Legislature(2013 - 2014)HOUSE FINANCE 519
03/19/2014 01:30 PM House FINANCE
| Audio | Topic |
|---|---|
| Start | |
| Black and Veatch Presentation: Observations on Heads of Agreement | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
March 19, 2014
1:33 p.m.
1:33:30 PM
CALL TO ORDER
Co-Chair Stoltze called the House Finance Committee meeting
to order at 1:33 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 Lindsey Holmes
Representative Cathy Munoz
Representative Steve Thompson
Representative Tammie Wilson
MEMBERS ABSENT
Representative David Guttenberg
ALSO PRESENT
Deepa Poduval, Principal, Management Consulting Division,
Black and Veatch
PRESENT VIA TELECONFERENCE
Jason De Stigter, Senior Consultant, Management Consulting
Division, Black and Veatch
SUMMARY
^BLACK AND VEATCH PRESENTATION: OBSERVATIONS ON HEADS OF
AGREEMENT
1:34:36 PM
Co-Chair Stoltze discussed the agenda for the day.
DEEPA PODUVAL, PRINCIPAL, MANAGEMENT CONSULTING DIVISION,
BLACK AND VEATCH, discussed her background and focus on the
natural gas markets. She relayed that Black and Veatch had
supported the state in its gas monetization efforts
beginning around 2007. A significant portion of her work
revolved around helping private companies and governments
look at natural gas infrastructure, market trends and
forecasting, and investment strategies.
Co-Chair Stoltze asked Ms. Poduval to clarify who the
consultants were working for. Ms. Poduval replied that the
firm was consulting for the Alaska Department of Natural
Resources (DNR).
Co-Chair Stoltze remarked that the consultants had been
hired by the administration and were also working for all
Alaskans.
JASON DE STIGTER, SENIOR CONSULTANT, MANAGEMENT CONSULTING
DIVISION, BLACK AND VEATCH (via teleconference), discussed
his background in financial modeling and engineering. He
was available to answer questions.
1:38:23 PM
Ms. Poduval provided a PowerPoint presentation titled
"Observations on Heads of Agreement" dated March 19, 2014
(copy on file). She noted that a presentation in members'
packets titled "Alaska North Slope Royalty Study - Selected
Extract" dated March 10, 2014 had been provided as backup
material (copy on file).
Ms. Poduval began on slide 3 titled "Long-Term North Slope
Oil and Gas Revenues are Driven by AKLNG Project Success."
The slide depicted revenue forecasts from North Slope oil
and gas production with and without the AK Liquid Natural
Gas (LNG) project. The blue line showed declining revenue
forecasts for the state using only oil production and
prices. The green line included both oil and gas and showed
increasing revenue forecasts; an additional $4 billion to
$4.5 billion in revenue could result from the LNG project.
She noted that the consultants looked at the economic value
of the AK LNG project from an incremental perspective;
models always included projections for an "oil only world"
with an overlay of what the world would look like for
Alaska with gas production as well. The models looked at
the difference between the two revenue and income streams
as accruing to the AK LNG project. The modeling took into
account that oil and gas production were linked in Alaska
and that producing gas from Prudhoe Bay could have
implications on oil production in the region.
1:41:28 PM
Co-Chair Austerman asked if the $4 billion to $4.5 billion
in potential additional revenues represented a gross or net
revenue stream. Ms. Poduval replied that the figures
represented the annual net revenue stream once the project
was operational. She detailed that the projection looked at
cash flows to the state on an annual basis; the $4 billion
to $4.5 billion was the incremental revenue the state would
receive with the AK LNG project in operation. The
presentation also included the Net Present Value (NPV),
which used all cash flow streams that would accrue later in
the project as well as the upfront investment the state
would make in the project.
Vice-Chair Neuman asked about various assumptions used in
the data including the price of gas. He mentioned the use
of gas in payment for taxes and standard allowable
deductions from the value to the state. Ms. Poduval replied
that forecasts for 30 to 40 years in the future relied on
the best information available and market view at present.
The data shown on slide 3 used an assumption of 2.5 billion
cubic feet (BCF) of LNG sold per day from the project; data
shown did not take the state's equity investment in the
project into account. The LNG market prices generally used
a formula that was linked to global oil prices; therefore,
the projection was based on a conservative to mid-price
level for LNG. The oil price was more conservative than the
one assumed in the Department of Revenue (DOR) revenue
sources book; it used a $90 oil price in current dollars
escalating at approximately 2.5 percent per year. The LNG
price was assumed to be 13.5 percent of the oil price plus
$1.00. The formula for LNG prices was fairly standardized;
it was usually a percentage of the oil price plus an
"adder." Recently the percentage of oil price had hovered
around 14 to 15 percent. The LNG price at the beginning of
the project was approximately $17 assuming a $90 price of
oil.
1:45:18 PM
Representative Gara asked for verification that the data
used an [LNG] price of about $17 mmbtu [Million British
Thermal Units]. Ms. Poduval replied in the affirmative
related to the first year of LNG production. The price
would increase with an increase in oil price.
