Legislature(2013 - 2014)BARNES 124
02/14/2014 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation(s): Gasline Issues/options | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
February 14, 2014
1:05 p.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Peggy Wilson, Vice Chair
Representative Mike Hawker
Representative Paul Seaton
Representative Scott Kawasaki
Representative Geran Tarr
MEMBERS ABSENT
Representative Dan Saddler, Co-Chair
Representative Craig Johnson
Representative Kurt Olson
OTHER LEGISLATORS PRESENT
Representative Andrew Josephson
COMMITTEE CALENDAR
PRESENTATION(S): GASLINE ISSUES/OPTIONS
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
JANAK MAYER, Energy Consultant
enalytica
Washington, DC
POSITION STATEMENT: As consultant to the Alaska State
Legislature, provided a PowerPoint presentation in consort with
Mr. Tsafos regarding gasline issues and options.
NIKOS TSAFOS, Energy Consultant
enalytica
Washington, DC
POSITION STATEMENT: As consultant to the Alaska State
Legislature, provided a PowerPoint presentation in consort with
Mr. Mayer regarding gasline issues and options.
ACTION NARRATIVE
1:05:04 PM
CO-CHAIR ERIC FEIGE called the House Resources Standing
Committee meeting to order at 1:05 p.m. Representatives Hawker,
Kawasaki, Tarr, P. Wilson, Seaton, and Feige were present at the
call to order. Representative Josephson was also present.
^PRESENTATION(S): GASLINE ISSUES/OPTIONS
PRESENTATION(S): GASLINE ISSUES/OPTIONS
1:05:25 PM
CO-CHAIR FEIGE announced that the only order of business is a
presentation regarding gasline issues and options by [the Alaska
State Legislature's energy consultants] Mr. Janak Mayer and Mr.
Nikos Tsafos, partners in the consulting firm "enalytica".
1:05:54 PM
JANAK MAYER, Energy Consultant, enalytica, consultant to the
Alaska State Legislature, began by noting that this is his third
year before the legislature testifying on oil and gas issues.
Prior to co-founding enalytica, he was with PFC Energy. At PFC
Energy he led the analytics team working on fiscal terms
analysis, project and portfolio economic modeling, and building
financial economic models for large and small transactions for
national and international oil companies and private equity
firms, as well as a range of analysis of the impact of fiscal
terms on government investment.
1:07:16 PM
NIKOS TSAFOS, Energy Consultant, enalytica, consultant to the
Alaska State Legislature, introduced himself saying this is his
second year advising the legislature. Prior to co-founding
enalytica, he spent seven and a half years with the natural gas
practice at PFC Energy. While at PFC he advised some of the
world's largest oil and gas companies regarding how to sell gas
if the company had gas, where to buy gas if the company wanted
to buy gas, and helping companies make sense of local, regional,
and national gas markets.
MR. TSAFOS explained that today's presentation is focused on two
things. The first focus is on in-kind and in-value, and how the
State of Alaska should participate in the proposed Alaska
Liquefied Natural Gas (LNG) Project. He said in-kind versus in-
value, as well as price/cost exposure, are effectively overall
project questions that are in the Heads of Agreement (HOA). The
second focus is on midstream options, which is about the role of
the Memorandum of Understanding (MOU) with TransCanada Alaska
Company, LLC, in the project design.
MR. TSAFOS, addressing slide 4 entitled, "OIL VALUE CHAIN",
noted that enalytica wanted to find a way to put the questions
faced by the legislature about gas in terms that legislators and
the public are more familiar with. He explained the slide is a
cut-and-paste from [page 106] of the Department of Revenue's
Revenue Sources Book, Fall 2013, and depicts the production tax
calculation for [Alaska North Slope (ANS)] oil for fiscal year
(FY) 2015, the first year that all oil production is subject to
SB 21. The FY 2015 forecast price for oil is $105 [per barrel],
he pointed out. The midstream costs are estimated to be about
$10 [per barrel], of which some are marine transportation costs,
some are Trans-Alaska Pipeline System (TAPS) costs, and some are
other costs. Lease expenditures are estimated to be $46 per
barrel. The result is [a production tax value] at the North
Slope of about $49 per barrel.
1:10:43 PM
REPRESENTATIVE SEATON observed that slide 4 indicates 35 percent
of the production tax value and said this does not include the
credits which will be significantly different than what appears
on the slide, especially as prices decline. He expressed
concern that members are seeing a partial picture.
MR. MAYER replied the purpose is not to talk about oil taxes,
but to take one particular section of things and compare how
this calculation might work with gas. The credit side was
deliberately not looked at because the focus is on the question
of where value is in the barrel. The aim of the exercise is not
to say how much tax the state collects from oil, but rather how
gas compares to oil. The aim is not to get into the question of
how much of a future development cost would be attributed to oil
versus to gas and what credits would be involved and what
credits are actually applied to gas, because at the moment none
do. The calculation was held off of the tax before credits
because that is what is being concentrated on.
REPRESENTATIVE SEATON said he is confused, then, where different
oil prices are used. For example, calculating this at $81 per
barrel versus $105 per barrel will result in a very different
oil value to the state. He requested that that also be put into
context here so legislators and the public can actually get a
value comparison.
MR. TSAFOS concurred, but said he will walk members through why
those numbers were put there. The thought was to start with a
view at the 30,000-foot level before drilling down to finer
details to ensure everyone is focused on the things that are the
biggest and have the biggest impact for the state. He said he
will be happy to answer further questions if they are not
answered by the rest of the presentation.
REPRESENTATIVE SEATON pointed out that gas taken in-value by the
state is being compared to a non-existent system, given the
state's system does not tax 35 percent of the production tax
value; rather, the state has a 35 percent less credits variable
on the price. He requested that at some point a comparison be
made to the system the state has in place.
1:14:41 PM
MR. TSAFOS resumed his presentation, turning to slide 5 and how
the price for Alaska gas will be different than the familiar
picture for oil. One difference is that the ANS price for oil
is transparent, while the price for gas is highly opaque and
does not just come up on the World Wide Web. Another difference
is that the price for gas is highly variable. Even within one
country there will be a 20, 30, or 40 percent variation between
one price and another price. So, while there may be an average
price, the reality is that [the State of Alaska] will be earning
very variable prices on its gas. Additionally, the gas price
for Alaska is likely going to be linked to oil since the state
will be looking at Asia. Most of the LNG in Asia is priced
against the Japan Customs Cleared (JCC) price, also known as the
Japan Crude Cocktail price, which is the average price that
Japan pays for oil. He noted that enalytica calculated back to
2004 and found the JCC is basically the same as the ANS.
Responding to Representative Hawker, Mr. Tsafos confirmed
enalytica's analysis is of the export aspect without any
prejudice as to the domestic price and how the domestic price
will be set. Continuing his presentation, he said the last
difference is that, in general, energy for energy, gas earns
less than oil. A $100 barrel of oil is not the same as a $100
barrel of LNG. Some contracts may get pretty close to that, but
in general gas trades at a discount to oil. The reason for
this, especially in Asia, is that when gas is priced more
expensive than oil, consumers go back to using oil.
MR. TSAFOS turned to slide 6 to discuss midstream costs and how
these costs differ for oil and gas. Gas is more difficult and
more expensive to transport than is oil, he explained, a reason
for why gas is often stranded. Rather than a transportation
cost of $10 [as seen for oil at the FY 2015 price of $105], the
gas value will be higher. The tariff for gas will not be
regulated by the Federal Energy Regulatory Commission (FERC) and
the tariff will be sensitive to the capital structure. The gas
tariff will be governed by how much the infrastructure costs and
the allowed rate of return on that infrastructure.
1:18:23 PM
MR. TSAFOS, moving to slide 7, outlined an indicative LNG chain
for when oil is priced at $100 per barrel. At this oil price,
the estimated price for LNG could be $81 [per barrel of oil
equivalent (BOE)], he said. This presentation is not a
forecasting exercise; rather, it is to show that LNG is "a very
different beast" than oil and must be thought about in a very
different way. In the midstream, the transportation cost for
LNG would be about $66 as compared to $10 for oil. At an
upstream expenditure for LNG [of $6 per BOE], the result is [a
production tax value (PTV)] of about $9 per BOE. If the
legislature were to focus its attention on how to tax $9, it
would be leaving the vast majority of the barrel untouched. The
$66 is so big that ignoring it, or saying that the state is a
tax levying authority at the wellhead, is leaving most of the
pie outside of the state's control. Commencing to slide 8, Mr.
