Legislature(2013 - 2014)HOUSE FINANCE 519
03/28/2014 01:30 PM House FINANCE
| Audio | Topic |
|---|---|
| Start | |
| Presentation by Enalytica: Alaska Lng: Key Issues | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
March 28, 2014
1:39 p.m.
1:39:18 PM
CALL TO ORDER
Co-Chair Austerman called the House Finance Committee
meeting to order at 1:39 p.m.
MEMBERS PRESENT
Representative Alan Austerman, Co-Chair
Representative Bill Stoltze, Co-Chair
Representative Mark Neuman, Vice-Chair
Representative Mia Costello
Representative Bryce Edgmon
Representative Les Gara
Representative David Guttenberg
Representative Lindsey Holmes
Representative Cathy Munoz
Representative Steve Thompson
Representative Tammie Wilson
MEMBERS ABSENT
None
ALSO PRESENT
Janak Mayer, Partner, enalytica; Nikos Tsafos, Partner,
enalytica.
SUMMARY
^PRESENTATION BY ENALYTICA: ALASKA LNG: KEY ISSUES
1:39:54 PM
Co-Chair Austerman discussed the meeting agenda.
Co-Chair Stoltze requested that questions be held until the
end of the presentation.
1:40:29 PM
JANAK MAYER, PARTNER, ENALYTICA, provided a PowerPoint
presentation titled "AK LNG: Key Issues" dated March 28,
2014, (copy on file). He discussed his professional
background.
NIKOS TSAFOS, PARTNER, ENALYTICA, provided information
about his professional background.
1:42:37 PM
Co-Chair Austerman asked for the presenters to provide full
detail prior to using acronyms.
Mr. Tsafos provided an outline for the presentation. He
pointed to slide 4 titled "LNG Projects Evolve: QC LNG
(Australia) Case Study." He addressed the different
sections of the presentation shown at the top of the slide
including project pathways, alignment, equity, midstream,
risks, and cash-in/cash-out. The section on project
pathways focused on the current status and what may occur
going forward. He remarked that the term "alignment" was
the buzzword of the season. The company had done extensive
economic modeling to determine whether equity was a good
deal for the state; whether taking ownership of the project
made sense. He intended to address the financial and
nonfinancial aspects of the midstream portion of the
project including the proposed partnership with
TransCanada. Additionally, they intended to address risks
to the state and various ways it could mitigate risk.
Lastly, they would talk about money - what the state may be
expected to invest upfront and what it could expect to earn
over the project's lifetime.
Mr. Tsafos relayed that Liquid Natural Gas (LNG) projects
evolved quite dramatically from inception to the time they
went online. The slide depicted an example of the
Queensland Curtis LNG project in Australia beginning with
the FEED [Front End Engineering and Design] stage. He drew
attention to the fact that Alaska LNG as proposed was
looking to initiate a pre-feasibility study and would move
to a FEED stage in 1.5 to 2 years. The slide indicated
significant change that could occur between the FEED stage
and project completion. He noted the project in the example
was not online yet.
Co-Chair Austerman asked for an explanation of the FEED
acronym.
Mr. Tsafos replied that FEED stood for Front End
Engineering and Design. He explained that the FEED stage
was a project's most extensive study that was conducted to
determine whether a project was viable. The final stage
called the Final Investment Decision (FID) occurred once a
project had been deemed viable by the companies involved.
He detailed that when the Queensland Curtis LNG project had
entered the FEED stage it had been conceived as a "one
train" unit of volume of 3 million to 4 million tons (with
the potential to expand to 12 million tons). The upstream
was owned by a British company BG and by Queensland Gas
Company (QGC). The liquefaction ownership was 70 percent BG
and 30 percent QGC. The off-take of the gas was 100 percent
BG. When the project had reached FID two years later the
project size had expanded to 8.5 million tons. Upstream
ownership had shifted primarily to BG with the China
National Offshore Oil Corporation (CNOOC) and Tokyo Gas
acquiring a small portion.
1:49:12 PM
Mr. Tsafos continued to discuss slide 4. The liquefaction
had also shifted to 90 percent BG ownership and 10 percent
CNOOC ownership in the first train and 97.5 percent BG
ownership and 2.5 percent Tokyo Gas ownership in the second
train. Additionally, the CNOOC and Tokyo Gas had been added
as buyers.
Representative Gara asked about the acronym mmtpa. Mr.
Tsafos replied that the report included a unit section. He
relayed that 7.8 mmtpa [million metric tonne per annum] was
equal to 1 billion cubic feet (bcf) per day. The project
shown on slide 4 was slightly over 1 bcf per day.
Representative Gara surmised that it was about one-third or
one-quarter the size of the proposed Alaska LNG project.
Mr. Tsafos replied that the Alaska LNG project was slightly
over 2 bcf per day (the project shown on slide 4 was about
half the size of the AK LNG project). He continued to
address slide 4. In January 2014, the Queensland Curtis LNG
project had remained the same size, but CNOOC had taken a
larger percentage of the upstream. The liquefaction
ownership had changed to 50/50 for train 1 and CNOOC had
acquired an option for a possible third train if an
expansion took place. The project off-take had increased
beyond the project's capacity with the idea that BG would
supplement sales from its other projects. Financing had
been secured from the Japan Bank for International
Cooperation and $1.8 billion had been secured from the U.S.
Export and Import Bank. The slide's purpose was to
demonstrate how things changed; it was useful to think
about where the project was at present, but many changes
would take place before the project came online. He
elaborated that new partners may join the project, some
partners may leave, and buyers were yet to be determined.
He noted that financing had not been secured until the
after the FID stage for the Queensland Curtis LNG project.
1:52:39 PM
Mr. Tsafos turned to slide 5. The slide depicted a timeline
for Alaska LNG and addressed what may be expected to occur
at different development stages. Subject to the passing of
enabling legislation the project would begin in the pre-
FEED stage, which provided a "first pass" to determine
project viability. The project seemed to make sense;
however, whether it would cost $45 billion or $65 billion
was unknown. Due to the broad spectrum of potential costs
it was necessary to narrow the estimate down in order to
make a decision. There may be some preliminary marketing
agreements; related documents included the Memorandum of
Understanding (MOU), the Heads of Agreement (HOA), and a
State of Alaska (SOA) plan. It was possible to move through
the entire pre-FEED stage without securing any definitive
gas sales plans. Preliminary work may include travel to
Asia to determine whether the market was amenable to
purchasing gas from Alaska. The state would need to reach
out to private and sovereign financial institutions to
determine whether investors were interested in the project.
Defining the initial structure would cost between $400
million to $500 million; whereas the state's investment
would be between $50 million and $120 million. He relayed
that the range depended on the total cost and whether
TransCanada partnered in the project.