Representative Gara referred to prior presentations and
explained that the highest price estimate for LNG had been
roughly $17 in the Japanese market. However, there were
prices of $10 to $13 paid in other parts of Asia. He noted
that under contract the state would be responsible for
selling its gas (Exxon, BP, and ConocoPhillips would not
sell the state's gas on its behalf). He wondered why the
model assumed the state would receive the highest gas price
available.
Ms. Poduval responded that the $17/$18 price was based on
the current oil prices and executed LNG contracts. The LNG
price in the model using current prices would be closer to
$12 or $13. The $17 price was a forecast for 10 years into
the future.
Co-Chair Stoltze spoke to over optimistic projections. He
used an example related to pumpkin market prices. He asked
Ms. Poduval if she would bet her own money on the price
projection.
Ms. Poduval replied in the negative. She reiterated that
the estimate was based on the best information available at
present. She believed the firm had taken a somewhat
conservative view on what the prices could be. However, she
recalled the legislative process related to the Alaska
Gasline Inducement Act; there had been rising gas prices in
the Lower 48, but shale gas development had not been
foreseen. She had believed that $11 gas prices would be
sustained; however, she had been proven wrong just as many
other natural gas experts had been. She pointed to the
significant magnitude of the LNG project and its
accompanying projections over the upcoming 40 years. She
did not have a crystal ball.
Ms. Poduval moved to slide 4 titled "Putting the HOA within
the Context of AKLNG Timeline." The slide showed how the
development stages of the project were lined up. One of the
first steps of the process was the pre-Front End
Engineering and Design (pre-FEED), where design began for
the scope of engineering and technical aspects. The pre-
FEED stage typically took 1.5 to 2 years. The AK LNG
project was anticipated to take approximately 1.5 years; if
it began in mid-2014 it was expected to go through the end
of 2015. The next stage was the Front End Engineering and
Design (FEED); it was anticipated to take approximately 3
years for the AK LNG project. She stressed the importance
of the FEED stage, when all of the detailed engineering and
design details were solidified. She elaborated that cost
estimates would be narrowed, technical challenges would be
addressed, and the majority of the commercial agreements
underlying the project would be locked down. She explained
that arrangements between stakeholders and markets were
finalized during the FEED stage. She expounded that LNG
sales and purchase agreements (SPAs) were generally
negotiated and executed towards the end of the FEED stage.
Additionally, financing arrangements were nailed down
during the stage as well. She relayed that the project
entered the Final Investment Decision (FID) stage once it
had been determined that the market price would support the
project cost structure and that banks were willing to
finance the project. During the FID stage each company
involved in a project committed to moving forward (Alaska
and TransCanada in the case of the AK LNG project).
1:51:17 PM
Representative Gara referred to prior testimony that the
state had proposed a production tax rate between 7 and 13
percent. He wondered what production tax rate was assumed
in the graph on slide 3.
Ms. Poduval replied that slide 3 showed a straight forward
SB 21 fiscal structure [SB 21 was oil tax legislation that
passed the legislature in 2013]. The information did not
include equity investment by the state and any changes that
would call for the production tax.
Representative Gara asked for verification that the taxes
shown were indicative of money the state would receive
under the SB 21 tax structure. Ms. Poduval answered that
the slide set the framework for the discussion ahead where
the state's equity investment would be included as well.
Co-Chair Stoltze confirmed that it used the current law.
Ms. Poduval agreed.
Ms. Poduval returned to the project development timeline on
slide 4. Major expenditures began once FID had been
completed. She pointed to the state's required investment
during each of the stages. Depending on the level of equity
taken on by the state and the involvement of TransCanada,
the state's investment would range from $43 million to $100
million in the pre-FEED stage. State commitment during the
FEED stage would be between $180 million and $450 million.
Once the FID stage had concluded and sales agreements and
financing had been locked in, 95 to 97 percent of the
state's total investment would occur (at the end of 2018
and prior to the completion of construction). The state
would be required to make decisions about its total
investment as would the producers. The development plan
phases were very typical of large LNG projects worldwide;
decisions about project viability were made based on
information received in previous stages. She pointed out
that the Heads of Agreement (HOA) laid out principles that
advanced the project to the pre-FEED stage when the state
could begin entering into commercial agreements with
producers and other parties.
1:54:52 PM
Representative Wilson asked about the reason for the $43
million and the $108 million investment range in the pre-
FEED stage. Ms. Poduval replied that the range was
determined by the share the state and partners would take.
Ms. Poduval continued to discuss slide 4. She noted that
the legislature would have many sessions ahead that
involved determining more detail related to a project. She
moved to slide 5 titled "Royalty Study Highlights and
Recommendations." She expressed intent to discuss different
aspects examined by the royalty study and some of the key
findings. The key finding was the recommendation that the
state consider equity participation in the project. The
study team included Black and Veatch, Daniel Johnston and
Co., DNR, DOR, and producers. The study had examined four
primary items. The first was to help the state understand
the global LNG market (i.e. opportunity, opportunity size,
competition). The second item looked at supply chain
elements including potential project expense, common
commercial structures for LNG projects, and the likely
structure of the AK LNG project. The third aspect looked at
the project from a fiscal perspective and used other large
and successful worldwide projects as a benchmark. The
fourth aspect examined project risk and ways for the state
to manage the risks and incentivize the project. The
findings (shown in blue) and recommendations (shown in
green) had led to the ultimate recommendation of state
equity participation. The global LNG market was growing and
was projected to double in size by 2030; it was driven by
market fundamentals where the developing world was becoming
increasingly energy hungry. Developing nations were looking
at natural gas as a source of clean and less expensive
energy. The global market recognized the attractive
opportunity; therefore, there were various LNG projects
competing for the growing demand. She stated that Alaska
competed fairly aggressively against the other projects
looking to capitalize on the opportunity. Some of the
state's advantages included a well-established resource
base (competing projects had uncertainty about access to
adequate LNG that would support a 30-year project life) and
shipping proximity to Asian markets (Asia was a growing
center for LNG demand). One of Alaska's main disadvantages
to the project was the expensive cost structure. Other
projects that were as or more expensive had achieved FID.