Tsafos posed a scenario for the indicative LNG chain in which
the oil price is about $90 per barrel [with resultant LNG price
of $72.18 per BOE]. At this price, he pointed out, there is no
longer any production tax value at the North Slope for LNG
because the entire value has been taken up by infrastructure to
produce the gas and bring it to market. Turning to slide 9, Mr.
Tsafos posed a scenario in which the oil price is $100 per
barrel [with resultant LNG price of $81 per BOE], but the costs
for LNG are 12 percent higher. In this scenario, he noted, the
[production tax value] at the wellhead is also zero. Projects
much smaller than the Alaska LNG Project can cost 10 percent
more than thought, he advised, so a 12 percent cost escalation
is not unreasonable.
1:21:16 PM
MR. TSAFOS displayed slide 10, entitled "Implications for State
of Alaska". When thinking about what drives the value to the
state, he said, the state will want to ensure it gets a fair
price for the LNG, that the price per BOE is maximized.
However, he stressed, it is really about the midstream. The
midstream is such a big part of the pie that if the state is
nowhere near that $66 [in transportation costs] it is really
missing out. Upstream is important, but not as important as
midstream. The point being made, he said, is that the wellhead
is insufficient to drive the value for the state. At $9 per
BOE, multiplied by a production [of 384,000 barrels daily], the
state is looking at $372 million. That is not a big amount when
put into the context of what the state earns from oil today,
even though a production of 384,000 barrels is actually a
sizeable production project; while the volume is big, the value
is much smaller. Responding to Representative Seaton, he
clarified that the oil price used for slide 10 is $100 per
barrel, which leads to [an LNG price per BOE] of $81.
1:23:27 PM
MR. TSAFOS, responding to Representative Seaton, said 384,000
barrels of oil is equivalent to 17.4 million tons per annum, or
a little over 2 billion cubic feet (BCF) per day, which is the
assumption that has been put forward by the project sponsor in
the royalty study for the capacity. The capacity of the project
has a range of between 15 and 18 million tons because of the
weather - the colder the weather the more gas that can be put
through the pipeline. He reiterated that this analysis is about
the export, although the pipeline will be bigger because of the
in-state gas that is not for export. Responding further, Mr.
Tsafos said that 2.5 BCF per day is the initial capacity of the
pipeline, of which about 2.0 or 2.1 BCF per day will be exported
and the rest will be for the Alaska market. The pipeline, as
well as the LNG, has the potential to be expanded in the future,
although that is not what this presentation is looking at.
REPRESENTATIVE SEATON asked whether the pipeline being discussed
in today's analysis is the Alaska Gasline Development
Corporation (AGDC) pipeline or the Alaska LNG Project.
MR. TSAFOS answered it is the pipeline that is proposed in the
Heads of Agreement (HOA) and the Memorandum of Understanding
(MOU) for bringing North Slope gas to Nikiski for LNG export,
including the five in-state outlets.
1:26:06 PM
MR. MAYER turned to slide 11, entitled "RIV [royalty-in-value]
makes Upstream the Sole Price Absorber". He explained the slide
expresses the calculations on the previous slides in the form of
a bar graph, with both axes depicting a range of prices for LNG
in dollars per barrel of oil equivalent (BOE). Under a typical
Asian LNG pricing contract, he said, $80 per BOE for LNG could
easily be a crude oil price of $100 [per barrel]. For oil,
royalty and production tax are the two most substantial
components in the state's fiscal system. For gas, however, when
royalty and production tax are taken in-value and there is the
very high tariff of the entire midstream component, any changes
in gas price are enormously amplified in the impact on the
state. The state actually bears a huge amount of price risk,
the reason being that that is essentially the state's value; the
value at the wellhead is the absorber of differences in price.
REPRESENTATIVE HAWKER observed that the chart on slide 11 looks
at five price scenarios and how the destination price gets
shared along the way back to the wellhead. He inquired whether
there is an error with the farthest left column.
MR. MAYER confirmed an error and stated that the BOE price on
the X axis should read $110.
REPRESENTATIVE SEATON inquired whether slide 11 is the ANS West
Coast price or the "after deduction of the 22 percent" price.
MR. MAYER replied it is an LNG price expressed in barrels of oil
equivalent; so, it is after discount based on a pricing formula.
REPRESENTATIVE SEATON surmised that $22 would be added in order
to look at a comparative price.
MR. MAYER agreed, saying that $80 BOE relates, roughly speaking,
to the $100 per barrel of oil in the previous example.
1:30:19 PM
MR. MAYER returned to his discussion of slide 11, saying there
is enormous variation in what the state would get in royalty or
in production tax depending on the oil price. In higher oil
price environments, substantial value remains for the state to
take in royalty and to take in production tax. But, as the
price falls, that value quickly falls away to nothing, and the
value falls away much faster than the price itself is falling.
The structure is amplifying the effect of the price fall to the
state's revenues. It is amplified because there is a large
fixed component -- the tariff that is set on all the other
pieces. Whether a real tariff, or a tolling facility, which is
the case here, or an integrated project among the producers
where it is not looked at as a tariff, the cost of that
component must be assessed for regulatory and legal purposes and
the process for determining that tariff must be reasonably well
established. As a fixed component, the midstream gets its
guaranteed rate of return regardless of what the price is; that
value is always going to be there. It is the state's share that
has to take up the entire burden of a decrease in the price,
which is why the overall effect of this structure is to amplify
on the state's revenues the effect of a fall in price.
Correspondingly, the same thing would be true of an increase in
costs.
CO-CHAIR FEIGE interpreted the aforementioned as making a good
case for being an owner of the project, because then there would
be an ownership of at least a piece of the guaranteed return
that is shown on the graph.
1:32:26 PM
REPRESENTATIVE SEATON posited that, because it is not a tariff,
those expenses could be shifted by the individual parties. He
requested there be discussion at some point as to how the state
would be impacted by someone having higher expenses or taking
more expense as tariff versus someone taking lower tariffs.
MR. MAYER responded this is an excellent point. Returning to
slide 5, he said there is much less transparency throughout the
components that make up the core of the value. There is less
transparency because there is not one quoted price out there for
gas that everyone can understand; instead, it is subject to
contractual negotiations and different volumes. Additionally,
it is not a FERC regulated pipeline from a tariff perspective
because it is a pipeline for export. But, there is enormous
ability, subject to whatever regulatory constraint can be placed
on it, to vary that tariff through different capital structures
on a whole range of levels. Over the last few decades there
have been battles on the Trans-Alaska Pipeline System (TAPS)
over a tariff that represents $6 out of $100 per barrel of oil.
Thus, a tariff of more than $60 for the entire midstream
component, liquefaction back to the wellhead, is a good reason
for wanting a better solution to the question of understanding
where is the value in that chain and aligning interests on how
value is created across the value chain, rather than fighting
over which components accrue the value.
1:35:14 PM
REPRESENTATIVE TARR inquired whether Mr. Mayer is in agreement
with the 75/25 equity-to-debt structure that has been discussed
in previous presentations before the committee.
MR. MAYER replied the 75/25 structure is laid out in the MOU and
relates specifically to the question of TransCanada and
TransCanada's interest in the pipeline and the gas processing
facilities. He said enalytica would agree with the
administration and its consultant's analysis that the tariff is
much more sensitive in almost all circumstances to the relative
levels of debt and equity than it is to the specifics of, for
instance, the return on equity that is allowed. In that sense,
75/25 is quite an aggressive degree of leverage. Ratios of
70/30 to 60/40 are probably more typical mixes of debt and
equity for setting tariffs for regulatory purposes, so 75/25
looks quite attractive. In general, the other components of the
deal must be weighed out.