Mr. Tsafos continued to discuss slide 5. The project would
advance to the FEED stage if the pre-FEED results were
positive. The transition went from the concept stage to the
detailed blueprint stage. The finalization of marketing and
financing plans began in the FEED stage including how much
the state could borrow, the rate, and implications. The
FEED stage could cost between $1.5 billion to $2 billion
with the state's cost ranging from $200 million to $500
million. At any point during the FEED stage new partners
may sign on and ownership may be refined.
1:56:01 PM
Mr. Tsafos continued to discuss slide 5. Once it was
determined that the project would move forward the FID
stage began; construction took place and the majority of
the cash was spent. Additional partners and financing could
still be secured during the FID stage. He relayed that it
would be 4 or 5 years before the state would know whether
it wanted to authorize spending to move into the FID stage.
He discussed the challenge was that more information was
wanted for the state to make an informed decision, but
gaining more information required going through the
process. The process had to be taken step by step. The
point of the slide was to address where the project was in
the process at present and what would need to happen before
it came online.
Mr. Mayer addressed slide 6. He highlighted two agreements
the legislature had to consider including the HOA that it
would sign with the producers and TransCanada and the MOU
that it would sign only with TransCanada. He discussed that
currently the state was a taxing and regulating authority;
it drove value from its oil and gas assets through leases
to private sector participants. Production tax and
royalties were currently determined by the value of the
commodity at the point of production (i.e. the North Slope
wellheads). As a result the state had no direct stake in
the upstream assets and under the status quo it would not
have a stake in the rest of the project; it would be a
recipient of value (net of all transportation costs) based
on a percentage of tax and royalty at the wellhead. The HOA
was a nonbinding document that laid out a vision for an
alternative; instead of taking value at the wellhead the
state would be a participant in the project and would
receive its share of project value in-kind in the form of
gas at the point of production. The state would not
participate in the upstream, but it would have a share of
the gas and a corresponding share of gas treatment
facilities, pipeline, and liquefaction project. The HOA
posited a state share somewhere between 20 and 25 percent;
the figure was more likely to be 25 percent (as reflected
on slide 6). The state would have 25 percent of the gas and
25 percent of the infrastructure facilities required to
eventually sell the gas as LNG to Asian buyers. The MOU
contemplated what may happen with the state's share of the
gas treatment plant (GTP) and the pipeline.
2:01:29 PM
Mr. Mayer addressed alignment and why the state may have an
interest in the concept. He stressed the importance of
long-term stability for large scale LNG projects. First,
LNG projects tended to involve enormous upfront capital
expenditures ($45 billion to $60 billion for the Alaska LNG
project) with relatively low levels of operating
expenditure and a long and steady cash flow year after
year. From the perspective of private sector investors the
purpose of investment was to make one large upfront
investment, which was followed by years of steady and
predictable cash flow. He detailed that the predictable
cash flow was necessary because in order to finance the
upfront capital the overwhelming bulk of LNG produced was
sold under long-term contracts; typically 20-year take-or-
pay contracts. He explained that under take-or-pay
contracts a buyer signs up to take a volume of LNG and
agrees to pay even if they are not able to receive it for
some reason. The security of the long-term contracts
enabled projects to move forward; it was important for
investors to understand what economics looked like in the
future after committing significant capital. He elaborated
that a significant number of items would be locked over a
20-year period; therefore, it was important to understand
what revenues and costs would be over time. He mentioned
the possibility of disputes related to costs and what
investors were entitled to; the potential for a dispute was
scary from the perspective of investors, particularly when
investing $45 billion to $65 billion.
2:05:28 PM
Mr. Mayer continued to address stability over time and why
alignment may be in the state's and producers' interest
(slide 7). He listed items to consider including how oil
differed from gas and lessons that could be learned from
the past related to North Slope oil production and the
Trans-Alaska Pipeline System (TAPS) pipeline. Calculations
on slide 7 had been used from the Department of Revenue
(DOR), Revenue Sources Book projections related to royalty
and production tax. He pointed to the DOR FY 15 projected
price of $105.06 per barrel of oil at the top of the slide.
To reach the gross value at the point of production,
transportation costs of approximately $10 per barrel were
subtracted ($3.50 for marine transportation, $6.18 for TAPS
tariff, and other); the state's royalty value was
calculated from this figure. Additionally, after lease
expenditures ($45.99 in FY 15) were subtracted the state
could levy production tax on the remaining amount ($48.64
projected in FY 15). He noted that credits would be applied
later.
2:08:07 PM
Mr. Mayer turned to slide 8 and addressed alignment and oil
versus gas prices. Determining gas revenue would be
different from oil. He explained that oil prices were
published daily; whereas, there was no global market or
quoted price for gas. The price of gas depended on the
cargo of LNG and under the contract it had been delivered.
Gas was priced differently in Asia than in Europe or the
U.S. and could vary between contracts. The highest price of
LNG going into Korea over the past year was almost double
the price of the lowest priced LNG going into Korea during
the same time. He detailed that the LNG going into Korea
had been sold under long-term contracts based on indexation
to oil; however, the indexation varied widely between
contracts. Subsequently, some cargo may have been delivered
from $8 to $10 per million btu (mmbtu) under some contracts
or for $15 per mmbtu or more under others. He stated that
the actual gas price was variable based on location and was
far from transparent; the price would likely be linked at a
discount to the Japan Customs Cleared (JCC) price of crude
oil. Gas was sold on the basis of thermal equivalency;
however, the same price based on heat content would not be
received for LNG compared to oil. Currently a typical gas
contract may bring in around $80 when oil was $100. He
spoke about a regression formula.
2:11:56 PM
Mr. Mayer addressed the tariff on slide 9. He relayed that
the tariff for gas would be much higher than it was for oil
(gas tariff shown on slide 10). He elaborated that there
may be different scenarios determining how a pipeline
tariff was set. He shared that the liquefaction project was
within the jurisdiction of the Federal Energy Regulatory
Commission (FERC); only FERC could regulate a tariff, but
currently the agency did not regulate tariffs on LNG export
projects. He described the liquefaction component as a
"black box" with scope for substantial changes in capital
structure without significant state insight. He elaborated
that the tariff was sensitive to debt, equity, and
allowable returns.
Mr. Mayer directed attention to slide 10. The slide showed
an average LNG price of $81.00 per barrel with a tariff
price of $66.00. The slide included minimal operating and
capital expenditures totaling $6.00 per barrel. With the
subtractions the production tax value would equal $8.82
under the current tax structure.