The Gorgon project in Australia was headed by Chevron and
had equivalent capacity to the project contemplated in
Alaska; however, at last count the cost estimate was
approximately $53 billion. The project was under
construction and was expected to start production in a
couple of years.
2:00:49 PM
Ms. Poduval communicated that fiscal benchmarking put
Alaska's government take as fairly high; the take included
the state and federal government. Alaska's government take
got close to 70 percent; for LNG projects worldwide the
government take ranged from 40 to 85 percent. The study
recommended that the state work on improving its commercial
attractiveness given the expectation that market demand for
LNG would grow dramatically and recognizing that several
other projects were competing keenly with Alaska. The
second recommendation was to retain value to the state as
much as possible in any incentive the state provided to the
project. The supply chain element assessment recognized
that the AK LNG was anticipated to be a large, complex, and
high cost project. She pointed out that elements comprising
the project would be considered complex individually (i.e.
gas treatment plant (GTP), 700-mile pipeline, and LNG
plant). The good news was that the producers involved in
the project were the best in the world and had the ability
to tackle the magnitude and complexity of the project. The
project structure was likely to be integrated and producer
owned. She explained that with a vertically integrated
structure the same parties would own the upstream, the GTP,
pipeline, and the LNG plant. The structure was typical for
large, complex LNG projects. She relayed that an integrated
structure allowed for maximum project control; therefore,
there was not typically a situation where one component was
ready but another was not. The integrated structure helped
to control costs, locate efficiencies across the
components, and to control the project schedule. She stated
that the structure was rational from the project's
perspective. However, one of the risks the structure
created for the state was the potential for misalignment
between interests of the state and the producers. She used
the Trans-Alaska Pipeline System project as an example.
The state was not likely to have access to significant
information and producers inherently worked to maximize
value to their companies. She detailed that the objective
was not necessarily achieved by allowing other companies to
utilize the infrastructure or to encourage production from
the other companies.
2:05:23 PM
Ms. Poduval highlighted the study's recommendation for the
state to align with producers.
Representative Gara observed that the term "misalignment"
had been used frequently related to gas legislation in the
current session. He asked for detail on the meaning of the
word in the context of the current topic [AK LNG project].
Ms. Poduval discussed various areas of potential
misalignment. For example, producers had no incentive to
expand a project, to create open access, or to enable more
exploration and production activity on the North Slope;
whereas, the state would have a high level of incentive to
enable the items. Additionally, if the LNG plant was
producer-owned, under the current fiscal structure a high
midstream cost would reduce the state's royalty take and
production tax, but from the producer's perspective the
scenario was lucrative. She explained that a producer's
midstream entity would make a significant amount of money,
but its upstream would appear to not make a substantial
amount.
Vice-Chair Neuman was concerned about risk management. He
wondered if Black and Veatch had ever compiled a project
were the project expense structure and the government's
share looked similar to the proposed AK LNG project. He
mentioned that the proposed structure included royalty,
gas, and taxes paid to the state.
Ms. Poduval did not believe she had worked on a project as
outlined by Vice-Chair Neuman. However, there were a number
of projects worldwide where the state would take its share
of the project as a portion of the production. She detailed
that it was fairly common within a production sharing
contract for an IOC and production entity to share the
production coming out of a project. The production was
split into two tiers: the first tier would be called either
"cost oil" or "cost gas" and went to the producer to help
cover its costs associated with the project; the second
tier would be "profit oil" or "profit gas" and was
typically split between the state and producers in some
ratio. Negotiations occurred related to the ratio structure
(i.e. fixed versus varying over time). She provided Yemen
LNG as an example where the state and producers had a share
in the project. Cutter was the world's leading producer of
LNG and had a number of projects that all worked under the
production sharing contract arrangement. She reiterated
that it was not uncommon to see structures similar to the
LNG project contemplated by the state.
Ms. Poduval pointed to the dark blue box on slide 5, which
indicated that the project did not come without risk. There
were a number of significant risks the state needed to
manage and to be cognizant of. The project was currently in
the very early development stage; as more information on
the project emerged and financial decisions needed to be
negotiated, the state had to actively think about risks it
wanted to take on and which risks it wanted to offset with
another party. It was important to recognize that there
would be costs associated with offsetting risk to another
party. She returned to the royalty study recommendation of
state equity participation on slide 5.
