Legislature(2013 - 2014)BUTROVICH 205
02/10/2014 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB138 | |
| Alaska North Slope Royalty Study | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SB 138 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 138-GAS PIPELINE; AGDC; OIL & GAS PROD. TAX
3:30:29 PM
CHAIR GIESSEL announced continued consideration of SB 138 and
that today they would hear from Black and Veatch on the work it
did that advised the administration and the departments on how
to proceed on the gas pipeline issue.
3:30:54 PM
SENATOR MICCICHE joined the committee.
^Alaska North Slope Royalty Study
Alaska North Slope Royalty Study
DEEPA PODUVAL, Principal, Black & Veatch, Management Consulting
Division, said she had been working in the energy industry with
a focus on natural gas for the last 13 years. Black and Veatch
is a privately held corporation with 10,000 employees in 100
offices around the world; they specializing in critical human
infrastructure: energy, water, and telecommunications. A fairly
large division also supports the federal government. She and her
partners have a long history of working with the State of
Alaska; she has led the team supporting the state for the last
eight years focused on economic analysis, markets, and
commercial support; she would lead the presentation with the
help of her colleagues.
3:35:35 PM
PETER ABT, Managing Director, Oil and Gas Strategy, Black &
Veatch, Management Consulting Division, said he had been with
this company for eight months or so. Prior to that, he spent 10
years working for Gazprom helping them develop their global LNG
strategy focusing on commercial structures, negotiating
commercial and terminal use agreements, sales and purchase
agreements of LNG. He had also spent time working in the oil and
gas development, exploration and production drilling and
completing wells. He spent time in pipeline line development and
had run trading organizations and had a deep knowledge of U.S.
natural gas business, the global LNG business, and the issues
the AKLNG project faces.
3:37:02 PM
JASON DE STIGTER, Senior Consultant, Black & Veatch, Management
Consulting Division, said he had been working on this project
with Ms. Poduval since 2008 and was deeply involved in the
modeling effort. Most of his client engagements focus around
economic, financial, and risk analysis.
CHAIR GIESSEL acknowledged that Commissioner Balash was on line.
MS. PODUVAL noted these facts:
The Alaska North Slope Royalty Study was undertaken between June
2013 and November 2013 and, hence, preceded finalization of the
Heads of Agreement ("HOA") between ExxonMobil, ConocoPhillips,
BP, TC Alaska, AGDC, and the State Administration as well as the
Memorandum of Understanding ("MOU") between the State
Administration and TransCanada.
While the study informed the State Administration as it
negotiated the HOA and the MOU, the study, and this presentation
summarizing it, do not analyze the specific terms within these
agreements or their impacts on the competitiveness of the AKLNG
project.
The study pointed out several factors that were taken into
consideration by the administration and addressed where possible
within those agreements, like the risks associated with royalty
in kind (RIK) and procuring access and control in a potentially
integrated LNG project.
3:39:59 PM
After the royalty study summary, supplemental analysis was
included that summarizes some ongoing work that looked at
specific terms in the MOU and HOA and their impacts on the
state, and she looked forward to presenting some of it to the
committee and to work with legislative consultants to pull
together an analysis related to the specific decisions at hand.
In the interests of time Ms. Poduval said they had summarized
the royalty study at a high level; she said a lot of work had
been done that was not included, including various detailed
analysis. They ran more than 100 separate scenarios and continue
to analyze various issues. The Administration has looked at a
significant body of work to get to this point.
Executive summary:
The Alaska Liquefied Natural Gas (AKLNG) project is a proposed
project to liquefy Alaska North Slope (ANS) gas and export it as
LNG, primarily to Asian markets. The project is comprised of
three main components:
-Gas treatment plant (GTP)
-Pipeline
-Liquefied natural gas (LNG) plant
The total estimated capital cost of the three components of this
project is $45 billion falling within a range of $39-$54
billion. She clarified that the $45-$65 billion estimate they
hear about includes the investments in the upstream, especially
at Pt. Thomson. Natural gas to supply the project is anticipated
to come from the proven reserves at the Prudhoe Bay and Point
Thomson units on the Alaska North Slope. The key project
sponsors are Exxon Mobil, ConocoPhillips and BP (referred to in
this study as Producers) with potential participation by
TransCanada and the State of Alaska. The Final Investment
Decision (FID) for the project is assumed to be 2017-2018, with
the project achieving commercial operation around 2023-2024.
3:44:01 PM
MS. PODUVAL said the study had two main objectives; the first
was to provide information that can help the state protect its
royalty interest and maximize its value from this project. The
second was to understand what the state can do to incentivize
and impact the success of the AKLNG project in its role as land
owner of the oil and gas resources on the Slope.