MR. MAYER, responding to Representative P. Wilson, confirmed he
is saying that the ratio of 75/25 looks good for the state.
1:37:12 PM
MR. MAYER resumed his presentation, turning to slide 12,
entitled "In Kind W/ Equity Offers More Downside Protection".
The graphs, he explained, are preliminary findings from
enalytica's model and over the next few weeks the assumptions
used in the model will be further refined. As these assumptions
are refined there may be a shifting of the precise points
depicted on the graphs or a shifting of precisely where the
lines on the graphs cross over, but the basic directional
findings extrapolated on the charts will not change. The
directional findings on the graphs depict the value of the
state's ownership if it takes the royalty and production tax in-
kind as a gas share as well as a corresponding share of equity
in the entire midstream component. By taking value in-kind and
an equity share of the midstream, essentially being a partner in
this project rather than a taxing and regulating authority, the
state has greater downside protection than it does if it takes
in-value. This is because instead of having a big fixed
component that is someone else's guaranteed return, a value is
distributed across an entire investment. If prices go down the
state may make less than an optimal return, but it is not a case
where value suddenly goes to zero with a very small movement in
price. The HOA posits a 20-25 percent share of gas for the
state. At a 25 percent share of gas, and a corresponding 25
percent equity stake in the entire integrated project, the value
to the state at low prices is higher than it is in-value and it
also has the shallowest slope; the state is better protected on
the downside but actually gives up some of the upside of high
prices.
1:41:34 PM
MR. MAYER, responding to Representative P. Wilson, explained the
graph on the left side of slide 12 looks at things from the
state's perspective, the middle graph is from the producers'
perspective, and the right graph is from the federal
government's perspective. In further response, he explained the
red line on the graphs represents the option of taking the
royalty and production tax in-kind as barrels and having a
corresponding equity ownership in the pipeline and liquefaction.
The green line essentially represents the status quo of tax and
royalty netted back at the wellhead in-value. The slope of the
red line is shallower than the slope of the green line, meaning
the in-kind world gives the state less price upside when prices
are high but less downside when prices are low. The state is
better protected against price risk in the in-kind world than
the status quo in-value world, which is a counter-intuitive
finding that enalytica thinks people should understand.
MR. TSAFOS interjected that what is being done on slide 12 is
adding up all the money generated by the project and seeing how
that money gets distributed amongst the state, producers, and
federal government. Distribution of the money can occur in two
different ways of structuring the project: the state can levy
the royalty and production tax in-value, or the state can take
gas for itself and invest in the infrastructure and become a
partner in the project. The green line is the status quo and
the red line is if enabling legislation is passed to play out
the scenario envisioned by the HOA. Basically, the HOA would
switch the state from the green line to the red line.
1:44:47 PM
REPRESENTATIVE SEATON posited that when the state takes debt in
the midstream most of the value will go out to pay for expenses,
so most of that value will not be retained as profit above
expenses. He inquired whether the lines on the graphs in slide
12 represent the actual money retained, in other words the
revenue that is usable to the state and not committed to
repayment of the midstream equity.
MR. MAYER replied the graphs are preliminary results from
enalytica's model that look at cash flows, not revenues, for the
project life. They factor in all of the initial upfront capital
cost or the operating cost of maintaining that plant and depict
the ultimate cash flow to each of these three parties after
debts are paid. Included in the model is a 70/30 percent
capital structure. Payments of both principle and interest are
based on the idea that 70 percent of the capital is coming from
debt and has already been taken out of these cash flows and
these are levered after-tax cash flows.
REPRESENTATIVE SEATON observed on slide 12 that the in-value
figure for producers is $70 at a low price, which is more than
depicted for the total value on slide 11 at a BOE price of $70.
MR. MAYER answered slide 11 is a stylized way of looking at a
single barrel of value, whereas slide 12 is looking at results
at a scale of billions of dollars from the entire 17-million-
ton-per-year LNG project over decades. In further response, he
confirmed that the Y axis on slide 12 is the cash flow in
billions of dollars.
1:48:21 PM
REPRESENTATIVE P. WILSON understood that as far as cash flow, if
the state were to take its share of the gas as gas the state
would not have as much at the top end or as much at the bottom
end. But, if the state took its share of the gas as in-value,
it would have more at the top end and more at the bottom end.
MR. MAYER responded correct, the state would have more exposure
at both the top and the bottom; so, more upside at the top and
more downside at the bottom.
REPRESENTATIVE P. WILSON inquired whether, for the producers,
slide 12 is depicting what the producers get or what the state
pays the producers.
MR. MAYER replied it is what the producer gets in total cash
flow from this project.
REPRESENTATIVE P. WILSON understood that in-value is not as good
for producers as it would be if the state took its share as gas.
MR. MAYER answered that, in absolute terms, that may vary and
that may vary depending on a range of assumptions. But, in
terms of exposure on the upside and downside, in the in-value
world the producer has less upside but is more protected on the
downside and in the in-kind world the producer has more upside
but is more exposed to downside risk.
1:50:18 PM
MR. MAYER, resuming his discussion of slide 12, noted the far
right graph shows that in lower price environments the federal
government's share drops substantially in an in-kind world. The
main reason for this is that in low price environments the
state's share of overall project value is relatively higher.
The state is not a federal taxpayer and so the project, overall,
pays relatively less and less federal taxes in low price
environments than in high price environments. To the extent
that there is a transfer of value through the in-kind structure,
a big part of that transfer of value is away from the federal
government and to the state government and the producers.
REPRESENTATIVE SEATON observed on slide 12 that in a low price
environment, with all the criteria that is in the agreement, the
minimum value for the producers is going to be $45 billion if it
is in-kind and $65 billion if it is in-value. He asked whether
enalytica's analysis is saying that under all scenarios of low,
mid, and high price this is a great project in which everybody
makes lots of money.
MR. MAYER responded these are very preliminary results intended
to indicate directional relationships of variables. He said
enalytica will do a much broader range of scenario analyses as
it works before the committees, looking at a much broader range
of assumptions and showing the different risks the state could
bear in different scenarios. The aim of this exercise is not to
say that it is all great all the time, it is simply to look at
one structure versus another and see which structure protects
the state better.
MR. TSAFOS interjected, drawing attention to the low ends of the
in-kind and in-value lines on the producer chart on slide 12.
He pointed out that spending $45-$50 billion for a return of $60
billion in 30 years is not a very good deal as there is also a
time value of money. In further response, he confirmed that the
graph depicts netback value.
MR. TSAFOS, responding to Co-Chair Feige, agreed that that is
still a significantly less return than at the other end.
1:53:40 PM
MR. MAYER returned to his presentation, moving to slide 13 and
noting that rather than looking at the undiscounted cash flow
time, slide 13 looks at the overall net present value of the
project across that same period. Additionally, rather than
looking in absolute terms, slide 13 looks at the share that each
participant in that overall net present value is receiving. In
a 20-25 percent gas share and a corresponding 20-25 percent
equity stake, it would intuitively seem that the state would be
getting about a 25 percent share of the total value of the
resource. As the resource owner, the question is whether that
represents a good or bad deal for the State of Alaska. In fact,
however, the state in most circumstances has substantially more
than 25 percent of the overall economic value produced by the
project. Further, the state's share of the pie of total value
produced is relatively higher in low price environments than it
is in high price environments. One reason for this is that
while the state is a 25 percent participant on an equity basis
throughout the entire midstream component, it does not have to
pay for any of the upstream costs like the producers do. Also,
for most purposes, the State of Alaska is not a state or federal
taxpaying entity, which means that, relatively speaking, it gets
to take a much bigger share of the value. However, he said, the
model assumes property taxes are a state liability, so issue
could be taken with that because 2 percent of a $60 billion
investment is a significant amount that would have to go to
municipalities.
1:56:20 PM
REPRESENTATIVE HAWKER observed that on slide 13 the in-kind line
in a low price environment is at 58 percent for the State of
Alaska, 50 percent for producers, and 15 percent for the federal
government; aggregated, those figures are more than 100 percent
of the pie. He inquired whether he is misreading how the graphs
are supposed to be constructed.