2:12:48 PM
Ms. Poduval spoke to fiscal aspects of the project and ways
to reduce risk. One simple way to improve the
attractiveness of the project was to reduce the state's
fiscal take from production tax or royalty. The study had
determined that moving the fiscal needle did not move
project economics enough to make them attractive. She
explained that taking royalty or production tax away
completely would only improve the producers' Internal Rate
of Return (IRR) by 1.5 percent due to the significant
upfront capital outlay required. She stressed that
midstream costs (associated with the GTP and LNG plant)
were such a significant portion of the project's total cost
that without a way to influence or modify them the needle
would not move significantly. The other downside to a
straight fiscal-take reduction was that the state was
essentially transferring value to the producers and not
necessarily getting anything in return. She discussed the
importance of creating value for the state and producers,
which had led to the equity participation recommendation.
The state could be part of the project and helped reduce
the project's cost because some of the upfront cost was
borne by the state. Additionally, the state would receive
value in return for the dollars; it would not be a $2
billion to $4 billion reduction in the state's fiscal take.
The alignment between the state and producers was another
reason that equity participation made sense; participation
by the state would award the state a seat at the table and
would include access to information from producers
throughout the process.
Representative Gara discussed a scenario in which the state
was a 20 percent owner of the project; he wondered why it
would be helpful to have access to the information from
producers if the state could not act on it. Ms. Poduval
answered that it would depend on how the commercial
agreements were structured. It would be valuable to have a
seat at the table related to the expansion principles that
were laid out in the HOA; the principles allowed each of
the parties (even minority interest holders) to initiate an
expansion of the project.
2:17:06 PM
Representative Gara believed expansion was a significant
benefit; however, if the state was a one-fifth owner the
state could vote to expand, but it would be required to pay
the full expansion cost. He questioned when the scenario
would be economically viable for the state. He stated that
under a prior version of the project all parties would have
been required to share in the cost of expansion.
Ms. Poduval replied that it would not necessarily be bad
for the state to pay for the expansion. She elaborated that
the state should expect the cost to be paid by the producer
seeking to use the expansion. She provided a hypothetical
scenario where Anadarko found gas and wanted to enter the
LNG project; if the state facilitated the expansion
Anadarko would pay a tariff through the GTP pipeline and
LNG plant for the state. The state would have its original
investment offset by the tariff payments and should expect
to earn a return on equity as well. She expounded that the
scenario would be similar to the tariff the state would pay
TransCanada if the company had a share in the project. She
summarized that having to make the investment may not be a
bad thing and may be an additional source of revenue for
the state.
2:19:24 PM
Ms. Poduval turned to a pie chart on slide 6 titled
"Criteria Applied for Evaluation of HOA Tie in to Royalty
Study Recommendations." She used the royalty study
recommendations as the valuation criteria as she discussed
the HOA. She highlighted four primary recommendations
including create alignment through equity, improve
commercial attractiveness of the project recognizing its
challenges, preserve value to the state, and manage the
associated risks. She moved to slide 7 that addressed the
first concept of creating alignment through equity
participation. She detailed that the HOA outlined equity
participation for the state. Key tenets of the HOA were
shown on slide 7. The first basic concept was that royalty
as gas and gross tax as gas together would combine and
create the state gas share. The state gas share would be
equivalent to the state's equity share through the project
itself (the GTP pipeline and LNG plant). In turn, the
state's equity share would impact how much the state
invests in a project and how much it would earn. The state
was anticipated to hold equity along the entire supply
chain (through the GTP pipeline and the LNG plant). The
state's financial commitments were anticipated to be made
in a stage-gated manner (current decisions would focus on
funding for the pre-FEED stage only). The structure helped
to create alignment. When Black and Veatch had looked at
state equity participation there had been a number of
different structures it had examined. One equally
attractive alternative from a financial perspective was for
100 percent state ownership of the pipeline; however, one
of the shortcomings was that producers could prevent access
through the GTP or in the LNG plant. The structure on slide
7 created a path through the project for the state's gas
and to facilitate other explorers and developers to move
their gas to market.
2:23:30 PM
Representative Gara pointed to slide 7. He noted that the
state used to receive royalty and production tax payments
in the bank. He mentioned a shift to the state receiving a
20 to 25 percent portion of the gas, which it would sell.
He asked for confirmation that the state gas share and the
state equity share did not need to be the same. He wondered
why the two numbers were identical.
Ms. Poduval replied that each party would have an equal
share of the gas and the project; each party would have the
same share of the project as they had in gas on the slope.
The scenario reflected the general structure for a
vertically integrated project where the upstream and
midstream shares were equalized. Every party would have the
same ownership as it went through the different pieces of
the project. The objective was for the producers and state
to have their share of the gas; each party would pay for
their own infrastructure to move the gas to market. A
difference between shares introduced the possibility that
the state would ship its gas on the producers' capacity and
the question of how terms would be negotiated or vice
versa. It was clearer to have the items be equal.
2:26:59 PM
Representative Costello remarked that the state got
involved in royalty gas arbitration and that the royalty
share was not always the same. She wondered if the project
royalty share would always be 12.5 percent.
Ms. Poduval deferred the question to DNR.