3:44:55 PM
The team included Black and Veatch as well as the international
expertise of Daniel Johnston, and the study was conducted under
the leadership of the Department of Natural Resources (DNR) with
support and consultant from Department of Revenue (DOR) DOR.
Inputs and assumptions provided by the Producers were
considered, as well. A lot of uncertainty surrounds this project
at this point, because it is significantly large with many
complex variables that cannot be perfectly foreseen.
3:45:58 PM
SENATOR FAIRCLOUGH joined the committee.
3:46:09 PM
Given that they have tried to make the best assumptions possible
while being conservative and recognizing that many reasonable
scenarios can be created to look at this project, Ms. Poduval
said they were presenting their view of the market and it will
not necessarily be the official view of the administration.
3:47:17 PM
She skipped the key findings and went on to conclusions on slide
15, saying bottom line, it's their assessment that the AKLNG
project can be feasible and competitive with changes to the
project's cost structure and the state's fiscal framework. From
an incentive perspective fiscal and non-fiscal incentives can
improve the commercial attractiveness of the project. These
include:
-a reduction in government take, either royalty or taxes
-ways to share the cost of the project, which are expected to be
significant
-non-fiscal terms such as stabilization provisions and
modifications to existing lease terms, such as the state's right
to switch between royalty in kind (RIK) and royalty in value
(RIV).
They anticipated that the AKLNG project would be an integrated
project like several large LNG projects are worldwide.
Integrated project ownership of AKLNG by the Producers presents
the risk of misalignment wherein project revenues could be moved
between the upstream and the midstream components to maximize
value to the Producers. These decisions could potentially be to
the detriment of the state.
3:49:39 PM
MS. PODUVAL said one of the study's findings was that fiscal
structure changes beyond stand-alone royalty share or tax rate
modification can help in improving project economics and
creating alignment. One way to achieve that would be direct
participation by the State in the project in conjunction with
establishing a gross share of the gas that would allow for an
alignment of the share of the gas as well as potential equity
participation in the project.
3:51:23 PM
Direct state equity participation in the project can provide key
benefits to the state and include:
-creating alignment of interests
-creating transparency through the midstream portion of the
supply chain for the state entity that participates in the
project
-having the ability to facilitate third-party access to the mid-
stream
-potentially increasing the state's cash flows and improving
producer economics.
She said that establishing a gross share of gas in lieu of
production tax and marrying that with equity investment in the
project may provide the needed alignment for a competitive
project as well as allowing the state to maximize the value of
its resources.
3:53:17 PM
MS. PODUVAL noted that this is not a strategy without risks, and
the state has the ability to lessen those as well as achieve
objectives of transparency and open access for third parties,
but will need to weigh those opportunities circumspectly and
with carefully defined state's rights and obligations.
3:54:14 PM
MIKE PAWLOWSKI, Deputy Commissioner, Department of Revenue
(DOR), said it was important to remember that these conclusions,
one being the commercial agreements and another being the access
for third parties, are a review of the royalty study completed
prior to the finalization of the Memorandum of Understanding
(MOU) with TransCanada and the Heads Of Agreement (HOA). The
administration looked at these as key concerns and managed some
of those risks in the HOA or articulated them as areas of
concern they will continue to work on. This study is the
foundation on which the state built its response in the
discussions with the Producers.
3:55:26 PM
MR. ABT took over the Black & Veatch presentation and began with
the LNG market on slide 18. He focused on three primary tasks:
-providing an overview of how LNG is traded in value in the
various markets that are available to the AKLNG project
-undertaking an analysis of historical and future global LNG
pricing trends
-providing some discussion around the supply and demand
projections in the LNG market and the potential implications
that will have on the AKLNG project
Current LNG market realities on the demand side:
-the LNG market is highly concentrated
-7 countries account for 70 percent of demand
-Asia Pacific accounts for 70 percent of global trade
-demand is growing rapidly, about 8 percent per year
Current LNG market realities on the supply side:
-LNG supply is also highly concentrated among 8 exporting
countries that provided 85 percent of global LNG exports in 2012
-liquefaction capacity, or trains, are very expensive and
financed on long term sales and purchase agreements (SPA) with
LNG buyers.
-gas quality varies by project and between buyers with Asian
buyers preferring higher btu gas
-long term contracts of 20 years or more dominate the market and
are expected to continue doing so in the future
-no liquid market to provide price markers for LNG (unlike
natural gas or crude oil)
3:58:25 PM
MR. ABT said the price structures of the SPAs need to provide
certainty over the long term to support the cost of the projects
and the underlying reserve developments that are necessary to
provide the feed gas to the LNG terminals. In the past, he said,
LNG contracts have typically been structured with an oil price
linkage.