MR. MAYER responded he does not think Representative Hawker is
misreading the graphs, but he will need to get back to the
committee with an answer. Responding further, he confirmed that
[the lines adding up to 100 percent] is the concept of how the
graph is supposed to be read.
REPRESENTATIVE HAWKER further observed the graphs on slide 13
appear to be working in regard to the in-value lines, but not
the in-kind lines.
MR. MAYER replied the intent of slide 13 is to illustrate that,
in all price environments, the value to the State of Alaska is
more than the nominals of 25 percent gas share and corresponding
equity, and that value comes from not paying upstream costs and
not being a taxpayer, among other things. This is particularly
the case in low price environments where things like property
tax would otherwise take a progressively larger share of the
total pie if the state were a taxpayer like the other gas owners
and equity holders.
REPRESENTATIVE HAWKER stressed that the technical point he drew
attention to does not at all contradict or cause him any concern
with his aforementioned conclusion.
MR. MAYER offered his thanks.
1:59:33 PM
MR. MAYER added that also seen on slide 13, particularly in mid
to low prices, is a transfer of value to the producers and to
the State of Alaska from the presence of the federal government,
a non-federal taxpaying entity in this project. He further
noted that in this particular case, slide 13 shows value to the
producers in the in-kind world as being lower than in the in-
value world. He cautioned, however, that that can vary entirely
based on particular assumptions of the model, both in terms of
the overall percentage stake and a range of inputs around costs
and other things, which enalytica will show in future
presentations. He urged members to not think that in-kind is
inherently less desirable from a producer's perspective because
this example is just one way of cutting things.
REPRESENTATIVE HAWKER asked whether the state's portion shown on
slide 13 is reflective of everything that would go to the
state's treasury or reflective of what the state's agent,
TransCanada, would take.
MR. MAYER answered slide 13 looks solely at the in-value versus
in-kind question and is therefore reflective of the HOA without
considering the MOU. In the next few days enalytica will
specifically analyze the MOU and what it will mean to provide
some of that portion of value to TransCanada. A fixed tariff
creates greater price volatility and price risk for the state.
There are many reasons, some of them compelling, for why the
state entering into the MOU with TransCanada is desirable. One
point to consider is that inherently having a fixed tariff in
the system adds back some degree of price volatility that the
in-kind arrangements in general are taking away.
REPRESENTATIVE HAWKER pointed out that what is shown on slide 13
for the State of Alaska is actually an amount that would be
split between the state and TransCanada and the question is
whether that is a fair deal for the state.
MR. MAYER concurred.
2:02:53 PM
REPRESENTATIVE SEATON, observing that the previous calculations
are all based on all of the state's 25 percent being tax exempt,
questioned whether that is necessarily going to be the case.
MR. MAYER qualified he is not a tax attorney and cannot give
detailed advice on exactly how the state needs to structure this
to ensure tax exempt status. But, he added, the state obviously
has the ability to do that because it has successfully kept the
permanent fund from being a taxed entity. What is being shown
is that a key part of the overall value to the State of Alaska
and to the producers comes from the in-kind world, partly
through value to the state from decreased downside exposure and
partly through a transfer of value from no tax liability from
the federal government to the state and to the producers. To
that extent, ensuring that things are structured in a way that
the state does not incur a federal tax liability seems
absolutely crucial to this endeavor. He understood that the
AGDC subsidiary is set up in a particular way in the enabling
legislation to ensure that a federal tax liability is not
incurred, but he said he cannot comment on this with expertise
because it is not his specialty.
2:05:23 PM
MR. TSAFOS, resuming the presentation, advised that the price of
the gas and the cost of the infrastructure are the two things
that matter the most for how much money an investor will end up
with. In that way, the state is fairly similar to how an oil
company will look at this. The state will start off by saying
it wants the maximum value for the commodity and it wants to
produce the commodity at the lowest cost possible. The two
questions that then come up are: what is the price going to be
and what is the risk to that price, and what is the cost going
to be and what is the risk of that cost. Slides 14-16 begin the
conversation about how to think about these two questions.
Addressing slide 14, entitled "Price Exposure Defined at
Contract Signing", Mr. Tsafos pointed out that when thinking
about the price of gas, one must forget what one knows about the
price of oil. The price of oil can be found in a journal - if
the price is down, less money will be made; if the price is up,
more money will be made - but gas does not work that way. Gas
is usually traded in long-term contracts and usually the price
is linked to oil. However, just because a contract is linked to
oil does not mean it will earn the same value as another
contract that is linked to oil. For example, Taiwan buys gas
from three main long-term suppliers - Indonesia, Malaysia, and
Qatar. While it buys gas from those three suppliers in
contracts that are linked to oil, it can be seen on the graph
that these contracts do not rise and fall together. The
contract with Indonesia has one of the strongest links to oil,
such that the more oil goes up the more gas goes up by a similar
amount. The contract with Qatar has a very different
relationship; when oil is $100 per barrel, the gas price with
Qatar is [$6 or $7 per million British Thermal Units (MMBTU)]
while the gas price with Indonesia is $20 [per MMBTU]. When
Malaysia first signed a contract, it had a gas price similar to
Qatar. At some point, Malaysia renegotiated its contract to
move its gas prices up. [The dates shown] on slide 14 are the
key point - what really matters is the timing, when the price is
set, and whether it is set at the top of the market or the
bottom of the market, because that is the price that will be the
guide throughout the process. Except, if it gets really out of
sync with reality, contracts have an ability to revisit. For
instance, Kenai has been exporting to Japan since 1969 and there
is no way a contract can ever be written that would withstand 40
years of oil price where the contract is just as good and just
as reflective of reality every single day for 40 years. But,
for the most part, that initial signing sets the price, sets the
relationship to oil, and also sets the conditions under which
there can be a review. Mr. Tsafos counseled that new contracts
are sort of irrelevant. If the State of Alaska has a contract
with Tokyo Gas in Japan and then Australia signs a contract with
Tokyo Gas in Japan for half the price, Alaska's price does not
get affected, just like Indonesia's higher price does not do
much for Qatar. However, if Qatar wants to sell more gas to
Taiwan, it could bargain by pointing out the price Indonesia
receives. Deals around the world are useful for understanding
what is happening in the market, but they will not affect the
State of Alaska in the same way the state would be affected for
oil, because all that matters is the relationship that is
codified in the contract.
2:12:26 PM
REPRESENTATIVE HAWKER posited that the graph on slide 14
illustrates that the most critical thing is the ability to
negotiate long-term LNG shipping contracts with price floors and
price ceilings. He asked whether slide 14 is illustrating an
argument against a royalty-in-kind situation where the state has
to go into the market and develop its own sales contracts. In
such a case, he said, the state might be at a profound
disadvantage against the producers that have a major
international marketing system.
MR. TSAFOS responded that the answer is yes and no. Yes in the
sense that it is absolutely critical the state get a good deal;
it is absolutely critical that at the time the state signs this
it gets good value for its gas. No in the sense that a big
driver of what the state gets is the market reality at the time
the contract is signed. What the state gets depends on what
leverage it has. If the state is one of twenty or thirty
suppliers it probably would not have much leverage, but if the
state is one of three suppliers it would have a lot more
leverage. It is correct that the ability to negotiate matters,
but the market can sometimes matter even more. Continuing, Mr.
Tsafos said that in the world of LNG marketing he would not
necessarily conclude that a bigger oil company always gets a
better deal. In looking at gas pricing around the world, there
are many times that companies, even big companies, have signed
deals that five or ten years later they wish they could have
done something different, but at the time that was the best they
could get. He advised there are multiple ways for the state to
market its gas to defend itself against that. One option is for
the state to hire a marketing team. Another is for the state to
announce that it has 25 percent of 17 million tons and is
looking for someone to market it and ask prospective marketers
what they will give the state for that. Thus, there are
different ways for the state to protect itself against the
aforementioned asymmetry.
REPRESENTATIVE HAWKER said the HOA provides that the state might
avail itself of those producers it is contemplating going into
partnership with who have these global organizations, which gets
to his point that this is a very intricate and linked concept.
