partner during negotiations with the
producers. He noted that TransCanada did absorb financing risk
if not able to raise the 75 percent debt, even though the state
did bear a lot of risk as it paid the shipping tariff.
REPRESENTATIVE HAWKER responded that this was presuming the
state passed enabling legislation as it would not have any
review for the MOU which involved the indemnifications for
TransCanada insulating them from risks. He acknowledged that
the state would keep the risk, however the choice by the state
was whether or not to own a "chunk of the pipe." He offered his
belief that the chart on slide 17 reflected that ownership of
this "chunk of the pipe" offered a minimal ultimate return for
this additional risk.
9:14:00 PM
MR. TSAFOS expressed agreement that what the state would
transfer to TransCanada was not that high. He pointed out that
the assumption of risk was a fixed claim, and that the tariff
paid to TransCanada was fixed to an agreed upon tariff
structure. He reiterated that the overall percentage share of
the tariff was lower at higher gas prices.
REPRESENTATIVE HAWKER offered his belief that $8/MMBTU would not
result in a successful project for the state.
MR. MAYER, in response to Representative Johnson, directed
attention to slide 18, entitled "'IN KIND' W/EQUITY OFFERS MORE
DOWNSIDE PROTECTION." He explained that this reflected the
absolute value for undiscounted, cumulative cash flows over the
project life as a taxing entity compared to an equity
participant with gas. He directed attention to the three charts
depicting the State of Alaska, Producers, and Federal
Government. He reported that an "in value" structure was
preferable if there were higher MMBTU prices for the entire 25
year span of the project, although value fell very quickly as
the prices dropped because of the fixed claims charged. He
noted that an "in kind" structure gained more value with greater
participation, as a 25 percent share was substantially
preferable to a 20 percent share. He noted that this was
limited to the share amount that could be financed for capital
expenses and the share size to which the producers would agree.
He reported that the HOA had anticipated a share range of 20 -
25 percent. He pointed out that the producers had greater
returns for the "in kind" structure with higher LNG prices,
however with falling prices, the value fell quickly.
9:19:18 PM
MR. MAYER moved on to discuss the comparative value for the
state with a 20 percent share versus a 25 percent share, slide
19, entitled "LIMITED VALUE FOREGONE UNDER TC W/BUYBACK OPTION".
He described the left chart as being the State of Alaska total
cash flows, comparing the range of value for 20 percent equity
share and no involvement with TransCanada, 25 percent shares
with the TransCanada buyback, and the sum of the total cash
flows from the project undiscounted over time. The right chart
compared the same flows, but with a 10 percent discount rate for
net present value. The idea for this was to look at the capital
outlay required to build the project, and the benefit for
financibility. The outlay after paying the debt equity ratio of
70/30 was about the same in both the aforementioned 20 percent
and 25 percent examples, and if just comparing this outlay, the
choice would be for the 25 percent share with TransCanada. He
pointed out that there was foregone value by not having the full
25 percent. He reported that the difference was the greatest
when viewed on an undiscounted basis, simply for total cash
flows. When there was a discount for the upfront cost by
TransCanada, which emphasized that they had the majority of this
cost, the difference was much smaller. He offered an example of
a $15 MMBTU price, with a $75 billion value to the state for the
life of the project, and he estimated a loss of about $5-6
billion to TransCanada for tariff. He pointed out that the loss
to the state was about $400 million after reviewing the effect
of the reduction to the net present value discounted at 10
percent.
9:22:14 PM
MR. MAYER pondered the different ways to think of the non-
financial benefits with TransCanada, which included its active
role in future expansion during contract discussion with the
producers. He also reviewed the role for TransCanada as a
finance option. Although there was a marginally increased value
for the state to finance the project without TransCanada, there
was the question for the capital constraint and that resulting
loss of value. He acknowledged that there were a lot of
unknowns that may be answered further along the project, and
that there was still the option for the "off ramps" to terminate
the project agreements.
9:24:43 PM
REPRESENTATIVE SEATON, comparing slide 19 and slide 9, asked if
the difference was all because of a NPV (net present value) 10.
MR. MAYER expressed agreement, and noted that the chart on the
left was undiscounted, whereas the chart on the right reflected
the impact of the 10 percent discount rate.
REPRESENTATIVE HAWKER referenced an earlier statement by Mr.
Mayer as the cumulative take away of the entire presentation and
asked if the title of slide 19 was saying the same thing as
"there is little to be gained by us going it alone."
MR. MAYER replied that, relatively speaking, it was saying the
same thing.
REPRESENTATIVE JOHNSON pointed out that, although a few billion
was relatively small given the scope of the project, it was
"still a whole truckload of money." He referred to the earlier
discussion of non-tangible aspects for having someone at the
table to support expansion.
MR. MAYER reflected on the Washington, D.C. dictum "a billion
dollars here, a billion dollars there, pretty soon you're
talking real money."
REPRESENTATIVE JOHNSON mused about the current budget for
education relative to this money.