SENATOR FAIRCLOUGH asked if that price linkage had been standard
since 1970 and if it was true in an Asian market also.
MR. ABT answered yes; that is clearly the price preference in
the Asian market. They have been the predominant buyers of LNG
since the 70s; there is no natural gas market per se in Asia, so
everything has been linked to crude since that time. With the
recent development of U.S. Gulf Coast export projects they are
trying to delink some LNG prices away from crude oil, but a
majority of LNG prices are still linked to oil contracts. The
period of 2002 - 2006 saw some lower-price oil-linked contracts
signed by Chinese/Japanese buyers, but that was mostly due to
prevailing economic conditions at the time and some pressures
that project developers were under to get project financing, and
in 2008 there was a severe world recession.
MR. ABT said the recent emergence of Henry Hub linked tolling
agreements in the U.S. Gulf Coast has created an alternative
price structure that the Asian buyers are very interested in.
These structures in current market conditions are lower than the
oil-linked prices for delivery into the Asian markets. But
buyers in Japan and Korea are aggressively seeking Henry Hub
linked contracts now and are entering into traditional oil
contracts. He anticipated that condition will not last for much
longer and a limited amount of U.S. volume will be exported from
the Gulf Coast. Once those projects have been identified and
final investment decisions have been taken, the Japanese and
Korean buyers will likely be back in the market pursuing oil
linked contracts once again.
4:01:56 PM
SENATOR FRENCH said this seems like an area of potential risk
for the state, because if it turns out that the Henry Hub model
becomes dominant over the next few years it could lose out
because those contracts pay less than the oil linked contracts.
MR. ABT responded that the Henry Hub-linked price contracts are
targeted to entering the market place in about the 2017-2020
timeframe, but there will be a time when demand goes beyond what
the Gulf Coast can provide. The underlying assumption is that
the Gulf Coast will have a limited amount of export volumes.
There are twenty-odd projects that have applied for approval to
sell LNG sourced in the U.S. to non-free trade agreement
countries, but he didn't anticipate all of those projects
receiving approval nor did he anticipate that if they receive
approval that they will ultimately get constructed.
4:03:36 PM
MS. PODUVAL added another factor that will come into play is the
desire of the Asian buyers to have diversification within their
LNG supply portfolio. There are concerns about being too heavily
dependent on shale gas from the U.S. as well as passage through
the Panama Canal to get Gulf Coast LNG over to Asian markets.
So, they anticipate projects like AKLNG that have a well-
established resource base, a stable political environment, and
proximity will be attractive to Asian buyers even outside of
price considerations.
SENATOR FRENCH said he asked whether or not the Henry Hub
pricing scheme would pay us less than a crude-linked contract
would and neither presenter answered it.
MR. ABT apologized and said it is possible that the AKLNG
project could be priced through a Henry Hub-type pricing
mechanism, but the fixed price element of the contract would
need to be determined in order to make the project economic and
that has not been a part of this analysis.
SENATOR FRENCH said it's in the analysis before him and he
didn't know why neither analyst would say on the record that LNG
prices Henry Hub-linked tolling agreements are less that oil
linked contract prices.
CHAIR GIESSEL said Ms. Poduval had noted that transport costs
through the expanded Panama Canal were not known and that the
distance is much greater than between Alaska and Asia, and that
they had not, therefore, analyzed that scenario. But they could
certainly think about it and respond later.
4:06:44 PM
MR. PAWLOWSKI said he would be happy to work back through the
committee to Senator French's question. He thought Mr. Abt was
trying to say that the Henry Hub linked contracts have a
variable component, which is the Henry Hub price, and then there
is a fixed component, which is for recovery of the cost of the
infrastructure, and without knowing what that fixed component
looks like it's difficult to compare them.
SENATOR DYSON said the most recent contracts have a 14-15
percent effective slope and asked if it was a btu equivalent.
MR. ABT answered that the slope is what was used to convert the
LNG price from a crude oil price to an LNG price. In Asia it's
typically 14-15 percent. In simple terms, if a barrel of crude
oil is $100, the equivalent LNG price is $14-15/mmbtu.
4:09:50 PM
SENATOR MICCICHE said he thought the slide20 was incorrect and
that "mcf" should be "mmbtu."