2:14:50 PM
He moved to slide 11 related to the midstream. He
communicated that fair market price was critical in
establishing a solid top line and that the overwhelming
bulk of the value was likely to reside in the midstream;
upstream was secondary to midstream and often the wellhead
value was insufficient to drive value to the state
(particularly when prices were low). He discussed LNG
production at different price levels using the price of a
barrel of oil equivalent. Slide 12 included a bar chart
showing prices ranging from $110 down to $70 per barrel of
oil equivalent or $18.33 per mmbtu down to $12.08 per
mmbtu. The slide depicted a scenario in which the state was
a taxing regulating authority at the wellhead where it
generated everything based on value at the point of
production. He pointed to large deductions that were the
first claims on the cash coming from selling the LNG
including tariff, transportation, shipping, liquefaction,
pipeline, and gas treatment; all the items could be
deducted prior to the assessment of value at the gross
point of production. He explained that a deduction of $66
from a price of $110 still meant substantial value was
remaining; however, it did not take a large drop in price
to reach a point where there was no value to the state
remaining. He elaborated when oil was $70 per barrel and
gas was at $12.08 per mmbtu there would be no value left
for the state to take in the form of royalty or production
tax. He explained that the return on capital for the
significant investment in the midstream was guaranteed to
companies making the investment; the wellhead price was the
shock absorber that took the price risk.
2:18:02 PM
Mr. Mayer relayed intent to show what value for the state
looked like across a range of possible scenarios
specifically when prices were high or low. He pointed to
slide 13 related to equity methodology. There were two
basic cash flows that would come to the state if it were an
active investor and participant in the project (as
envisioned under the HOA). The state would earn revenues
from selling LNG to Asia (the volume of LNG sold multiplied
by price). There were also a number of expenditures that
would need to be removed to reach the net cash flow to the
state including initial capital expenditures, operations
and maintenance expenses, debt service (principal and
interest), and tariff paid to a partner (i.e. TransCanada).
The state would also receive cash flows from sovereign
functions including state corporate income tax and property
tax from the state as a whole.
2:20:27 PM
Mr. Mayer addressed four cash flow scenarios on slide 13.
The initial analysis was more about taking the state's
value of a taxing regulating authority versus taking it as
a project participant. The presentation would address what
the economics looked like under four cash flow scenarios
(slide 13):
· No debt and no TransCanada partnership
· No TransCanada partnership but the state finances
70% of its share with debt
· TransCanada is a partner and the state exercises
its buyback option
· TransCanada is a partner and the state does not
exercise its buyback option
Mr. Mayer relayed that the presentation would address total
cash flows to the state and whether it would be useful to
subtract out the 25 percent royalty that went to the
Permanent Fund Dividend (PFD) and property tax that went to
municipalities. He communicated that it was important to
keep in mind that the project still needed to go through
the pre-FEED and FEED stages. He stated that currently
there was not a project to conduct a cash flow analysis on.
Any numbers presented to the legislature currently were
based on educated guesses on potential costs, a range of
structures, and revenues. He acknowledged that the
information could be very useful for directional analysis.
The goal behind running numbers presently was not to
predict that the state would receive $3 billion to $4
billion in annual revenue into the future and what would
need to be spent. The items all came with significant
caveats because much was unknown. The basic idea was to
predict what the items would look like given a range of
assumptions if the state took value at the point of
production as a taxing regulating authority or a
participant, what it could look like over a range of
prices, and how the variables interacted. He stated that
clearly there was not currently enough information to
determine whether the project should move forward; if the
information was known the state would not need to spend
hundreds of millions of dollars on feasibility work and
analysis to nail down the numbers.
2:23:45 PM
Mr. Mayer turned to slide 14 titled "SOA Equity Leads to
Higher Government Take on Average." He remarked that the
committee had received a different but similar analysis
from Black and Veatch. He believed the models that made
different assumptions and ran different numbers were
directionally similar in their conclusions related to value
to the state. The left chart showed a status quo scenario
where the state would remain a taxing regulating authority
taking its value by receiving a royalty in value at the
wellhead and levying a 35 percent production tax. The green
bars represented the overall share of the total project
value for the state. The other charts showed what the
state's value would look like if it had a share of the gas
and a corresponding equity stake in the project (20 percent
in the middle chart and 25 percent in the right chart). The
slide showed that the state would receive good value for a
project in a status quo scenario (with the state as a
taxing regulating authority) if current LNG prices of $15
to $18 mmbtu could hold for a long duration; value could be
better than what the state may receive if it went with
equity in-kind. However, when prices decreased, the state's
value fell much faster if it was only a taxing regulating
authority at the wellhead. He explained that when all of
the value came at the point of production, after everyone
invested in infrastructure to transport the gas from the
North Slope into Asian markets had been paid a fixed and
guaranteed rate of return on their investment, the state
was the variable source baring the price risk. The state's
value remained steadier in the middle and right charts (the
state received the highest share at low prices). Under a
scenario where the producers and the state each had a 25
percent share the state would receive a larger percentage
of the value if the state's sovereign functions were
removed; the reason was due to the difference between a
private sector participant and a sovereign participant in
the project. The state had sources of cash flow from
sovereign functions (state corporate income and property
tax) and from producers. As long as the structure was
correct the state should not be liable for federal
corporate income tax; whereas, producers were (as shown in
blue on slide 14).
2:29:02 PM
Mr. Mayer addressed slide 15. When prices began high and
decreased the value to the state in the "in value" world
was very susceptible to movements in price and could
quickly disappear. The slide looked at total cumulative
cash flows over the life of the project. The previous
slides looked at a share of value to the state that added
to 100 percent at both low and high prices. He noted that
the total value was much smaller than in a high price
world. Data shown on slide 15 used pure, undiscounted
cumulative cash flows over the lifetime of the project and
indicated how value was distributed between involved
participants. In a high price world there was substantial
value to the state as a taxing regulating authority (shown
in the left chart). He reiterated that as prices declined,
value to the state decreased quickly; the state would
receive more value if it were an in-kind participant with a
corresponding equity share. He added that the bigger the
state's share the more value it would receive; under the
scenario the state's value was subject to its total capital
commitment to the project and the amount producers were
willing to share. He communicated that going in-kind with
equity counterintuitively provided more downside protection
to the state when prices were low; whereas, the in-value
status quo structure provided less value to producers when
LNG prices were high, but protected them better from the
downside. Under the in-kind with equity structure producers
were more exposed than the state.