2:17:00 PM
REPRESENTATIVE KAWASAKI understood that the specific time when a
rate is set is most important, but asked how the volume and the
time term of contract would impact the pricing.
MR. TSAFOS replied that the term or length for new LNG contracts
is usually long, 15 or 20 years and is what the state should
probably expect. There are exceptions to that rule, but, for
the most part, to underpin that investment [a buyer] is looking
for a long term contract and that usually means 15-20 million
tons. Regarding volume, there is really no answer. There are
projects that might sell the entire volume to one player;
however, the Alaska LNG Project, as a whole, has probably too
much gas for that because there probably is not anyone out there
willing to take 17.4 million tons. Plus, the state's partners
probably would not sell it to them because it would be too
concentrated of a risk. If the state has 4-5 million tons of
LNG, it would not be surprising if the state found only one
buyer, but most likely it would be 3 or 4 buyers with each
taking 1-3 million tons.
REPRESENTATIVE P. WILSON surmised a buyer would be better off
having several [suppliers] because that would help the buyer get
gas at a lower price.
MR. TSAFOS confirmed that a buyer's interest is to have as many
suppliers as possible. At the same time, he added, a buyer
cannot create suppliers, unless, perhaps, it is willing to pay
an exorbitant price.
2:19:57 PM
MR. MAYER returned to Representative Hawker's question, saying
that the deal the seller negotiates, when it is negotiated, and
the market terms are crucial. However, once that is done, it is
done and it is set. So, if in the future the Henry Hub or other
of the more volatile price structures become the norm, or if
Lower 48 gas prices go through the floor, the key is that
inherent to the entire LNG structure and process is the setting
in place of these long-term contracts, and it is known what the
deal is and, by and large, that deal is done before the final
investment decision. When the actual time comes to put down the
real money, the state will know what that deal looks like and
what its exposure is.
2:21:07 PM
MR. TSAFOS, resuming the presentation, moved to slide 15,
entitled "Expensive Projects can Hedge against Volatility".
There are ways, he advised, in which the state can protect
itself against volatility. The typical way that this happens is
called an S-curve. He drew attention to the far left graph on
slide 15, entitled "NO S-CURVE", saying it illustrates what
happens when the price of gas and price of oil rise and fall
together. He said the middle graph, entitled "S-CURVE",
illustrates the same concept, but does not go all the way - in
this case, a little bit of the upside is given away in return
for a little bit of protection on the downside. The far right
graph, entitled "FLOOR/CEILING", goes to the extreme of where a
floor and a ceiling are put in place. For example, if a project
requires $12 to break even and the seller cannot go below $12,
the seller could protect itself by saying it is willing, even if
the price relationship were to go to $20, to take only $16. The
prevalence of S-curves depends on who has bargaining power, the
market fundamentals, and are a perfectly legitimate means for
companies and governments to protect themselves from volatility.
Thus, there are a number of contractual ways that the state can
reduce its exposure to pricing.
2:22:58 PM
REPRESENTATIVE TARR understood the MOU gives the responsibility
of marketing the state's gas to TransCanada. She inquired how
the state can be involved in the aforementioned type of
participation through that relationship.
MR. TSAFOS answered the MOU sets up a relationship of investment
in the treatment plant and the pipeline, the midstream portion.
Nothing in the MOU says TransCanada will be responsible for
obtaining a price for the state. TransCanada is only an
investor and a shipper of the gas through the pipeline.
TransCanada does not take ownership of the gas; it is the
state's gas throughout, even though the state may be paying
TransCanada a fee to use the facility. The aforementioned is
completely independent of TransCanada because it does not deal
with the MOU.
2:24:15 PM
REPRESENTATIVE HAWKER asked what the implication is of the word
"expensive" in the title on slide 15.
MR. TSAFOS responded that in the last few years the chief reason
why companies have tried to use S-curves is because costs for
LNG projects have become very high. Drawing attention to slide
16, he explained that this slide shows cost escalation and that
the announced cost structure for the Alaska LNG Project would
fall in the category of the more expensive LNG projects that are
out there.
REPRESENTATIVE HAWKER surmised that any project would desire to
hedge against volatility.
MR. TSAFOS answered not necessarily. For example, when
Equatorial Guinea was built, the operator, Marathon, said it was
able to deliver the gas through the upstream and the pipeline
and the liquefaction for under $1. So, if a seller can deliver
gas for under $1, why would it want protection on the downside?
REPRESENTATIVE HAWKER interjected that that is immaterial.
MR. TSAFOS, continuing his answer, said that if a seller has
very cheap gas and does not think the market is ever going to be
against it, why give up the upside to be protected on the
downside and that is where the whole idea of expensive comes in.
2:26:16 PM
MR. TSAFOS resumed the presentation. Addressing slide 16, he
urged members to look at the big picture and remember that what
drives value in this project is price and cost - the state wants
the best price and the lowest cost. A question the state is
going to be asking is how much the project will cost. Right now
the answer is $45-$65 billion for the whole thing, which is a
pretty big range. Another part of the question is how it is
known that this will be the cost. Slide 16, he explained,
serves as a reference regarding the type of delay and type of
cost overrun that LNG projects have faced over the last 10
years. If the state is going to be on the hook for 25 percent
of this investment, it is legitimate for the state to ask how
high the cost could really go and how delayed could the project
be. Slide 16 tries to provide an answer by looking across the
universe and seeing what the delays and overruns have been.
2:27:37 PM
REPRESENTATIVE HAWKER, in response to an earlier request by Co-
Chair Feige to hold questions until after the presentation,
interjected that he wants to be on record as stating that one of
the things legislators have picked up along the way is that the
assured failure of a mega-project is to be schedule driven
rather than being driven by the project and an understanding of
the project and its development. The inability of members to
drill down on these slides in public is becoming schedule
driven, he asserted, and members are not being given the
opportunity they need in public to hold these dialogues.
2:28:22 PM
MR. MAYER returned to the presentation. Displaying slide 17, he
said its purpose is to conceptually address the different ways
that the state could approach [structuring the midstream and the
path of the MOU]. The midstream is the gas treatment plant and
the pipeline, not the liquefaction facility. Of many
permutations for how the state could structure the midstream,
one obvious structure worth thinking about is an in-value
proposition, a purely producer project where the producers have
all the gas and each producer has a share of the pipeline, gas
treatment pipeline, and liquefaction. Another obvious structure
is one in which the state takes an in-kind share in each of
these things; this could be a structure with the producers plus
the State of Alaska or a structure with the producers, the State
of Alaska, plus some sort of third party. If there is a third
party, then the question becomes whether to leverage the state's
history with the third party in the Alaska Gasline Inducement
Act (AGIA) by continuing with that party [TransCanada] or
whether to terminate AGIA and launch a bidding process for a new
partner. The path of MOU is that of producers, State of Alaska,
and the third party involved with AGIA.
2:31:17 PM
MR. MAYER turned to slide 18 to address the core drivers for the
State of Alaska in terms of fundamental interests and things the
state wants to maximize. One core driver, he said, is to ensure
there is as much alignment as possible between the producers and
the State of Alaska. The previous slides showed graphically and
numerically just how important that question of alignment is
because of the possibility of disputes over value and where
value accrues. The question of what the capital structure is,
and whether there is a tariff and what that tariff is, can
become very contentious if this is a producer-only project.
From the producers' perspective there is actually no tariff, it
is simply an investment they make in infrastructure that takes
gas from the North Slope and sees it ending up for sale in Asian
markets. But from a legal and regulatory perspective, a tariff
is inferred and that tariff can be subject to all sorts of
changes based on capital structure and allowed rate of return.