MR. ABT said that was correct. With respect to the Henry Hub
pricing versus oil-linked pricing, in today's market the Henry
Hub price is at a level that is lower than the crude oil-linked
price. So, Gulf Coast projects, if they were in service today,
at Henry Hub prices would be lower than the oil-linked price.
4:10:38 PM
SENATOR MICCICHE asked if was safe to say that if those two
relationships were plotted over the last 20 years and likely the
next 30 years that they would be all over the place on value.
MR. ABT said yes, that was a fair statement. Tremendous
volatility has been seen in natural gas prices in North America
that would have suggested the Henry Hub-based price versus crude
oil would be very similar, in some instances even higher than
what the prevailing crude oil-linked price would have been over
the past 30 years.
4:11:25 PM
MR. PAWLOWSKI inserted that the full study is available on the
DNR commissioner's website under "Priorities," and the
consultants are in a video link describing some of the issues
the committee is wrestling with.
4:12:29 PM
MR. ABT went to the bottom of slide 20 and said non price
features are typically negotiated into the long term SPAs; they
include duration of contracts, the nature of commitment (take or
pay provisions), delivery terms (ability to pull the cargo and
take it to a higher value market or not take the cargo and allow
the seller to take it to an alternative location), and the LNG
specifications that he mentioned earlier.
SENATOR DYSON asked if the buyer can say he does not want to
take this cargo and the ship can go to another market with a
better price.
MR. ABT responded that a lot of the provisions are negotiated
depending upon the actual demand that a buyer may have at some
point in time or the flexibility that the seller would include
in its ability to divert a cargo. Typically, if the buyer has
purchased the LNG at the terminal - freight on board (FOB)
purchase - the buyer would control the flexibility of the tanker
on the open water. If they did not have sufficient demand to
justify delivery into the target market, they then would have
the ability to divert that cargo to an alternative market.
4:14:52 PM
MR. ABT said the demand forecast used by Black & Veatch for this
study and all their economic analyses was labeled the "Reference
Case." Slide 21 summarized several forecasts of projected LNG
demand growth over the next 20 years; in 2020 the range will be
40 million tons per annum, just over 5 bcf/day. The forecast is
a little more aggressive through 2015 and then is more
conservative from 2015-2030. The difference between the
Reference Case and the other forecasts was due to factors that
differ based on view of the markets, for instance, Asia has more
aggressive demand growth and they also believe Europe will have
more demand for LNG than what they see. They also expect that
other agencies are forecasting a much higher penetration in
transportation fuels for trucking and marine facilities than
what they used for the Reference Case.
4:17:27 PM
SENATOR BISHOP asked if the Reference Case kept with his theme
of "our assumptions in this study were made in a conservative
manner."
MR. ABT answered yes.
4:18:03 PM
He said slide 22 depicts the breakeven price for the AKLNG
project, and added that the breakeven price has no bearing on
the price of LNG. It also depicts the buildup of costs that are
necessary to construct this project and breaks them down into
components as follows:
-upstream costs on the left
-the cost of the LNG plant
-the cost of the GTP and the pipeline
-shipping from the terminus of the LNG plant to the market in
Asia
-the state's take (taxes that each agency collects throughout
the entire supply chain)
-the federal government's take
-zero MPV for the producer (an assumption)
The breakeven price is $12.30/mmbtu and takes into account the
capital and operating costs of the midstream (assuming an 8.5
percent discount rate).
Key factors that can cause the breakeven price to either
increase or decrease include a lower ambient temperature at the
LNG facility, which would cause the ability to generate LNG to
fluctuate; but perhaps the biggest factor is a projected change
in the capital costs, which already have a great deal of
uncertainty.
A decrease in capital costs or increased efficiencies through
the labor markets would result in a decrease in the breakeven
price. One other factor that might influence the breakeven price
downward is negotiating with the producers and having them
accept lower returns than what they typically look for in their
midstream investments (assuming an 8.5-10 percent discount rate,
and the producers would look for something higher than that).
4:21:52 PM
SENATOR MICCICHE asked if he was not using a particular ambient
temperature range for liquefaction conditions in his analyses.
MR. ABT said that was correct at this stage, but they had not
got into any of the detailed engineering that would optimize the
plant design.
4:23:05 PM
On slide 23 he compared the breakeven analysis for the AKLNG
project to all the other proposed LNG projects that have a
projected in-service date after 2014 and developed a global
supply curve. The breakeven price of the various projects was
plotted on the vertical line; each slice on the horizontal
access represented an individual LNG project that is currently
under development. The relative capacity of each of these
projects was determined by the width of the respective line
along the horizontal axis.