2:32:10 PM
Mr. Mayer relayed that the information summarized
enalytica's high level perspective on the HOA and on the
state going from a taxing regulating authority to an entity
taking a share of the gas and facilities. He asked members
to think about what alignment was like when there was a $10
tariff on $100 of value. He asked them to think about the
past couple of decades of litigation related to what the
real tariff was or should be and what the value to the
state was or should be. He spoke to the creation of
uncertainty on future project value. He then asked members
to think about a tariff of $66 on an $80 per barrel of oil
equivalent (delivered to Asian markets) and all of the
incentives it created. He highlighted the concept of
spending $45 billion to $65 billion of capital to the
project based on 20-year contractual commitments. He stated
that alignment was fundamental to the project and the
reasoning behind the proposed structure because the tariff
essentially went away and all parties had a share of the
infrastructure and gas. Additionally, under the structure,
all parties would make their money by selling LNG to Asia
(transportation costs were subtracted); whether the value
happened at the wellhead, through the pipeline, or at the
liquefaction plant was no longer an issue or a source of
dispute and arbitration. He believed that combined with the
mitigation of price risk to the state, the structure was an
attractive option to consider provided that it had a
sufficient share of the project to generate value (i.e. 25
percent) and that a range of items were negotiated (e.g.
disposition of the state's share of LNG).
2:36:56 PM
Mr. Mayer continued to discuss slide 16. He addressed the
MOU agreement between the state and TransCanada related to
the gas treatment and the pipeline. The slide showed the
HOA with 25 percent state ownership in the GTP and
pipeline. The MOU gave the 25 percent to TransCanada in
return for TransCanada using its capital to build the GTP
and pipeline facilities; TransCanada would recuperate the
capital in the form of a tariff. He noted that TransCanada
would not have a share in the LNG. The slide showed a
second MOU option where the state would have no direct
equity in the GTP and pipeline, but it would have 25
percent ownership of LNG. The MOU also contained an equity
buyback option where the state could buy back up to 40
percent of its initial 25 percent investment (up to 10
percent of the total) in the GTP and pipeline before the
end of 2015. He elaborated that a TransCanada subsidiary
vehicle would hold the overall 25 percent share and the
state would own 10 percent of the total as a limited
partner. The state would be liable for a tariff to
TransCanada, but the upfront capital required would be much
less.
2:39:20 PM
Mr. Mayer highlighted potential financial and non-financial
benefits and drawbacks of the MOU on slide 17. The first
financial benefit was that the state would not be obligated
to meet a substantial portion of the capital cost upfront.
He estimated that $22 billion to $25 billion of the $45
billion to $65 billion project would be for the GTP and
pipeline; the state's share would be 25 percent. He relayed
that the state would not be required to meet the obligation
upfront if it faced capital constraints. He noted that the
state would ultimately reimburse TransCanada in-full
through a tariff and would enter into a firm transportation
services agreement over time. The state-owed debt could be
in the form of a bond, loan, or tariff, which were
equivalent in some ways. He believed further analysis on
the fundamental difference between the debt reimbursement
options was necessary in terms of understanding the state's
debt service capacity, borrowing costs, and how ratings
agencies thought about the items. He questioned whether the
capital cost would be fundamentally shifted from the
state's books or whether the result would be less clear.
2:41:56 PM
Mr. Mayer continued to highlight MOU benefits on slide 17.
Data indicated that the MOU held attractive tariff terms
relative to market norms. Additionally, the MOU would allow
the state to exit from potential Alaska Gasline Inducement
Act (AGIA) liabilities. He spoke to financial costs
occurring under the MOU. Tariff costs would be higher than
the cost of capital the state would have if it were able to
finance the project on its own. Also, the state would be
required to reimburse TransCanada in full with 7.1 percent
interest in all circumstances (even if TransCanada decided
to terminate). He discussed that the agreement could be
terminated by the state if the project was determined
uneconomic or if TransCanada could not get adequate
financing.
2:44:20 PM
Mr. Mayer discussed the non-financial benefits of
TransCanada's involvement. TransCanada would be an
expansion-oriented partner, which would be important to
drive future expansion development to the remainder of the
North Slope and into Arctic waters. Unlike producers that
made money selling the gas to market, TransCanada would
make money transporting gas through the infrastructure;
having a partner that cared about expansion was important.
A presence at the negotiation table and a partner with
expansion execution capabilities were clear benefits to the
state. Additionally, the state would benefit from the
continuity and momentum to move forward without setbacks.
One non-financial drawback was that the state would bear
most of the risk under the MOU; TransCanada would be "made
good" in most circumstances. There was some financing risk
to TransCanada; the company bore the risk of not receiving
the same 12 percent return on equity (ROE) outlined in the
MOU if it could not raise sufficient capital; however, the
company had the right to terminate if financing was not
available. He questioned how much the return could
deteriorate before TransCanada decided to exercise its
termination agreement or to renegotiate with the state. The
state would also be a limited partner under the MOU and
therefore it would give up significant control (the general
partner would make the majority of the decisions).
2:47:44 PM
Mr. Mayer summarized slide 17. He stated that there were
clearly many things to like about the proposed MOU (e.g.
transitioning from AGIA and the involvement of an
expansion-oriented partner); however, there were costs to
assess as well. He turned to slide 18 related to the tariff
benchmark. The slide included 2012 capital and debt
structure information for all FERC regulated pipeline
companies. The left chart debt reported to FERC ranged from
zero to 34.7, 40.2, 46.7, to 68.1 percent. He detailed that
25 percent of the companies reported a level of debt
between zero and 34.7 percent; the next 25 percent reported
debt below 40.2 percent. He noted the median was 40.2
percent. The next quartile reported debt between 40.2 and
46.7 percent; the remaining 25 percent reported debt
between 46.7 and 68.1 percent. He applied the information
to the MOU where there would be a 75/25 debt-to-equity
structure for the initial phase of the pipeline.
Mr. Mayer explained that the MOU debt-to-equity structure
was quite aggressive based on the other figures; the median
debt-to-equity for companies reporting to FERC was 60 /40.
Rate making capital structures were ideally established
based on a correlation to the capital structure
underpinning the pipeline; it was a set number that
determines the eventual rate of return allowed to the
company in setting a tariff; the rate was determined on
both the debt and equity components. The higher the debt
used to set the rate, the cheaper the eventual weighted
average cost of capital used in the rate would be. The
proposed debt to equity was attractive because the lower
cost of debt combined with the greater component of debt
reduced the tariff to the state. He pointed to the average
cost of debt between 2.5 percent and 9.8 percent (right
chart), with a median around 6 percent. The chart showed
the average cost of equity between 9 percent and 18.5
percent, with a median around 12.5 percent. The project's
proposed cost of debt was 5 percent and equity was 12
percent; both figures were well within market norms. The
project's weighted cost of capital was 6.75 percent
compared to the 6.5 percent to 14 percent range for
companies reporting to FERC.