There are all types of possibilities for disputes about what
that tariff actually is and therefore what value should be
netted back to the wellhead. Minimizing those disputes is
crucial. Also crucial to the State of Alaska is third-party
expansion. At the moment there is about 35 trillion cubic feet
of proved gas on the North Slope, with estimates of over 200
[trillion] cubic feet of yet-to-find resource. A big part of
the aim should be building infrastructure for the future to
bring some of that resource to market. Different players have
different incentives in this. Some players are in this to
monetize the gas that they have at the moment and may not be in
this to monetize the gas of future resource holders in quite the
same way. How that plays out is critical to the state's overall
interest. A third core driver is that the state needs to ensure
that in-state deliveries are enabled and that in-state customers
have the lowest possible tariff. A fourth driver is the state's
interest in ensuring the greatest possible execution capability
that the pipeline can be done on time and for the lowest
possible cost. A fifth driver is the substantial interest in
ensuring continuity and momentum in terms of the work done to
date and in terms that something real now seems to be happening
after many decades of talk about monetizing North Slope gas via
different measures. Producers are moving this project from
their production arms to their development arms. There is a
value to continuity and momentum and if a decision is made that
sets back the process, there is the question of what the cost of
that would be and how to weigh and evaluate that.
2:35:14 PM
MR. MAYER moved to slide 19, entitled "Producer Only:
Alignment/Expansion Weak Points". The questions of alignment
and expansion are key weak points of a producer only structure,
he said. [In regard to alignment], significant potential exists
for disputes over the allocation of value and the question of
what an optimal tariff is and optimal for whom. If the state
gets its economic value from the project from taxing value at
the wellhead there is a strong incentive to ensure that the
tariff is as high as possible, creating a lot of avenues of
potential dispute. Regarding third-party expansion, the
overwhelming focus of the producers by themselves, with no one
else involved in the mix, is commercializing their resource.
The way producers make money is by taking that resource to
market and that does not necessarily give them a compelling
interest in finding other resource holders and shipping the gas
of other resource holders through the pipeline. [In regard to
in-state deliveries], the potential for disputes over allocation
of value, in terms of the tariff, has an impact on the overall
monetary value to the state as well as the tariff that is paid
by in-state customers. [As far as execution], the producers
have a strong and proven ability to execute. However, the
midstream is becoming less of a focus for the major producers.
As far as continuity and momentum, all of these options, other
than the MOU path, have some degree of uncertainty around
arbitration, litigation, and what is involved in getting out of
the AGIA process, and whether the work done to date can be
maintained.
2:37:32 PM
MR. MAYER displayed slide 20, entitled "SOA Equity: More
Expansion Bias but Burden on SOA". He explained that a
structure involving [State of Alaska (SOA)] and producer equity
participation is envisioned through the HOA. With only the
producers involved, the state would take 20-25 percent of the
gas as well as a 20-25 percent equity stake in the liquefaction,
pipeline, and gas treatment plant and would run and manage that
stake itself. There is some strength to this structure, but
some questions around the state's ability to manage it. This
solution would create strong alignment between the producers and
the State of Alaska and would get rid of the question about what
the tariff is and where the value is allocated. It would mean
that all of the participants are taking value fundamentally in
the same way through the project. The State of Alaska has a
compelling interest in third-party expansion, but the question
is whether the burden of expansion should fall onto the state,
whether the state is well placed to be a strong pro-expansion
pipeline operator, and whether the state has that capability.
The state would be the only participant in this project whose
core interest is served by aggressively seeking new customers
for the pipeline and aggressively seeking to expand the
pipeline, so the question is the state's capacity in that front.
Such a solution would mean that the state's equity-entitled
capacity can be used to carry gas to local markets and,
potentially, at low cost of capital and low tariff for that gas.
Regarding execution, there is strong ability by the producers to
execute for the initial phase of the project to the existing
proposed liquefaction trains at Nikiski. But any expansion
would either be by the state by itself or by the state and any
new partners that are brought in for that expansion. Thus, the
question of execution becomes more of one about future expansion
than it does about the initial phase. Regarding continuity and
momentum, the same questions remain as were discussed earlier.
2:40:06 PM
MR. MAYER turned to slide 21, entitled "MOU: Expansion Bias &
Momentum; But Best Deal?" The structure under the MOU would
have the same benefits of alignment between the producers and
the state as would the previously mentioned structure, he noted.
However, the question becomes whether this is the best deal for
the state given that a third party would also be involved.
Would this particular deal with TransCanada be better than, or
as good as, any other that could be had? The capital structure
for rate setting, specifically the tariff, certainly seems
competitive with other FERC regulated pipelines across the U.S.,
but how is that actually known if there is no open bidding
process? The state never will know, but if an open bidding
process is held there is no guarantee that a better deal will be
found or that the state will even get the same deal. There are
many uncertainties, and much judgment is needed in evaluating
what the best option is. A key benefit of a third party is
having a company involved in the entire process that makes its
living not from shipping molecules to market, but just from
shipping molecules. This means that the third party's
fundamental interest is in expansion of the pipeline and in
finding new gas to ship to make more money out of the project.
If there are any questions about the State of Alaska's ability
to play that role, then the idea of a capable third party with a
proven ability to execute has attractions, regardless of who
that third party is. The gas treatment facility and the
pipeline are different from liquefaction, Mr. Mayer pointed out.
Expansion of the liquefaction can occur if there is enough gas
for a new liquefaction train. A new liquefaction train can be
built and can have a completely different ownership structure
than the previous trains, something that is frequently the case.
The molecules, however, are still going to be moving through the
same pipeline. Thus, the question of expansion becomes more
critical for the pipeline than for the liquefaction project, and
this appears to be the administration's rational in the MOU
given that the focus is on the pipeline rather than on the
liquefaction. Regarding in-state deliveries, the MOU structure
is similar to the previously mentioned structure. Regarding
execution, TransCanada clearly has a proven and serious ability
to execute major pipeline projects. There could be concern that
because a pipeline company simply makes a fixed rate of return
on whatever it spends on the pipeline, it has no incentive for
cost control. However, the three producers are going to care
very much about the price of this pipeline because that
determines all of their economics. Therefore, this counter
weight of different parties and different interests could
potentially serve the State of Alaska and its interests very
well. As far as continuity and momentum, the MOU structure
clearly is an option that maintains the progress made to date
and continues to accelerate investment.
2:44:52 PM
MR. MAYER brought attention to slide 22, entitled "Bid: Will
Reward Compensate for Cost in Time and $?" A final option, he
noted, is to look into whether a better deal could be had with a
third party other than TransCanada. While the arrangement with
TransCanada seems competitive, the state does not really know
unless it goes to a competitive process. However, the downside
to this is the question of whether the state will necessarily
get a better offer or even as good of an offer through a
competitive process. To help answer this question, one can look
back at the entire AGIA process and how many bidders were
involved, and ask whether that was representative or whether
there could be a stronger, more competitive process if it was
done again. The other core difference of this option is the
question of continuity and momentum and whether the possibility,
but not the certainty, of a better deal is worth the time and
momentum in terms of the work done to date, the cost, and the
arbitration around the AGIA process.
MR. MAYER moved to slide 23, entitled "SOA Needs to Carefully
Weigh Key Questions". He advised that the State of Alaska needs
to carefully weigh the following key questions: What
compensation might the state have to pay to get out of AGIA if
it is not by mutual agreement [and what intellectual property
will the Alaska LNG Project retain]? How will the HOA with the
producers be affected if the midstream is tied up in arbitration
or litigation? What are the odds of getting better terms than
those involved in the MOU? To what extent was the level of
competition seen in the AGIA process, which was not very high,
representative of interest and to what extent could there be a
more competitive process today? And, if the state could get a
better deal than is currently on the table, would that
compensate for the absence of an experienced, pro-expansion
player from being at the table over the next 12 months as core
commercial agreements are negotiated.
2:48:31 PM
REPRESENTATIVE P. WILSON returned to slide 21, inquiring how it
is that the producers reinforce cost discipline given that they
would not care if the tariff is high.
MR. MAYER responded the producers "care absolutely what the cost
of the pipeline is."
REPRESENTATIVE P. WILSON countered that the producers can write
off that cost.
MR. MAYER replied that depends to some extent. For instance, if
the state takes gas value in-kind rather than through production
tax, from the producers' perspective there really is no such
thing as a tariff on the pipeline anymore because the state has
its share of the gas and its share of the capacity and does what
it will with its LNG. The producers have their share of the
gas, their share of the pipeline, and their liquefaction
project, and they do with it what they will. For all intents
and purposes these could be two completely separate projects.