The box in purple represented the amount of new capacity
necessary to meet their projected demand in 2025. He explained
that the curve tells them that the AKLNG project as currently
configured in the current fiscal structure is out of the money
and that projects with lower breakeven prices than Alaska's can
provide about 340 million tons of new supply, which is more than
what is required to meet the projected demand of 250-300 million
tons in 2025. So, the AKLNG project faces significant
competition.
4:25:15 PM
MR. ABT said, however, due to many factors, not all of the
projects under development are going to be in service by 2025 or
even after, including many that are on the left of the AKLNG
project. Many include the U.S. Gulf Coast green field LNG
projects that are still seeking export authorization and have
yet to file for authorization from the Federal Energy Regulatory
Commission (FERC) to construct their facilities. So, it's highly
likely that many, if not all, of the green field projects in the
U.S. Gulf Coast will not be constructed. In addition, several of
the projects located to the left of the AKLNG project are
located in relatively unstable areas throughout the world. So,
the likelihood of those projects getting developed for multiple
reasons is also questionable.
SENATOR FRENCH asked what units of measurement he used on the Y
axis.
MR. ABT replied dollars per mmbtu, similar to the axis on slide
22.
SENATOR FRENCH asked if the $12.30 breakeven figure was the same
for both.
MR. ABT answered yes, for the AKLNG project. He added that they
had evaluated all of the projects throughout the world and the
relative value was depicted on the curve, the point being that
there are many projects at a breakeven price less than the
Alaska project that have the ability to meet the projected
demand in 2025.
4:28:24 PM
SENATOR DYSON said as Asian countries - Taiwan, South Korea and
Japan - have talked to them about gas and oil, he always had a
sense that one of the things that makes Alaska attractive is
political stability and that we are one of the few countries in
the world that could protect supply routes that ships use.
MR. ABT agreed that there was a great deal of concern over the
Suez Canal and the emergence of the Panama Canal as primary
water ways that are necessary to transport LNG from the U.S.
Gulf Coast to Japan and the markets in that region. Uncertainty
surrounds whether there will be additional costs on ships going
through the Panama Canal. So, having supply sources that don't
rely on those types of shipping logistics are particularly
attractive to the buyers in Asia.
SENATOR MICCICHE asked what causes the gap between where Alaska
is and the other projects in of projects being more economic
(slide 23). Is it the liquefaction plant costs or the midstream
costs?
MR. ABT answered that it is a combination of costs throughout
the project; one of the disadvantages that the AKLNG project has
are the costs associated with the pipeline and the GTP that are
necessary to take the gas from the North Slope down to the LNG
terminal. Typically, LNG projects developed around the world
don't have a large pipe component in their cost structure, and
although some treating is required it's not to the magnitude of
this project. Chevron's Gorgon project in Australia has a high
GTP cost, but they don't have a high pipeline cost associated
with it.
SENATOR MICCICHE said that the cost of the gas can really be
isolated to the extreme cost of the pipeline.
MR. ABT said that's a big component of the gap.
SENATOR FAIRCLOUGH asked if Alaska being in the red indicated
the volume of LNG that will be available to markets compared to
the size of the other projects (slide 23).
MR. ABT replied that the AKLNG project is one of the wider
rectangles on that graph and depicts that it is a large project
that will produce large volumes of LNG relative to other
projects they evaluated.
SENATOR FAIRCLOUGH asked when other markets are looking at
Alaska, if they might think of it as a prize, because it can
provide gas for longer term.
MR. ABT replied that typically an LNG project will have about
20-25 years of producible reserves, because that is what is
necessary to make the economics work. The AKLNG reserves
position clearly helps the project, but he wasn't sure that
gives it a significant competitive advantage over other projects
that are also competing to serve the markets in Asia.
4:36:35 PM
He moved on to slide 24 that addressed project factors that can
influence the price the AKLNG project might be able to obtain
for the production. Factors that would drive a higher price
environment, for example, would include the North American
projects, particularly the Gulf Coast projects being permitted
at a very slow pace, perhaps like now or even slower. If that
were to occur, then the non-North American conventional supplies
(Australia, Africa and Russia) would then compete to serve the
remaining demand, Alaska being one of those projects. Another
factor that could drive favorable pricing for Alaska obviously
would be for Asian demand to grow much more rapidly than what
they had depicted in their Reference Case.
Were all of this to occur, Mr. Abt said, the very high cost
projects in Australia and Russian would become the marginal
supplies, and Alaska is positioned very favorably relative to
those projects. And if there isn't an abundance of U.S. Gulf
Coast supply, sellers would be in a strong position to continue
demanding the high-sloped, oil-linked contract terms as opposed
to having to sell under Henry Hub pricing. In that case, he
would anticipate LNG selling for somewhere between $14-18/mmbtu.