2:52:06 PM
Mr. Mayer turned to a chart on slide 19 and relayed that
historically FERC ROE had been higher than returns in
Canada. He addressed how FERC returns historically compared
with the Canadian National Energy Board (NEB). The black
line represented NEB ROE rates over time and the dots
represented FERC approved litigated cases and approved
settlements. The chart indicated that overall there was a
lower allowed return on equity under the NEB formula. The
FERC numbers tended to be around the 12 percent to 14
percent range; whereas NEB numbers had started out at that
range and had dropped to 8 percent and 9 percent in the
past decade. He detailed that many companies had sought
higher returns from NEB through litigation. He referred to
a recent TransCanada report citing two to three cases of
successful settlements with NEB where rates had gone from
the 8 percent level to the 12 percent level (based on the
60/40 percent debt to equity split). He communicated that
based on a 75/25 percent debt to equity with a cost of
equity around 8 percent or 9 percent the weighted average
cost of capital would be around 6 percent. He relayed that
based on the figures the proposed structure looked like a
good deal.
Mr. Mayer looked at three charts showing total value titled
"TC's Share of Cash is Highest at Low Prices" (slide 20).
The left chart showed a scenario of value for the state and
partners without TransCanada. The middle and right charts
included TransCanada with no buyback option and with a
buyback option respectively. He emphasized that TransCanada
would only receive 25 percent of the infrastructure return,
which did not include a share of the gas; the company would
take value from the state, but the amount was not enormous.
He explained that ultimately value would come from moving
gas through infrastructures and selling it to buyers in
Asia. The value to TransCanada was highest when prices were
low; it was a fixed claim on the state's cash. He
elaborated that under a no-buyback scenario with the lowest
prices TransCanada may receive 7 percent of the total cash;
however, with high prices and a buyback provision, the
total cash to TransCanada may only be 1 percent of the
total.
2:56:09 PM
Mr. Mayer turned to slide 21 titled "Limited Value Foregone
Under TransCanada W/ Buyback Option." He explained that
cash outlays under a 25 percent equity share with
TransCanada and a buyback option were comparable to a 20
percent share without TransCanada. The slide showed
cumulative cash flows over the life of the project (left
chart) and net present value to the state (right chart).
Overall the value to the state (particularly when a
discount was factored in for the time value of money and
TransCanada's footing of upfront costs) looked relatively
closer to the 25 percent share as opposed the 20 percent
share. Under a scenario where the state could not do the
project on its own, the MOU and transportation services
agreement could make the project affordable for the state;
however, much remained unknown at present regarding the
state's ability to finance the project.
Mr. Mayer addressed key questions related to the midstream
on slide 22:
· Should the state reimburse TransCanada's expenses
under all scenarios; even if the project is a no-
go?
· What does this imply for risk/reward split and
appropriate locus of control?
· How firm is 'off ramp' if state must offer
TransCanada participation if it continues with
project within 5 years?
· Should non-participants in an expansion benefit
from lower costs if they share no risks of higher
costs?
Mr. Mayer elaborated on slide 22. He asked whether the all
the risk should be on the state if TransCanada decided to
not make the final investment decision. He referred to the
third question and added that the cost of debt and equity
would be negotiated at the time based on conditions at the
time. He believed it was important to ask what it would
mean if the state decided it could finance the project on
its own. Under the scenario, he asked whether the state
could communicate its cost of capital and ask TransCanada
if it could compete on the cost of capital and debt or
whether it was more complicated.
3:00:35 PM
Mr. Tsafos addressed risks associated with the project on
slide 23. The largest risk was that the project would not
get built. The slide included a world map comparing Alaska
to other locations looking to develop LNG. Other locations
included Western Canada, the Lower 48, Brazil, eastern
Mediterranean, Qatar, Russia, Africa, Australia, and
Southeast Asia. He referred to the high expense of the
Alaska LNG project. He communicated that it was possible
for the state to compete, but it was not a given. He moved
to a map representing the mid/late 2000s on slide 24 to
demonstrate the point. The map showed where analysts had
predicted that new LNG would come from at the time. He
listed various world locations where projects had been
proposed that had not happened including Alaska, Venezuela,
Trinidad, Norway, Russia, Algeria, Libya, Egypt, Nigeria,
Equatorial Guinea, Qatar, Iran, Myanmar, Brunei, Tangguh,
and Papua New Guinea. In the past it was not the cheapest
gas or most attractive project that came to fruition; the
project that got built was the project that could get
built. He elaborated that many locations were cheap, but
politics, technology, or other things got in the way. He
relayed that just because the Alaska LNG project was
expensive, did not mean it could not happen.
3:04:38 PM
Mr. Tsafos turned to slide 25 related to various financing
options open to LNG projects. He discussed specifics
associated with balance sheet finance:
· Project sponsors provide funds
· Funds can combine debt and cash flow
· Guaranteed by project sponsor (recourse)
· Rate depends on sponsor's balance sheet
· Easier if all parties have strong balance sheets
Mr. Tsafos discussed project finance, the second form of
financing (slide 25):
· Third parties lend to project directly, not to
sponsors
· Sponsors put up some equity (e.g. 30 percent)
· Guaranteed by projected revenues (non-recourse)
· Rate depends on project risk
· Easier to accommodate riskier options
Mr. Tsafos explained that because money was lent to the
project, what it earned was important; earnings would be
driven by gas contracts. Ultimately, the project itself
mattered when thinking about the rate (e.g. whether the
project could happen, were contracts worthwhile, etc.). He
elaborated that project finance was attractive, especially
when there were riskier sponsors. For example, if a company
was trying to do an LNG project in Qatar in the mid-1990s
and the state of Qatar had declared bankruptcy, the company
may want to think about project finance as an option. He
continued that under project finance because money was not
lent to the sponsor, the debt did not show up on the
sponsor's balance sheet. Whether or not the State of Alaska
wanted to recognize the debt would be something to
determine. He relayed that it was useful to remember that
different financing options existed; the options had
different implications for the state's balance sheet. He
addressed various questions including the right mix of debt
and equity, debt to the project or the sponsors, whether
equity would come from reoccurring revenues or other money,
and other. He explained that the different answers to the
questions would provide very different impacts in terms of
the state's ability to borrow and finances to the state.