Representative Costello wondered if the state would have
the option to sell its equity share in the future. Ms.
Poduval replied in the affirmative.
Representative Costello addressed the consideration of the
state's complete fiscal situation. She wondered if it would
be possible for the state to sell its equity share in the
project at some point in the future. Ms. Poduval replied in
the affirmative.
Representative Costello asked whether an equity owner had
sold a portion or all of its equity in any other similar
projects. Ms. Poduval replied in the affirmative. She
detailed that it was fairly common during the FEED stage of
LNG projects for the original sponsors to offer a portion
of equity to buyers to create purchasing incentive. She
noted that typically both parties benefitted from the
scenario.
2:28:59 PM
Co-Chair Austerman believed it was necessary to return to
the Memorandum of Understanding (MOU) to define who the
state's partners would be in a state equity share scenario.
He believed that for the state to have an equity share it
would be required to fund itself; therefore, a partner
would be taken on. He wondered if his understanding was
accurate.
Ms. Poduval replied that there were almost two different
decisions facing the state. The first decision was whether
the state wanted to take an equity share in the project.
The second decision was about the best way to optimize the
state's participation. She believed the TransCanada fell
under the second decision; after choosing to explore an
equity participation in the project the state would then
think about offsetting upfront capital cost risk by using a
partner.
Co-Chair Austerman asked for verification that there was
nothing forbidding other partners from having partners to
come up with their share of the funding. Ms. Poduval
agreed.
Ms. Poduval moved to slide 8 titled "Improve Commercial
Attractiveness of AKLNG Project." The slide showed the
producer's return on the project. The state's equity
participation in the project improved the returns for the
producers by 3 to 4 percent over the life of the project.
The increase was largely achieved by reducing the upfront
investment required by producers to facilitate the project.
The state's participation meant that it would have "skin in
the game" to make the project operational. Another
commercially attractive aspect of the structure was that it
could potentially reduce valuation disputes if the state
elected to use royalty-in-kind (RIK). She detailed that
using the RIK method came with risks for the state; the HOA
designated that the state would elect to take RIK if
satisfactory arrangements could be made for the state's
disposition of gas and the producers offered to
individually negotiate with the state to market its portion
of the gas. She would elaborate on the issue later in the
presentation.
2:33:02 PM
Representative Gara recognized that sovereigns had the
ability to tax and to receive the tax revenue. He
understood that Black and Veatch was recommending options
to make the project more economic. He remarked on his
interest in making the project economic as well. He pointed
to Ms. Poduval's testimony that instead of receiving taxes
the state would have a bundle of gas to sell. He observed
that the major oil companies had a long history selling
their oil and gas to customers worldwide; however, Alaska
had zero experience in the area. He wondered if it would be
feasible to require the companies to sell Alaska's share of
the gas in addition to their own share. He wanted to avoid
a situation where oil and gas companies negotiated a $17
contract for themselves, while Alaska only received a $14
contract. He added that the oil and gas companies would not
be incentivized to ensure that Alaska received the better
contract.
2:34:14 PM
Ms. Poduval replied that RIK represented valid risk to the
state. She noted that the royalty study in members' packets
["Alaska North Slope Royalty Study - Selected Extract" by
Black and Veatch (copy on file)] included a number of
slides designated to the risks associated with RIK. She
spoke to the importance of the specific risk highlighted by
Representative Gara. She detailed that the state did not
want to be in the position of competing with some of the
best marketers in the world for a share of the LNG demand
within the same timeframe. One of the advantages with RIV
[royalty-in-value] was that the state benefitted from
[companies'] marketing expertise, which the state would not
have if it was marketing LNG on its own. The marketing
difficulty would not only come from a lack of experience,
but from a lack of relationships with buyers in the Asian
markets. She noted that the companies had lengthy
relationships with some of the Asian buyers; it was a
market that worked based on relationships, which was unlike
the more transparent natural gas market in the Lower 48 and
the crude oil market.
Ms. Poduval relayed that the Heads of Agreement (HOA)
included the intent of the producers to market the
equivalent of their portion of the state's royalty and
production tax on the state's behalf. The associated terms
were yet to be negotiated. She stressed that the specific
risk was one of the key areas the state should focus on.
She added that it was difficult to see how RIK would make
sense if the producers or their equivalent were not
marketing the state's gas.
2:36:10 PM
Representative Wilson asked how much of the state's gas
would be used in-state. Ms. Poduval replied that the study
assumed that instate demand would be approximately 250 mmcf
per day. The state could choose to divert its gas towards
serving in-state demands, but without knowing the future
demand it was difficult to determine the answer. For
example, if Cook Inlet production was sustained at current
levels there may not be as much demand in the Anchorage
market. She detailed that the study took in-state needs
into account; it assumed gas was equivalently portioned
between the state and producers. She asked her colleague to
confirm her statements.
Mr. De Stigter agreed. The share of the 250 mcf per day for
in-state gas between the state and producers was based on
their overall share of the gas.
Ms. Poduval elaborated that the study assumed that the
producers and state could serve the in-state market; market
price was not necessarily discounted relative to what the
state or producers would achieve from selling to a global
LNG market. She added that it was cheaper in-state because
the gas would not incur shipping or LNG plant costs; only
the GTP and pipeline would be required to get the gas to
market.