Under the low price scenario, North America LNG supply would be
unconstrained, all of the proposed projects would get developed
and would all compete for markets in Asia. The low cost non-
North American conventional supplies would have to compete
directly with those projects, and in many cases would be
unfavorable and uneconomic. Under this situation, Henry Hub-
linked prices become the price setter for all Asian LNG into the
future. That would be an obvious down side scenario with a price
in the $10-14/mmbtu range.
MR. ABT said in both scenarios there is an opportunity for
Alaska to compete, but obviously in the higher price/higher
demand scenario there is a much better opportunity.
4:40:01 PM
SENATOR DYSON asked the decline rate for nonconventional gas
fields in North America.
MR. ABT answered the decline rate is very significant in the
early years of production and then it stabilizes over time. The
underlying assumption for the unconventional production is that
those wells will continue to be drilled, as there is a
tremendous inventory of prospects that will get drilled over
time if the price signals are sufficient to justify it. Rig
efficiency has improved, so more wells can be drilled with fewer
rigs and in fewer days. So, in spite of declining rig count,
current levels of production can be maintained. The expectation
is that U.S. gas supply in the Lower 48 will be able to meet all
of the projected demand going forward and, in fact, if the price
signal is strong enough, additional sources of supply, even
unconventional, can be brought on stream to meet it.
4:41:43 PM
He said the LNG market segment summary on slide 25 is
characterized by capital intensive projects and long term
contracts. All LNG projects are extremely expensive. The LNG
market is illiquid with very few players, which is in sharp
contrast to the oil market, which is very transparent and highly
liquid. LNG demand is expected to grow quickly over the short
and long term, but supply sources are also developing.
Currently, the AKLNG project appears to be out of the money
within the global LNG supply curve under the status quo
situation, although cost and fiscal modifications could enhance
its overall competitiveness.
4:42:49 PM
Slide 26 depicted supply chain elements, he said, and the study
provided an overview of the current capital cost estimates for
the AKLNG project as well as a quick review of the capital
structures that are likely to apply to and provided some
comparative projects to consider. Then they assessed the
commercial structures that might be applicable to the project.
Under slide 27 they were asked to look at the expected cost for
the project and to compare it to the initial 2008 estimate
developed during the Alaska Gas Inducement Act (AGIA) process.
Working with the state's technical consultants, he came up with
an estimate of $45 billion. The Producers' range for the GTP,
pipeline, and LNG project was in the $37-54 billion range (not
including upstream costs around Pt. Thomson.)
MR. ABT said what has driven the cost escalations in the past
five years have been modifications to the project's original
scope and cost escalation in labor and materials. In 2008, the
AGIA project was focused on building a pipeline to Canada; an
LNG project wasn't the primary focus. From the GTP perspective,
costs have escalated from $5 billion to $10 billion, primarily
because the scope got much bigger. The labor costs associated
with plant construction and owner costs have increased
significantly over time and going forward, they expect continued
uncertainty around the scope, the complexity of the project, and
the cost of the skilled labor that will be necessary to build
it.
The estimated pipeline costs have increased by about 50 percent
to $12 billion. Like the GTP, the pipeline has had a scope
change; initially it was scoped as a lower pressure 48-inch line
and now it's a much higher pressure 42-inch pipeline with a
significant amount of additional compression than originally
estimated. The costs in addition to the scope change have been
due to an increase in material (globally) and labor costs and
those could still increase more.
For the LNG plant, the costs have also risen significantly from
2008. Liquefaction costs have risen globally over that period
and now range from $1200/ton of LNG to $2500/ton. Here their
estimate is $1350/ton. Given the challenges of developing a
project in Alaska, specifically with respect to labor shortages,
material requirements and the logistics, he expected these costs
will be under continued pressure going forward.
4:47:42 PM
Slide 28 provided a brief summary of some of the capital
structures to show how they vary from project to project, and
depend on the risk profiles and the partner preferences. It
depicted capital structures of a few projects and each one
includes a partner in the AKLNG project.
He said that most LNG projects have some level of project
finance, although there are exceptions, and for projects of this
magnitude, long term sales and purchase agreements with credit-
worthy counterparties are essential to secure the financing. For
this study, they assumed a debt/equity ratio of 70/30.