3:08:37 PM
Mr. Tsafos continued to discuss project finance on slide
26. He noted that it may be tempting to think that project
finance sounded like a great option because it would be off
the balance sheet and that debt would be guaranteed through
project revenues, while wondering who would lend money to
such a large project. He pointed to recent examples of LNG
projects and relayed that large amounts of capital existed
for big LNG projects. The Ichthys project in Australia had
secured $20 billion in project finance and a Papua New
Guinea project secured $14 billion from ExxonMobil and
others. He detailed that frequently the capital came from
official sponsors. For example, the mission of the Japan
Bank of International Cooperation was to support Japanese
companies investing overseas with the goal of importing
natural resources into Japan; the company was willing to
provide interest rates significantly below market. He
concluded that once the state began working through
financial options, aspects, and rates, it may discover that
the underlying burden was much different; it was not yet
known and was something to study over the next few years.
He summarized that it was not worth getting sticker shock
up front because the picture would change over time.
Mr. Tsafos spoke to three additional aspects of risk on
slide 27 titled "Project Finance well Established in LNG."
He highlighted that price risk associated with oil involved
price fluctuations in ANS West Coast pricing; whereas LNG
would most likely sell at a price linked to oil. He
elaborated that a formula specifying that if the price of
oil was $100, the price of gas would be $14 per mmbtu. He
stressed that when a contract was signed the relationship
was locked; therefore, risk was associated with the price
of oil. The chart showed three long-term LNG supply
contracts for Taiwan with Indonesia, Malaysia, and Qatar.
He detailed that the price paid by Taiwan was linked to
oil; however, that did not mean it would be the same price
under different contracts. For example, at an oil price of
$120 the price of LNG was $6 or $7 with Qatar, but at the
same price of oil the price of LNG was over $20 with
Indonesia. The most important factor was what had been
negotiated in the finalized contract; knowing the numbers
before investing in the project was beneficial. He pointed
to an original contract with Malaysia (red) and a
renegotiated contract (blue); the contract had been
renegotiated after Malaysia determined it was not receiving
a fair deal out of the price. Due to their long-term nature
every contract allowed for price review and renegotiation,
which could be defined in the contract. He discussed that
the state may hear something like the Lower 48 was offering
gas to Asia that was not linked to oil. He stressed that if
the state had a contract that was linked to oil in a
specific formula, it really did not matter what another
seller did later because the state's relationship would be
locked; the price could only be revisited per the contract
agreement.
3:14:14 PM
Mr. Tsafos addressed slide 28 that outlined options to
reduce exposure. The chart on the left titled "No S-Curve"
showed a scenario where the price of LNG rose with the
price of oil. There were ways of hedging against the
volatility of oil price as shown in the middle and right
charts. The middle chart titled "S-Curve" showed a scenario
where the price of gas did not drop as fast as the price of
oil; usually this option could be negotiated by foregoing
some of the upside. The chart on the right titled
"Floor/Ceiling" depicted a scenario where LNG would not
drop below $12, but would not increase beyond $17 to $19.
He concluded that there were ways to contractually reduce
some of the state's exposure as contracts were negotiated
in order to fit a comfortable revenue profile. He relayed
that several more expensive projects had utilized the
floor/ceiling method. Project sponsors did not want to
invest only to realize later that they were out of the
money; therefore a floor/ceiling option could make sense if
they were willing to give up some of the upside.
3:16:16 PM
Mr. Tsafos addressed risk associated with cost overruns on
slide 29. He communicated that cost overruns were a fact of
life in large-scale projects. The slide included 16 LNG
projects worldwide and illustrated two types of risk that
could occur once investment had been made. Delay was the
first risk shown in red in the center of the slide. He
detailed that projects coming online on time or early did
happen, though not frequently. Cost overruns for projects
shown on slide 29 ranged from zero to 120 percent, with an
average of 25 percent (the presentation used a 25 percent
cost overrun example later on).
Mr. Tsafos looked at cash-in/cash-out on slide 30. He
emphasized the importance of the slide that worked to bring
together all components the presentation had addressed thus
far. The slide depicted four scenarios: 1) No TransCanada
and no debt (green); 2) No TransCanada with a 70/30 debt to
equity split (yellow); 3) TransCanada with a buyback option
and a 70/30 debt to equity split (red); and 4) TransCanada
with 100 percent GTP and pipeline ownership and a 70/30
debt to equity split (blue). The slide illustrated how
cash-out and cash-in changed between scenarios in the pre-
FEED stage (would be authorized with legislation); the FEED
stage (detailed study); the construction period; and once
the project went online (this section was shown as an
annual figure). He relayed that the state would be
responsible for $55 million to $100 million if it entered
into the pre-FEED stage. He encouraged members to refrain
from getting too caught up in the estimates. The cost to
the state depended on whether it or TransCanada paid for
the study related to the GTP and pipeline. The state could
choose to abandon the project if the pre-FEED study was not
promising; the state would be responsible for paying
TransCanada what it had fronted plus interest. The state
could also decide to sell down some of its equity at any
time during the process.
3:21:55 PM
Mr. Tsafos continued to address slide 30. Depending on the
state's arrangement with TransCanada, the FEED stage could
cost it between $250 million to $500 million. The state
would need to pay TransCanada anywhere from $150 million to
$400 million if it decided to disband the agreement. He
added that the state could always adjust its equity if it
decided that 25 percent was too much. The state could also
decide to move forward at the FEED study to the FID stage.
The state could potentially spend somewhere between $300
million to $600 million before it decided to move forward
with the project. He reminded the committee that the
figures corresponded to 25 percent of the project; the
partners would spend 75 percent. He pointed to the
construction phase and relayed that the state would be on
the hook for $11.8 billion to $12 billion if it elected to
move forward on the project without TransCanada and with no
debt. The figure may reduce to approximately $5 billion if
the state elected to take on debt. He stressed that once
the construction phase had begun it would be too late to
abandon the project due to the large financial investment.
Once the project came online the state may see revenues
between $2.9 billion to $4 billion. The chart's purpose was
to illustrate the impact of different choices; what the
state was giving up in terms of revenues later on versus
what the state gained upfront for spending less money.
Choosing between the yellow and red option (no TransCanada
versus with TransCanada) may allow the state to spend $1
billion or less in construction, but annually the state may
earn $300 million less.
3:25:25 PM
Mr. Tsafos turned to slide 31 titled "LNG Income Includes
Restricted Revenue." The chart on the left included the
same State of Alaska cash flow information shown on the
right of the previous slide. The middle chart subtracted
the PFD from the numbers and the right chart subtracted the
PFD and property tax for municipalities (the slide included
a hypothetical assumption that 80 percent of the property
taxes went to municipalities). He detailed that the state
may earn $4 billion, but the figure could be reduced to
something like $3.4 billion.
Mr. Tsafos moved to slide 32 titled "Stress Testing SOA's
Cash Calls and Revenues." The slide created a "near perfect
storm" of three things that could go wrong for the state.