They share physical infrastructure, but the producers' share of
the gas going from the gas treatment plant, through the
pipeline, and on down to the liquefaction project is just one
big capital investment from their perspective that enables them
to take gas from the North Slope and sell it in Asia. The more
expensive that is, the poorer the producers' economics. They
care very, very strongly about what the cost of the pipeline is.
CO-CHAIR FEIGE added that while TransCanada will administer the
state's share in the project, the three producers will have
approximately a three-quarter share. Therefore, he said, the
producers are also going to have a significant interest in
keeping cost down and making this the most efficient project for
their own selfish purposes.
MR. MAYER concurred.
2:51:07 PM
REPRESENTATIVE SEATON, referring to slide 11, related his
understanding that the State of Alaska would have a 75/25 equity
agreement with TransCanada and each producer would determine the
amount of equity it wants to have in its share, which will give
the producers a profit margin at a different phase than wellhead
value delivered to the customer. Regarding return on equity, he
inquired how members are to balance and understand the
difference between a producer in full control of the assumed
tariff and taking the value as a difference in wellhead value
and market price versus taking it as return on investment in the
midstream, which enalytica is saying is the largest portion of
the producers' capital return on the whole project.
MR. MAYER responded the answer depends on whether it is an in-
kind or in-value situation.
REPRESENTATIVE SEATON said he understands the in-value and about
reducing it to avoid taxes, royalties, and so forth. He
clarified he is asking what the other considerations are and how
they would impact the state if there is more value taken in the
midstream than at the wellhead, especially if the state is
counting on the producers to be the sellers of the state's gas.
MR. MAYER replied if the state has gas because it is taking in-
kind gas and is participating, the question of how different
producers choose to structure their investments really becomes a
question for the producers alone and is of no particular
relevance to the State of Alaska in the same way as it is if the
state is taxing at the wellhead. This is because from the
producers' perspective it really is not a tariff. Maybe the
producers come up with a tariff for some sort of internal
transaction pricing purposes, maybe they do not. But, overall,
this becomes one project that is simply a big capital investment
to take gas from the North Slope and sell it into Asia. The
state has its share and will choose how to structure its share
of capacity in the project. If the decision is made to go down
that pathway, it really is the sharing of actual physical
infrastructure, but two completely separate projects within that
same infrastructure.
2:54:34 PM
REPRESENTATIVE SEATON anticipated the state will be using the
producers' expertise in marketing the state's gas that will be
on the same tanker. Producers might structure their project so
their gas has a higher or lower wellhead value than does the
state's gas, but the producers will likely be selling Alaska's
gas at the same price as theirs. He asked how it could be
structured to protect the state's value chain from being at a
disadvantage during price negotiating.
MR. MAYER answered that once the state is taking a gas share in-
kind and participating in the project, that question becomes
what the state's ability is to negotiate a deal. That deal may
be with end buyers in Tokyo, or with the three producers to
market the LNG on the state's behalf, or with other major LNG
marketers that are bidding competitively to market gas on the
state's behalf. The value is not driven in any way by the
capital structure through the rest of the value chain; it is
about the deal the state negotiates for its LNG as it leaves the
liquefaction plant. A marketer may not give the state what it
can potentially receive for the LNG in Tokyo; the marketer
receives a premium for its risk in marketing the state's gas and
the state must analyze whether that premium is or is not a good
deal.
2:56:58 PM
REPRESENTATIVE SEATON posed a scenario of three LNG trains along
with tankers, and posited that combined shipments of LNG would
be the most economic as compared to storing LNG and waiting for
a separate tanker. He understood Mr. Mayer to be saying that in
that scenario, a different wellhead value for the projects would
have no relationship because it is just the state's leverage for
making a deal and the producers' leverage for making a deal and
sales to overseas markets.
MR. MAYER responded that in an in-kind world, wellhead value is
not the driver for anything because everyone has LNG. An
exercise of deciding how that is netted back to the wellhead
could be done, but how that is netted back to the wellhead does
not really determine anything because no one is taking their
value at wellhead. In a scenario where gas is taken in-kind and
then immediately sold at the wellhead, there maybe is a question
of whether the price received at the wellhead is similar to what
would be received through a tariff calculation or is a
negotiated price that is independent of that. But, assuming
that the state remains invested in the entire value chain and
has LNG to sell, the value of that LNG is determined by what the
end market will eventually pay for it, and whether the state can
market its LNG itself, and, if not, what premium the marketer
would charge for marketing on the state's behalf. It is not
driven by the wellhead economics.
2:59:09 PM
REPRESENTATIVE TARR asked whether the cost overrun information
on slide 16 can be used by members for making comparison to this
project. For example, whether there are similar or dissimilar
components that might give an indication as to whether the state
is potentially going down the road of where it would see those
same kinds of cost overruns. She further asked whether any
projects have been sanctioned between now and January 2012 when
the [Australian] project was sanctioned.
MR. TSAFOS replied he does not want to convey that slide 16 is
an exhaustive list of every single project proposed or built
over the last decade because there are other projects.
Regarding what the information means for Alaska, he said a
number of things can drive cost overruns and these can be
simplified to country specific, project specific, or global. A
global factor is the cost of steel because a lot of steel will
be used in this project. If the cost of steel rises between the
time it is decided to make this investment and the time the
steel is purchased, it will result in having to pay more for the
steel. Many commodities today, including oil, are at or near
historical highs and, in that sense, the state is more likely to
face an expensive project rather than a project with cost
overruns because the state knows that it is expensive. An
example of a country specific factor is the boom that happened
in Australia, resulting in a huge call on labor and so more had
to be paid for that labor than was anticipated. An example of a
project specific factor is Australia's Pluto project which had a
fire at one of its facilities as well as labor strikes. Another
example of a project specific factor is Australia's Gorgon
project which had delays because it is a very environmentally
sensitive area; things can just go wrong as a project is built.
MR. TSAFOS said that it also comes down to project management
and having people who really know how to do this, and the
companies involved in Alaska are very experienced players.
However, an experienced player is not foolproof protection
against cost overruns as the projects on slide 16 involved very
experienced players, but it is usually better to have an
experienced partner than an inexperienced one. As things get
closer to making a final decision on the Alaska LNG Project,
there should be a shrinking of the current range of price
estimate because an oil company will want that range to be
smaller. However, there must be an appreciation that things do
go wrong sometimes and end up costing more. Another thing to
keep in mind is that, because of the way these projects work,
what cost overruns usually do is reduce the rate of return.
Once the project is built it will not cost a lot of money to
keep it running. Over time, money will still be made, but it
just may not seem as smart of an investment in retrospect.
Generally, over the course of a project, money is not lost each
year in the sense of a negative cash flow; prices would have to
go really low for that point to be reached. Usually what
happens when costs go through the roof is that instead of making
an anticipated return of, say, 15 percent, the return is 10 or 8
percent.
3:05:05 PM
REPRESENTATIVE TARR related that when talking with TransCanada,
the company says it will be a good partner because it is a
pipeline builder as well as a pipeline operator. In looking at
the last slides of the presentation regarding the risk/reward
analysis and the things that need to align, virtually all the
items are aligned under the scenario in which AGIA would be
terminated and the state goes to the bidding process. She
inquired what that scenario would mean as far as the potential
for one partner building the pipeline and another partner
operating the pipeline and how that would compare to what is
currently being considered.
MR. MAYER answered that if, for instance, the tariff is of
paramount importance, then the state needs to carefully weigh
what the realistic chance is that there is a better deal on that
front versus what the state thinks the cost will be for either
arbitration or an ever messier exit to the AGIA process, plus
delay. The other question is the MOU and the number of off-
ramps anticipated within the MOU. If the Precedent Agreement
and the Firm Transportation Services Agreement outlined in the
MOU are put into place, TransCanada will bear the state's share
of costs in undertaking the Pre-Front End and Engineering Design
(Pre-FEED) study. At any point during that time, within 60 days
he believed, or possibly 90 days, the state can turn around and
say it wants to go alone or go with a different partner and
reimburse TransCanada its costs plus a 7.1 percent interest
rate. At the Final Investment Decision (FID), the state has the
ability, for any reason, to terminate the arrangement. When all
those things are factored in, that question of whether the state
is definitely getting the best deal and whether the state is
certain of that right now, in some ways becomes even less
pressing.