The projects are:
-The PNGLNG project in Papua New Guinea is currently under
construction and scheduled to commence operations later this
year. It is led by ExxonMobil and has a 70/30 debt/equity
capital structure; it has some Japanese partners as equity
participants, which has enabled this project to secure low cost
financing. The PNGLNG consortium is responsible for marketing
the LNG from the project, and long term SPAs have been entered
into with Sinopec, Osaka Gas, Tokyo Electric Power and SPC in
Taiwan.
-The Australia Pacific APLNG is a fully integrated project in
which ConocoPhillips plays a lead role in the development of the
LNG plant. The project is also under construction and first LNG
is expected in 2015. It has a 70/30 debt/equity capital
structure. Sinopec is a minor partner, but they are also the
major off taker of the LNG accounting for some 85 percent of the
LNG produced. They have also entered into a contract with Kansai
Electric Power Company in Japan that has provided the assurances
necessary to the banks, so they were able to secure financing.
-Gorgon LNG is 100 percent equity-financed from the balance
sheets of the partners (Chevron, Shell. and ExxonMobil). It is
currently the world's largest integrated LNG project and is
expected to cost over $53 billion. It is currently under
construction with first LNG expected in 2015. Each partner has
retained its own equity lifting rights, so each will be
responsible for selling LNG from their respective portfolios.
Several SPAs have been entered into already.
4:51:09 PM
This project is the most similar to the AKLNG project. The
Producers preference is equity lifting rights and in an ideal
world they would like to finance it with 100 percent equity as
well.
4:51:29 PM
Slide 29 depicts the various commercial structures that are
available to State of Alaska and most LNG projects.
Three typical projects are looked at:
-Integrated: aligned interest, cost and risk sharing,
concentrated control amongst the partners
-Merchant: less capital requirement for the individual sponsors
and separation of control between upstream and LNG project
-Tolling: contractually assured fees and returns, accommodates
supply from multiple upstream sources, no market upside for LNG
project in and of itself
MR. ABT said each structure affects the operations and financing
costs of the GTP, pipeline, and the LNG plant, and it impacts
key criteria important to State; those being open access,
expandability, and transparency across the supply chain.
Slide 30 details the advantages/disadvantages of each structure:
-Integrated Structure Advantages:
• Equity owners may or may not act together to sell the LNG
product from an integrated structure
• Control over production
• Aligned interests between owners
• Cost sharing and potential tax benefits
Disadvantages:
• Capital requirements are high and span the supply chain
• Concentrated control makes expansions and entry of new
participants difficult
Merchant Structure Advantages:
• Lower capital requirement if sponsors of upstream and LNG
Project Co are different
• Meets tax requirements for separate P&L center
• Comply with local laws for government ownership of upstream
project
• Less control by upstream participants over liquefaction
facilities
Disadvantages:
• Less flexibility for equity participants in production of gas
and selling LNG - sold uniformly by LNG Project Co
• Commodity price risk exposure for LNG Project Co
• Can be mitigated with variations of the merchant model, for
example, by selling LNG back to project owners' marketing
affiliate to insulate the project from risk
• Exposure to negotiating power of upstream owners
4:55:11 PM
Tolling Structure Advantages:
• Contractually assured fees and returns to service contractor -
Low market risk to LNG Plant Co
- Mitigates upstream supply risk for LNG Plant Co
• Potential tax benefits if title transfers are taxed
• Accommodates supply from multiple sources, entities
• Ability to attract other investors/owners to project - lower
capital requirements
• Facilitates project financing since liquefaction project
revenues are not directly exposed to market risks
Disadvantage:
• No upside to commodity price escalation for the service
provider as the party paying for the toll does not realize this
benefit.
4:55:56 PM
MS. PODUVAL took up the presentation working off of slide 31:
how the risk of misalignment could play out and result in lower
revenues for the state. For instance, the Producers controlling
the upstream and the midstream could create a "closed black box"
that could place risk on the state's expected revenues from this
project. Producers could shift revenues between the upstream and
midstream segments as a way of increasing their take, thus
impacting the state's take. For example, a scenario where the
LNG plant service rates are established using an equity-rich
financing structure and assuming a relatively high return on
equity as well.
This also looks like it would be an integrated project and one
that may not be project financed, and any financing on a
company's balance sheet may not be transparent related to this
project. So, the actual capital structure as well as the cost of
the financing and the equity that is claimed by the company
could be an area of misalignment and potential dispute.