First, capital expenditures that were 25 percent higher
(the average cost overrun shown on slide 29). Second, the
potential for an LNG sales price of $7 per mmbtu versus $15
per mmbtu. He noted that the prior year there was almost no
LNG in Asia that went for $7; there were a few bilateral
trades trading at $7 in legacy agreements from 12 or 13
years earlier. He added that Henry Hub gas in the Lower 48
at $3 would be closer to $9 or $10 in Asia. At a price of
$7 most of the proposed LNG projects would be uneconomical;
the price was not very sustainable. Third, the average
utilization was 80 percent rather than 100 percent. He
elaborated that average LNG utilization worldwide was in
the high 80s, which was due to some older projects that had
run out of gas. For example, Kenai had been included in the
calculation when the project had been active. The slide
used the same charts shown on slides 30 and 31, with an
additional chart titled "Stress Case Online (2023+)
Annually." He explained that the base case construction
figures were all 25 percent higher in the stress case
scenario, which meant the state may be on the hook for up
to $15 billion. Under the stress case scenario annual
revenues could be between $480 million to $1.6 billion
instead of $2.9 billion to $4 billion. He stressed that
even in the worst case scenario presented on slide 32, the
state's revenue did not turn negative. The beauty of LNG
projects was that once a project was built, it produced a
steady stream of cash for a long period of time without
needing significant attention.
Mr. Nikos Tsafos turned slide 33 titled "Stress Test:
Restricted vs. Unrestricted Revenues." The first of three
charts reflected State of Alaska total stress case revenues
of $500 million to $1.6 billion. The second and third
charts subtracted the PFD and property tax and indicated
that revenues would turn negative in the most extreme
cases.
3:31:14 PM
Mr. Tsafos addressed slide 34. The slide illustrated cash
flows to the state and included three stress case factors
of price, capital expenditures, and utilization (left to
right respectively). He relayed that other committees had
asked which of the three factors was the most important. He
discussed that hopefully a perfect storm would not occur
and only one of the factors would happen. He reiterated
that the cases included no TransCanada, TransCanada with a
buyback option, or TransCanada with no buyback. The charts
showed that price was the most important factor by far. He
relayed that capital expenditures were much less important
for the overall project economics. He pointed to the table
showing cost overruns (slide 29) and addressed why anyone
would build the projects with all of the overruns. He
relayed that even with cost overruns it was possible to
recoup an investment. He communicated that the importance
of utilization fell in between price and capital
expenditures.
3:32:56 PM
Co-Chair Austerman communicated that the current meeting
was the first time the full committee had taken a look at
the issue from the perspective presented by enalytica. He
anticipated hearing from enalytica again in the future.
Representative Costello referred to the importance of
price. She relayed that the legislature had been told that
Exxon, ConocoPhillips, or BP would help the state market
the gas; however, it was not addressed in the HOA. She
opined that if the clause was not included in the
agreement, the state would be competing against the
companies to sell gas in Asia. She remarked that the state
did not have experience marketing gas to Asia. She wondered
if the issue could be included in the HOA.
Mr. Tsafos replied that it could be done. He detailed that
the oil companies understood that selling the gas the
largest headache for the state. He surmised that if the
state did not receive a good answer to the question, the
project would not move forward. He believed the state
should keep some of its options open. He elaborated that
the HOA specified that the state may decide to have the
three partners sell gas on its behalf, but it could also
locate other partners that were willing to market the
state's LNG. He asked members to think about whether the
headache was large enough to lock down at present or
whether a better deal may come along later in the process.
He pointed out that the state could ask for bids from
various companies beyond the three major partners. It was
possible to define it up front, but was also possible that
the state could drive a harder bargain if it kept the
option open. He thought the state may receive significant
interest beyond the three partners. He opined that if the
HOA locked in the option to the three partners, it may
unnecessarily narrow the competition. He agreed that
competition with the three companies was an issue, but it
was not a significant as one could think. He relayed that a
number of LNG projects had different players marketing gas
individually. He used the Gorgon project as an example
where Shell, Chevron, and ExxonMobil each marketed their
share of the gas; the entities were competing with each
other and had the theoretical potential to bid down the
price. He reiterated that the state may receive a better
deal by opening the field to a broader range of
participants.
3:38:14 PM
Representative Costello wondered what role treble damages
played and if that was the reason the state was only
considering TransCanada. She elaborated that Black and
Veatch had deferred the question to the Department of
Natural Resources; whereas Mr. Mayer had relayed that
lawyers should be addressing the issue.
Mr. Mayer addressed several fundamental questions related
to the MOU including whether the state needed a partner,
whether it was best off going with TransCanada through the
MOU, or whether a broader and more competitive process
would be preferable. He relayed that much was not yet known
about the state's financial capacity to carry the project
on its own. Additionally, he believed there was a
significant amount to consider around future expansions and
whether a third party was desirable and would offset the
additional capital structure costs. He addressed whether
going with TransCanada was the best approach to take if the
state determined it needed a partner. He added that the
true answer would never be known because going down one
path precluded the other. He noted that someone could look
at the MOU and find many sensible terms (e.g. a competitive
cost of capital) and could look at terms of allocation for
risk and reward and the five-year offer to TransCanada to
participate even after termination. He spoke about
negotiating leverage (which probably came through AGIA) and
what it would take to get out of the agreement amicably. He
surmised that people could look at the issues differently
and draw conclusions about how the costs and benefits
stacked up. He believed a further legal analysis would be
necessary to gain a grounded and educated understanding of
the costs and benefits including the potential liability
through AGIA (whether the cost was in the millions or
billions of dollars). He did not know the liability related
to AGIA because it would require rigorous legal analysis.
3:41:54 PM
Representative Costello thought it appeared that the state
had an obligation to address the opportunity costs of
approving an MOU during the current legislative session.
She wondered if it would be valuable for the legislature to
take the time to consider different financing options.
Alternatively, she asked if there was no chance to make
changes until the legislature found out later on that it
would pay damages and perhaps others.
Mr. Mayer replied that if he was a legislator his answer
would depend on his interpretation of the off-ramp
provisions. He referred to a comment he had received from a
legislator that off-ramps appeared to always lead to an on-
ramp. He pointed to the state's numerous rights to
terminate the contract, but if it wanted to proceed with
the project or a similar project, it would need to offer
the right to TransCanada to participate on similar terms
(with the exception of the cost of debt and equity
negotiated based on conditions at the time). He would want
a good understanding of the situation; if the state wanted
to "go it alone" at some point in the future for a better
deal it could communicate its cost of capital and its
openness to offers that were competitive. He would feel
more comfortable locking down the partnership at present if
there was a possibility of exiting the contract in the
future. He added that he would feel increased anxiety about
committing to the agreement at present (before the state's
financing capabilities and other items were known) if he
thought there would be potential for dispute in the future.