Representative Wilson did not believe the scenario
increased affordability and surmised that producers would
make more profit off of the state if they did not need to
ship gas out-of-state. She anticipated that if the state
directed a portion of its gas share to in-state use it
would be more economical for rural residents versus a price
charged to go to Asia. Ms. Poduval did not believe
Representative Wilson was making a misstatement. She
expounded that the study did not assume that the gas was
sold at a discount in the local market. The assumption was
that the price was what the producers or state would have
achieved in the global market less the cost to reach its
destination. She detailed that the number did not really
change the project economics for the state due to the small
percentage it made up of the larger project as a whole. She
stated that it was a policy call for DOR or DNR.
Representative Wilson agreed that there was a big
difference between what the state was doing for its share
versus working to ensure affordability for the state's
residents. She remarked that the state could have a partner
in its share that could help the state attain a good deal.
Ms. Poduval replied in the affirmative.
2:40:45 PM
Representative Edgmon surmised that the study did not
include any additional initial infrastructure costs
associated with building off-take points. He believed an
off-take point to the Interior could vary greatly from
another location in terms of size and cost. Ms. Poduval
agreed. She anticipated that the costs would be small
relative to the overall project cost.
Co-Chair Stoltze noted that the committee would hold
questions until the end of the presentation.
Ms. Poduval addressed criteria on slide 9 related to
preserving the value to the state from royalty and taxes.
She addressed whether it was possible for the state to
obtain value in return for its incentives to the project
and to preserve the state's expected revenues from the
project relative to a royalty-in-value (RIV) world. She
shared that slides 10 and 11 laid out a forecast of revenue
for the project with and without equity participation. She
highlighted that the mix between the different sources of
revenue changed depending on whether or not the state had
equity participation in the project. Slide 10 depicted a
RIV scenario with no equity participation. The only
modification to the current fiscal structure was that it
assumed that production tax credits currently applicable to
oil ($5.00 per barrel) would extend to new gas production.
The slide showed forecasted revenues to the state using the
assumption that an Alaska LNG project would succeed with
the one change in the state's fiscal structure. The revenue
was slightly under $4 billion per year; a significant
portion consisted of royalty production tax and property
tax.
Ms. Poduval moved to slide 11, which showed a revenue
forecast with project ownership. The revenue mix shifted,
but the state was projected to make slightly over $4
billion per year. She noted that without the equity
investment the initial investment required by the state was
small; slide 10 showed production tax credits from
investment in the Point Thomson field (shown in negative
numbers in the years before the project became
operational). She addressed the total cash flow over the
timeframe included on slides 10 (2012 to 2041). Total
projected cash flow (including expenditures and revenue)
was approximately $68 billion through 2041. Total projected
cash flow in a state equity participation scenario was
approximately $72 billion. She explained that the state did
not necessarily loose value by taking equity participation;
there was a larger upfront investment, but it was recouped
through revenues coming in during the project's operating
years.
2:46:13 PM
Ms. Poduval turned to slide 12 titled "Preserve Value to
State from Royalty and Taxes." She stated that it was
challenging to identify precisely what the state would make
in a "do-nothing" scenario, given that the sum would change
based on market conditions. She noted that prices and the
project's capital costs were significant drivers. She
explained that prices that were different than the
forecasted numbers shown on slide 12 would completely
change the state's revenue forecast. She remarked that the
equity participation benchmark was a moving target as well.
The graph addressed 9 different combinations of two of the
largest risk factors to the project's economics including
market prices and project capital cost to determine how
much equity the state should own to be able to achieve the
same level of revenues it would have achieved in a do-
nothing scenario. The analysis had led to the study's
recommendation of the state's equity percentage (between 20
and 25 percent). In a low price environment the state
needed a relatively small equity share to make revenues it
would have earned without the equity investment. As prices
increased the benchmark increased because the state would
have made more money as prices rose in a do-nothing
scenario. The chart indicated that the state's equity
participation should be somewhere between 20 and 30 percent
to preserve the state's value. She reiterated that the data
assumed that the project would be successful in a do-
nothing scenario. She remarked that somewhere between 20
and 30 percent was where the state started preserving the
value it would have earned.
2:49:35 PM
Ms. Poduval communicated that if prices were lower, the
state would end up earning more with equity participation.
Everyone would make money when gas prices were higher, but
the state would not make as much as it would have made
without equity participation. She moved to slide 13 titled
"Gross Tax Rate Sets the Total State Gas Share and Equity
Participation." The slide highlighted that the variable in
the mix was the gross tax rate or the "tax gas." With a
royalty of 13 percent the tax gas share was somewhere
between 8 and 14 percent to get to a total state gas share
between 20 and 25 percent. She communicated that setting
the tax gas share essentially set the state's equity
participation, the state's investment, and the state's
revenues.
Ms. Poduval addressed management of risks the state would
take on associated with the project (slide 14). Slide 14
looked at the same 9 scenarios of varying costs of
investment and price. The blue bars represented the state's
revenues in a do-nothing, modified status quo scenario. The
green bars showed projected state revenues with equity
participation. The slide assumed a 25 percent state equity
participation. At a 25 percent equity participation in a
low price scenario the state made significantly more
revenues than it would have without equity participation.