3:08:08 PM
CO-CHAIR FEIGE observed that a number of projects on slide 16
were either early or on time and on budget. He asked who built
those projects.
MR. TSAFOS responded he will get back to the committee with that
information. The key thing here, he added, is to distinguish
that the oil companies are the project sponsors and that they
hire and oversee an engineering, procurement, and construction
(EPC) contractor to build the project. In the case of Egyptian
LNG, "BG" is the largest project sponsor and he believes BG
hired Bechtel to execute that project, but he will get back to
the committee to confirm this. He said he has worked in the
past with some of these producers, as well as EPC contractors,
and several have tried to link themselves with this chart.
However, he said, he has not found that being on time or on
budget is strongly linked to the EPC contractor. There are only
about 7-10 EPC contractors that build these facilities.
3:10:25 PM
REPRESENTATIVE HAWKER asked whether the four options discussed
today are definitely and exclusively the state's only options.
MR. TSAFOS replied no, there are other ways to structure this,
such as a third party only of TransCanada, which is what AGIA
is, as well as other ways. When enalytica tried to list out the
15-16 permutations things go lost, so these four options were
chosen for simplicity. He offered to look at a particular
option in more detail if the committee so desires. Continuing,
he said there could be a structure with different players being
the gas treatment plant and different players being the pipeline
and different players being the liquefaction. Another option is
that the whole midstream does not have to be the exact same
ownership.
MR. TSAFOS, responding to Co-Chair Feige, agreed to provide a
list of options in writing to the committee.
REPRESENTATIVE HAWKER, continuing his previous question, said
teasing out an entire list of options was not where he was going
with his questions. He asked whether these four options are the
only options that Mr. Mayer and Mr. Tsafos think the committee
should be concerning itself with.
MR. TSAFOS answered he and Mr. Mayer went from the 15-16 options
to these 4 because they certainly seem the most reasonable
options. He and Mr. Mayer thought having the producers involved
was essential to bring cohesion to the project and once that is
taken as a given, the question is whether it should be just the
producers or should someone else be added. In the MOU the State
of Alaska has an option, but not an obligation, to acquire
equity, so it is possible to end up with the producers plus
TransCanada and no State of Alaska. Thus, when next before the
committee, he and Mr. Mayer will work through the economic
calculations of the MOU to show an option where the state does
not exercise its right to acquire up to 40 percent equity.
3:14:27 PM
REPRESENTATIVE HAWKER said his takeaway is that the "field of
four" identified by enalytica are the places where the committee
should be focusing its attention, although he may not
necessarily agree with enalytica on that. He drew attention to
slide 23, noting the option in the far right column of producers
plus State of Alaska plus third party is the terminating of AGIA
and the launching of a separate bid to find a new partner. He
inquired how that would work "in the context of the MOU
provision that grants TransCanada, basically, a five-year right
to participate in any similar project on terms and conditions
consistent with those in the deal in front of us."
MR. MAYER responded there are two routes that could take. One
route, if the MOU is disliked, is to undertake something quite
different. The other is to go with the MOU and at one of the
off-ramps the state gets off and does something different.
REPRESENTATIVE HAWKER said "internal to that choice ... is an
inherent assumption that the ... MOU itself is materially
modified."
MR. MAYER replied the first option would be that the MOU does
not come into effect because the conditions that would bring it
into effect - the enabling legislation and its enactment with a
Precedent Agreement and a Firm Transportation Services Agreement
- do not happen. The other option is that those things do
happen and the exit ramps entailed in the term sheet are taken
instead.
REPRESENTATIVE HAWKER concluded that the aforementioned would be
not exactly approving the MOU but tentatively pursuing an HOA
process without the MOU relationship.
MR. MAYER answered that would be one option, but another would
be going through the MOU and at a future point taking the exit
ramps that are within the MOU.
3:17:33 PM
REPRESENTATIVE HAWKER opined that the dialog has all been on
alignment. Today's presentation only addresses the midstream,
but many of the questions and issues raised about the midstream
are relevant throughout the entirety of the project. As far as
the state's participation and the various players that might be
involved, he inquired whether in the parts of the project above
and below midstream the committee is to presume that the
presentation as presented really has no options. He then
withdrew his question, stating that enalytica's questions
depicted on slide 23 are good ones and that they go to the
question of whether the proposal in front of the committee
really and truly represents alignment from the very beginning of
a project to the very end of a project.
MR. TSAFOS turned to slide 7 to respond, replying that of the
$66 in total midstream transportation cost, only $24 is for the
pipeline and gas treatment plant (GTP) that TransCanada plays
into. Thus, there is a bigger midstream pie than just what
TransCanada is involved in. Regarding alignment in the other
parts of the project, it seems there would be alignment in the
liquefaction facility because every partner wants the lowest
possible cost. If the state is a 25 percent equity owner in the
liquefaction it will have a similar interest with the 75 percent
owners and no disputes with those owners. However, there is
some potential misalignment in the marketing of gas because, at
a volume of 17 million tons, the state will probably be knocking
on the same doors, and this is true of any project where the oil
companies compete with the world in the gas marketing and
compete amongst themselves in the project. That is more a fact
of life than a result of the specific project structure, he
added. One way to get around that, Mr. Tsafos advised, would be
to have all the gas go into a pot called "Alaska LNG" and Alaska
LNG sells this gas to the world. Other projects do this, one
such project being Angola LNG. However, he understood, this is
not the current thinking of the partners, but it is an option
for addressing some of the potential misalignments on the
marketing of gas. On the upstream, he said he would suspect
that both the state and the producers have a similar interest in
maximizing the ultimate recovery of the resource and the
reliable produce-ability of that resource. Thus, when thinking
about the entire chain, the biggest source of misalignment would
be under marketing.
3:21:55 PM
REPRESENTATIVE HAWKER pointed out that Mr. Tsafos is talking
specifically to alignment within segments of a project -
alignment in the upstream oil fields, alignment in the gas
treatment plant, alignment in the pipe, alignment in the LNG
facility. However, what he is getting at is the totality -
alignment within the entire value chain and that a value chain
is only as strong as its weakest link. He is therefore asking
how the aforementioned misalignment points and their consequence
on the entire value chain should be considered by legislators.
MR. TSAFOS responded that if the entire project is studied for
the weakest link, he would say there are probably many more weak
links under the status quo than under the current proposal
before the committee. The current proposal does not eliminate
all the weak links, he said, and there absolutely are different
ways that this project could be structured. However, there are
so many different ways to structure this that it could get
chaotic, so perhaps the best way forward is to zoom in on some
specific types of misalignment and scenarios and enalytica would
then be willing to provide its thoughts on those.
3:24:24 PM
REPRESENTATIVE SEATON said a question he has long had is how
many royalty scenarios around the world have structured in-kind
purchase and whether the state's alignment in this process is
similar to the percentage of government take in those other
world projects. He requested an answer be provided outside of
today's meeting since time is short. He then expressed his
concern about alignment to get a project going and agreed with
Representative Hawker that the legislature's consultants are
providing a take on the project that is being looked at, but
that there may be other solutions the committee should be
looking at and to see whether there is a better deal. He
observed that the scenario on slide 23 with the most checkmarks
describes AGIA, except maybe the part on alignment. The only
reason it is known that alignment may not be there is because
there was not a response to open season [under AGIA], although
there has not been a response to open season on this one either.
He said he would like to see an analysis on whether there are
ways to do something that will improve the position of the State
of Alaska in a gasline instead of just these four options.
REPRESENTATIVE TARR requested that when putting together the
additional scenarios for the committee, enalytica looks at the
five offtakes and where misalignment opportunities exist for
access for in-state gas.
3:26:58 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:27 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES enalytica - Revised Version 2.14.14.pdf |
HRES 2/14/2014 1:00:00 PM |