3:44:27 PM
Representative Wilson asked what the state should do. She
remarked on gaining understanding about what the state's
relationship had to be with TransCanada and limits that
would be put on the state. Mr. Mayer asked for
clarification on the question. Representative Wilson asked
what the state should do related to the entire project.
Co-Chair Austerman interjected and pointed to the noted
broad nature of the question and the limited meeting time.
He planned to have enalytica address the committee again.
Black and Veatch would also be available if the committee
wished to hear from them again. He relayed that tax
consultant Roger Marks would also present to the committee.
He noted that the committee did not currently have a bill
before it. He asked members to submit questions to his
office; his office would submit them to the consultants. He
relayed that DNR and DOL would also have an opportunity to
weigh in.
Representative Gara followed up on Representative
Costello's question related to selling the state's LNG. He
stressed that the issue was a big concern because the
larger oil companies were experienced at marketing gas. He
was not comforted to hear that the companies knew the issue
was a big concern to the state and that they would deal
with it. He stated that the companies would do what was
best for them. He understood the point that the state may
not want to commit because a better option may come along;
however, he wondered what would be wrong with including the
option for the large three to sell its gas in legislation.
He relayed that the concept was not foreign; currently the
companies were selling the state's oil. He asked the
consultants if they could help with an amendment to
legislation.
3:49:27 PM
Mr. Mayer replied that the HOA contemplated the option. He
believed the question related to how much the state wanted
to lock in at present versus later. Part of the issue
related to how much was known about the project structure
and other possibilities. He referred to joint venture
projects worldwide where the joint venture collectively
marketed LNG and participants each take the proceeds
respectively. Under the joint venture structure the
participants did not compete against one another and the
project marketed the gas. There were other projects that
included a joint venture where LNG sales were competitive
between each company with their own off-take entitlement
and obligation to sell their own share. The HOA outlined
that the parties would negotiate to have the three
producers market the state's gas if a satisfactory
agreement could be arranged. He observed that the issue was
clearly the biggest sensitivity for the state. He believed
the state should only proceed with taking equity and with
gas in-kind if it could satisfactorily resolve the issue.
He reiterated that the HOA did not commit the state, but
stipulated that the state would satisfactorily resolve the
issues if it could. He relayed that it was the start of a
long negotiating process; there were many things that could
be worked in and that would be better understood once the
project was better understood. He noted that the state
could include more restrictive language in the legislation,
but there were also a range of possibilities where it would
be in the state's best interest to remain open.
Mr. Tsafos added that it would be necessary to know the
terms if legislation included an option specifying that
Exxon, BP, and Conoco had to sell the state's gas. He
detailed that unless the state determined what the
companies would charge to sell the gas it would not have
resolved as much of the problem as it may like. He
addressed whether the agreed upon deal was good or not. He
stated that the world of marketing LNG was bizarre and
nontransparent. He pointed to Australia and noted that
price discovery basically consisted of gossip. He stated
that the bottom line was that what the market was and the
price that was accessible became extremely obvious when
marketing gas. He added that it was not very difficult to
assess whether a contract was in line with market norms;
the gas price transaction world was small. However, it was
not possible to predict whether in hindsight a deal would
turn out to be bad; the involvement of oil companies was no
guarantee of a good deal. He relayed that oil companies had
signed long-term LNG deals that they regretted at present.
He communicated that as the state went through the process
it would realize that judging whether it had a good deal
may not be as much of a concern.
3:54:20 PM
Mr. Mayer added that as the state went through the process
it would gain a better understanding about what constituted
a reasonable commercial relationship with companies. He
relayed that it was possible to firm up the sale of the
state's share of gas in current legislation, but it would
be done with much less knowledge about the project, the
market, and a whole range of conditions, which may not be
in the state's interest.
Co-Chair Austerman wanted to come back to the discussion.
Vice-Chair Neuman referred to earlier testimony that the
best way to reduce the state's risk prior to FID related to
the ability to change the financial agreements. He wondered
how the state would implement the advice in the current
gasline legislation (SB 138).
Mr. Mayer answered that the legislation under consideration
by the legislature would establish a tax structure that
would enable a discussion of in-kind versus equity and
would authorize a negotiation process with producers to
establish the details. The legislation also created a
process where legislators would be briefed in executive
sessions on negotiations as they occurred (there would be
an extended period where the administration was in
negotiations with producers and TransCanada). Once the
negotiation process had concluded (in over two years' time)
the terms would come before the legislature for approval.
He surmised that once the terms had come back to the
legislature for approval there would be relatively little
ability to influence the precise details. He noted that it
was crucial what happened in the negotiation process and
how the executive session briefings worked, how frequent
meetings would occur, how much detail legislators would
have access to, and how much ability there would be to make
it clear if the state did not like certain aspects.
Vice-Chair Neuman wondered if the consultants had seen a
financial agreement where the state or sovereign owner of
gas was paid in royalty and in production tax in an in-kind
form.
3:59:15 PM
Mr. Tsafos replied that in the majority of countries with
LNG, the sovereign was a participant with access to and
marketing of the gas. There were a few places in the world
where the sovereign acted purely as a tax and royalty
authority (e.g. the Lower 48 and Australia); however, in
the vast majority of countries with LNG projects the
sovereign participated as an investor and took ownership of
the gas. In some countries the sovereign was very active as
an investor and marketed the gas (e.g. Qatar owned ships
and regasification terminals and was active in marketing
the gas). Other sovereigns were more passive and let
international oil companies market the gas on their behalf.
Mr. Mayer added that there was one aspect that was unusual,
which related to the specifics of turning royalty and tax
into a gas share. He characterized it as a hybrid approach
compared to the more traditional North American tax and
royalty regime. A structure where the state was an investor
and participant was not a typical arrangement; however, its
goal of state participation in the project was common.
Vice-Chair Neuman surmised that the answer was no.
Mr. Tsafos replied that typically the state would own 25
percent of the upstream rather than turning royalty and tax
into a 25 percent share.
Co-Chair Austerman thanked the consultants for their time.
He addressed the paradigm shift in the state from pocketing
tax to moving to a profit base by converting tax into a
sellable product. He believed the public would need to
weigh in with its preference at some point over the next
year and a half. He reiterated his request for committee
members to provide questions to his office.
4:02:33 PM
RECESSED
ADJOURNMENT
4:02:33 PM
The meeting was adjourned at 4:02 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HFIN, enalytica, AKLNG 3-28-14.pdf |
HFIN 3/28/2014 1:30:00 PM |
AKLNG HFIN |