She relayed that in some ways it helped to hedge the risk
of prices being low. The base price scenario showed
revenues that were relatively close together with and
without equity participation; depending on capital costs
revenues could be slightly over or under status quo
revenues, but the state was kept whole with or without the
25 percent equity investment. In a high price scenario the
state would make less with the 25 percent equity investment
than it would have without it. The chart showed that the
state had essentially flattened its revenue profile and
exposure to prices with the equity participation; it would
make more in a low price world, less in a high price world,
and about the same in a base price world. Some of the
downside coming from low prices was taken away, but some of
the upside was also taken away from high prices.
2:53:44 PM
Ms. Poduval shared that the second significant risk to the
project resulted from capital costs. Slide 15 addressed
whether the state had found a way to manage its risk
exposure to capital costs flowing out. The highest risk to
the project was in the initial years before cash flows
began coming in when the state had "cash calls" on
investment (especially during the construction period). She
discussed the importance of acting to manage and reduce the
state's risk. TransCanada's participation in the project
allowed the state to retain 20 to 25 percent of the gas
share, while being responsible for approximately 13 to 18
percent of upfront costs. She advised that the goal should
be to maximize the state's share of the gas (due to
revenues it would bring in) while minimizing the upfront
costs. An upfront investment was made in order to achieve
revenues. The issue was especially important if cost
overruns occurred on the project. She advised the committee
to expect that project overruns would occur due to its size
and complexity. She referred to other projects of the same
magnitude that had experienced cost overruns resulting from
equipment and skilled labor. She pointed to Australia as an
example where large LNG projects had struggled to stay
within budget due to inflationary pressures. Producers
would try to manage costs closely, but costs were more
likely to increase rather than decrease.
2:56:26 PM
Ms. Poduval turned to a chart on slide 16 related to the
reduction of capital cost exposure resulting from
TransCanada participation. The blue lines represented the
state's investment in current dollars from a 20 percent to
a 25 percent equity share. The red lines showed the state's
required upfront investment with TransCanada participation.
She relayed that TransCanada's participation reduced the
state's upfront investment by about $3 billion under the
$45 billion cost estimate scenario and by $4 billion under
a cost overrun scenario of $54 billion. The strategy was
one of the ways the state could manage the upfront risk; it
did not mean the state would not have risk associated with
the remainder of its investment.
Ms. Poduval addressed the risk of potential loss of value
associated with RIK. She detailed that the state would be
in competition with skilled producers with a history of
marketing LNG globally. The HOA included the intent of
producers to offer to negotiate separately to market the
state's share of gas (to avoid triggering antitrust
provisions); the share of the gas would be proportional to
each producer's share of producer capacity. She advised
remaining aware of the issue as the details continued to be
negotiated. Under the arrangement the state would benefit
from the producers' marketing expertise rather than
competing with it; it could recreate some of the same
benefits that would be achieved by RIV.
2:59:34 PM
Ms. Poduval relayed that the fourth aspect of managing risk
was related to the structure on equity participation (slide
18). The royalty study highlighted various aspects of the
arrangement and agreement structure between the state,
producers, and TransCanada in a way that would allow the
state to achieve its objectives. She pointed to four HOA
elements beginning with "project within a project," which
specified that the major stakeholders could operate their
projects somewhat independently from a regulatory
perspective. The structure also allowed expansion to be
initiated by any one of the parties without agreement by
all parties (the provision was subject to some constraints
and should not negatively impact the project operation,
which was fairly standard). Stage-gated commitments were
another effective way of managing the state's risk because
the state would not make an upfront commitment covering the
entire project development process. The state's first
commitment would be to get through the pre-FEED stage; it
would enter into additional binding agreements when it
entered the FEED stage. She reiterated that the strategy
was a fairly standard way of developing LNG projects;
commitments by the state that were proportionate to the
project's current status were beneficial.
Ms. Poduval continued to address slide 18. The final HOA
element shown on the slide was "access to information." She
detailed that a seat at the table should allow the state to
have access to information such as what producers were
contemplating with respect to the project development, what
contracts were under negotiation for technical aspects, and
commercial agreements between producers. All of the HOA
aspects would be fine-tuned and solidified in the
commercial agreements that would happen at a later date.
She advised that the state had to be vigilant to include
terms in the commercial agreements that will help it to
achieve its objectives including open access, expansion, a
seat at the table, and access to information.
3:03:07 PM
Ms. Poduval moved to slide 19 titled "HOA Score Card
Relative to Criteria." She believed the HOA reflected terms
and a structure that would allow the state to achieve the
royalty study recommendations of alignment through equity,
improve commercial attractiveness, and preserve value to
the state. The equity participation along the entire supply
chain and a structure that enabled the state to be a
vertically integrated participant helped in the creation of
alignment. By investing state equity upfront it
simultaneously increased producer returns and preserved the
state's value relative to a status quo scenario. One risk
to the state associated with vertical integration was that
the state would not control the upstream; the risk would
need to managed and come through commercial offtake
agreements with producers. She detailed that the state
would receive a share of the gas, but it would be in the
producers' control to determine the amount of production.