9:27:55 PM
MR. MAYER moved on to slide 20, entitled "OTHER QUESTIONS FOR
THE MIDSTREAM," which stemmed from the micro level detail of the
MOU. He said that it was important to be aware that TransCanada
would recoup its expenses. If the state terminated, it would
pay back TransCanada with a 7.1 percent interest rate. If the
project did not reach a final investment decision, TransCanada
would be reimbursed. If TransCanada decided to terminate
because of lack of board support or lack of financing, it would
still be reimbursed with this interest rate. He noted that
there were important questions regarding the risk versus the
reward, including control and the appropriate split. He said
that the second crucial point was whether the state would decide
to terminate the agreement with TransCanada and go for the
project alone at the time of final investment decision. He said
that the state had numerous opportunities to terminate along the
path to the project. However, the state needed to offer the
option for participation to TransCanada within the next five
years, with a provision that the cost of debt and the cost of
equity for the tariff could be negotiated based on the
conditions at that time. He opined that the decision to go it
alone should include a better understanding for these benefits,
and that there should be consideration for what determined a
good faith offer for participation by TransCanada, and how firm
was the "off ramp." He offered his belief that the final
question for the midstream should be for who benefited from and
who bears the cost for a subsequent expansion. Under the
current terms of the HOA, an expansion that raised the unit
costs of the pipeline was paid by the expansion parties and the
initial parties were not included in those costs. He said there
were many reasons to support this decision for certainty at the
time of final investment decisions. He said there was
reasonable question whether expansion which benefited the
economics of the project should include those who did not
support the expansion.
9:33:44 PM
CO-CHAIR FEIGE requested that Mr. Mayer and Mr. Tsafos address
what the revenue could look like with expansion. He offered his
belief that the pipeline would lead to "a great deal of
exploration activity" and a need to get the resource to market,
which could benefit the state. He noted that the initial
contract agreement was for 25 years, and the MOU had details
which allowed for a change of ownership, or not, at that time.
He asked what should be considered for that time at the end of
the initial contract.
REPRESENTATIVE TARR asked what to review in order to better
understand the other opportunities and options for expansion.
MR. MAYER replied that there were a range of granular options,
some of which were contemplated in the MOU and the HOA. He
stated that only two sets of parties could really bear the cost
of expansion, either solely by the parties seeking and
participating in the expansion, or by everyone.
9:37:05 PM
REPRESENTATIVE KAWASAKI referenced slide 6 regarding the mix of
debt and equity and asked whether it was necessary to have the
answers to the questions presented on slide 20.
MR. MAYER acknowledged that these questions should be answered,
although some of the questions needed to be weighed and
considered for reasonableness of risk and reward by each member
themselves, and some questions, including those regarding the
off ramps in the contract, may require legal analysis.
MR. TSAFOS said that the first two questions on slide 20 were
not legal or technical questions. The third question for
solidity of the off ramp was a legal question, and the fourth
question was one of judgment for whether the upside should be
shared but not the downside. He stated that questions one, two,
and four were facts and each person needed to determine if they
were comfortable with them, or whether it was necessary to
change them. He noted that the third question was a legal fact,
and he would not presume to offer an answer to it.
REPRESENTATIVE KAWASAKI paraphrased from the LNG key issues
[Included in members' packets] and said:
from a purely financial perspective the impact of TC's
involvement may be seen as akin to a loan, the reduce
in capital investment in the project required by the
state, and the state pays back the loan through a
fixed payment in the form of tariff, also like a loan
it increases some of the state's exposure of risk by
adding a fixed claim on the project cash flows that
must be met before the state receives its share.
Compared to other forms of debt, TC's involvement's
relatively expensive form of financing, average weight
of capital's significantly above the states own cost
of debt.
REPRESENTATIVE KAWASAKI questioned, as this was in the
paraphrased analysis of the fiscal question, what should be
done. He offered his belief that it was not a huge financial
benefit, and he asked what the state was getting from this
partnership.
MR. MAYER, in response, said that from a purely financial
perspective this was not a net benefit to the state and there
was not a significant foregone value. It was a relatively small
amount of the overall total project value. He asked if the
other benefits from the involvement of TransCanada outweighed
the purely financial cost that was relatively small in the
scheme of the overall project.
9:41:25 PM
REPRESENTATIVE SEATON addressed the fourth question, and
expressed concern with the lack of liability to participate in
the escalated costs from expansion and then an expectation for
benefits from the expansion. He asked if there were relative
terms for similar expansion projects internationally, as this
was "an unbalanced formula here if there's no exposure to higher
costs, but there's savings on the downside." He opined that, as
the state would probably be an expansion party with others and
therefore should be the beneficiary for lower tariffs, this was
one of those decision points that should be decided before
moving forward.
MR. MAYER agreed to look into providing some points of
comparison to other projects. He stated that the points raised
were ideal ones for the producers and the administration to get
their thoughts and reasons on the nature of the expansion
principles.
MR. TSAFOS added that he was unsure whether there was more
analysis that could be done, as this was more of a question of
judgment. He suggested that the administration could have some
good reasons that had not been discussed.
REPRESENTATIVE SEATON asked if there were other expansion
projects with similar language, although generally more balanced
on the downside.
9:44:47 PM
REPRESENTATIVE JOHNSON said that he wanted to look at the
ultimate stress test under the current agreements for what would
happen under a variety of scenarios, including if ExxonMobil
Corporation bought ConocoPhillips Alaska, Inc., if TransCanada
had to file bankruptcy, and if Sinopec Group bought TransCanada.
He asked to know what the options were for the state, and
offered his understanding that the State of Alaska was the "deep
pockets."
9:46:09 PM
[CSSB 138(FIN) am was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES -enalytica, 3.24.24.pdf |
HRES 3/24/2014 1:00:00 PM |
SB 138 |
| AK LNG Key Issues - Enalytica March 2014.pdf |
HRES 3/24/2014 1:00:00 PM |
SB 138 |
| Leg. Legal 3.22.14 Sectional CSSB138 Version I.A.pdf |
HRES 3/24/2014 1:00:00 PM |
SB 138 |
| Response to HRES 3-21-2014 FINAL signed.pdf |
HRES 3/24/2014 1:00:00 PM |
SB 138 |