Slide 32 demonstrated three scenarios in which the tariffs could
potentially be set for the AKLNG through the GTP, pipe, and the
LNG plant, and the chart on the right looked at what the
corresponding state revenues would be in each of those
scenarios. The Reference Case on the left assumed a capital
structure of 70/30 debt/equity. Assuming a 12 percent return on
equity (ROE) would result in a tariff on the LNG plant of a
little over $6.70. The middle scenario was an extreme and
assumed the capital structure is 100 percent equity with a 14
percent ROE. This could impact the tariff that is claimed as a
deduction for the purpose of calculating net back on the LNG
plant; it's close to $11. The third scenario examines a 30/70
debt/equity assumption and still using the 14 percent ROE.
5:00:17 PM
MS. PODUVAL said the point is that the capital structure and the
ROE can have a significant impact on what the net back price
would be for the natural gas itself and, therefore, impact the
state's revenues, which could drop from $150 billion in the
Reference Case down to $110 billion.
5:01:09 PM
She said some potential safeguards can be provided by
regulations and guidelines on how the tariff would be set and
what acceptable capital structures would be and they could be
benchmarked, but that still wouldn't solve the potential for
misalignment including the state's need for transparency, having
open access, low tariffs, and being able to facilitate other
third parties to explore and develop the North Slope and be able
to monetize the gas.
5:01:38 PM
Transparency within a producer-owned project and cost allocation
will be an ongoing challenge for the state, Ms. Poduval said.
So, creating alignment between the state and producers is
critical for the state to receive full value for the AKLNG
project and to have access to information.
SENATOR FRENCH asked about shifting of revenues between upstream
and midstream on slide 31 and how that relates to the charts on
slide 32, which seems to depict different financing options and
their effect on the LNG tariff, mainly.
MS. PODUVAL explained that one example of value shift from
upstream to midstream could be if the project is financed not
just for the GTP, pipeline and the LNG plant separately, but
including capital costs associated with Pt. Thomson thrown into
the mix. In that case, it would be difficult to wade through the
web of information to understand what would be associated with
upstream financing versus midstream and downstream financing.
Some of the potential risk from the capital structure that the
slide 32 shows might be realized including the upstream as well.
5:03:50 PM
SENATOR FRENCH asked for a specific example, because there is
discussion about the construction of a pipeline from Pt. Thomson
to Prudhoe Bay to get gas into the system. And it sounds like it
might make a big difference to whether that capital cost for the
pipeline was included in the midstream element or the upstream
element as to how it affects the state's returns.
MS. PODUVAL said that was correct and she made a note to create
an example demonstrating that.
5:04:32 PM
MR. PAWLOWSKI said just to be clear on the left was the project
tariff that Senator French was representing correctly and on the
right were the SOA cash flows. Those colors break out into blue
as royalty, green as production tax, gray as corporate income
tax, and the yellow as property tax. One can see the financing
shift correspondingly. For example, in the Reference Case, one
can see $38.6 billion in royalty dropping in the 100 percent
equity, 14 percent ROE for the LNG plant down to $24 billion.
That is actually the quantifiable impact going on between the
increase in the cost and the effect on the upstream and coming
in at the reduction in the state revenues. He again reminded
them that this was not an analysis of the project going forward,
but an analysis of what issues and risks the state was looking
at going into the HOA and the MOU, and the drafting of SB 138.
In upcoming discussions he would show them how those issues were
addressed.
MS. PODUVAL said slide 33 summarized the section on supply chain
elements and that the capital costs for the AKLNG project are
likely to remain uncertain through the development of the
project. Total midstream project cost estimates from the AKLNG
project sponsors range from $37-$54 billion and they are working
with the Reference Case assumption of $45 billion. She said
complex LNG projects typically have an integrated commercial
structure to give sponsors maximum control. The AKLNG is
expected to have an integrated structure and that ensuring
alignment of interests between the State and Producers is
challenging and critical with a Producer-owned integrated
project.
5:07:49 PM
She said the third main scope item the royalty study addressed
related to the fiscal framework and its implications for the
AKLNG project. Specifically, they looked at what fiscal
structures relevant to LNG projects are worldwide and how they
compared to the AKLNG project, and what incentives the state
could provide to facilitate the project, and then assessed how
Alaska could leverage its royalty ownership position,
specifically using RIK versus RIV.
CHAIR GIESSEL said it seemed like they were entering into a
"pretty hefty section" and asked if it would be a good stopping
point.
MR. PAWLOWSKI said it was a good spot to pause as it deserved
fresh eyes and ready attention.
5:10:41 PM
CHAIR GIESSEL highlighted that the short videos on this issue
were available on the DNR website and included this section and
the next. [SB 138 was held in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| SRES Black&Veatch Presentation Revised 20140210.pdf |
SRES 2/10/2014 3:30:00 PM |
SB 138 |