She addressed the management of risks including price
exposure, capital costs, RIK marketing, and structure of
participation. She reiterated earlier testimony that equity
participation dampened the state's exposure to prices; it
improved state revenues in a low price environment and gave
up some of the upside in a high price environment. She
added that equity participation would help the state manage
the risk of lower than expected prices. She discussed that
TransCanada's participation would lower the state's initial
cash calls; it helped the state achieve a higher percentage
of gas without spending an equivalent portion of the
capital up front. She addressed RIK marketing risk and
believed the HOA reflected producer intent to market the
state's share of gas; the arrangement details had not been
finalized. She elaborated that the structure of the state's
participation would be in the details of commercial
agreements; ensuring the state had access to information,
could enable open access and expansion of the project, and
allow other explorers and developers capitalize on the
project. She stressed that the areas were important for the
state to maintain vigilance on during negotiations.
3:06:49 PM
Representative Munoz wondered what would happen to the
state's equity share if TransCanada was not involved. She
wondered whether the state's ultimate equity share would be
impacted if it invested more money up front.
Ms. Poduval replied that TransCanada's absence would not
necessarily impact the state's equity share. She elaborated
that the state taking equity participation and the
optimization of the equity position were two separate
decisions. The level of equity participation was negotiated
between the state and producers; the participation was
driven in part by the amount of gas the state would need to
be kept whole relative to revenues in a status quo world.
The HOA put the necessary state share between 20 and 25
percent. The decision to include TransCanada would not
change the state's gas share, but it would affect how much
the state spent upfront to achieve the gas share. Their
analysis showed that in the case of a 25 percent equity
participation, the state could achieve between $400 million
to $500 million additional revenues per year with
TransCanada involved; it could also invest between $2
billion to $4 billion less with TransCanada's involvement
than it would by going alone and taking a 20 percent equity
share. The state needed to take the tradeoff into account
and to determine whether there was a way to maximize equity
and reduce risk associated with initial capital costs.
Co-Chair Austerman assumed that the state could move
forward on its own if it chose to put the money upfront
through bonds, debt, or other. The objective of TransCanada
was to reduce the upfront cost and some of the risk to the
state in the beginning of the project.
Ms. Poduval agreed that the state could move forward
without a partner. She elaborated that the issue pertained
to what the state wanted to spend its money on and how much
it could borrow.
Co-Chair Austerman discussed a scenario where the state had
TransCanada as a partner. He referred to a buyout provision
in the MOU that would enable the state to buy back a
portion of the investment percentage. He assumed the
buyback would not take place until revenues were coming in
from the project.
Ms. Poduval replied that the current structure would give
the state the option to buy back between 30 and 40 percent
in the TransCanada entity holding the state's interest. The
decision would be made at the end of the pre-FEED stage; it
would not be after revenues began coming in.
3:11:13 PM
Vice-Chair Neuman wondered how to amortize the state's
investment. He pointed to the assumption of $17 per mmbtu
to Asia and the deduction of costs including
transportation, liquefaction, the pipeline cost of 12
percent charged by TransCanada, the gas treatment facility,
and transmission back to the point of production. He spoke
about taking gas in value and taxes. He believed the
assumptions were gross and not net.
Ms. Poduval answered that the study accounted for the
adjustments in the analysis. The other sources of revenue
for the state that made up the $4 billion in annual revenue
came from property taxes, the return the state would earn
from ownership in the project, and the state corporate
income tax.
Vice-Chair Neuman asked for a copy of the costs. He spoke
to the assumption under SB 21 of the $5 per barrel credit.
He spoke about oil at $100 per barrel in addition to the $5
per barrel equivalent and the calculation used to determine
the cost of gas. He mentioned a 35 percent tax and the
value provided to the state.
Ms. Poduval asked for clarification on the question.
Vice-Chair Neuman was trying to determine how the 14
percent number and the value had been reached. He discussed
that the state would invest close to $100 million in the
project 10 years before it would receive a return. The
investment would be up to $14 billion; he spoke about the
estimation of the time value of money. He requested
additional figures to help clarify value to the state.
3:15:34 PM
Co-Chair Stoltze wondered why it was necessary to discuss
anything but the numbers under the current tax regime. Ms.
Poduval replied that given the cost structure of the
project and the current fiscal structure, the project would
have a difficult time competing in the market; something
would have to change to make it commercially attractive.
She relayed that a fiscal reduction or a structural change
would be the most obvious options for the state to
consider.
Co-Chair Austerman asked whether the price of gas was
attached to the price of oil in the assumptions used by the
study and DNR. Ms. Poduval replied in the affirmative.
Co-Chair Austerman had read about angst associated with
what the long-term contracts had been in the Southeast
Asian market. He believed efforts were underway to change
the dynamic to a gas price based on gas price.
Ms. Poduval agreed that the statement was fair. She
detailed that the effort was mostly driven by Japanese
buyers who were the largest purchasers of LNG and made up
the premium and highest price market for LNG. The Japanese
market was trying to capitalize on a number of low cost LNG
brownfield projects in the Lower 48 that were being
converted from regasification facilities to liquefaction
facilities. The projects had all been built when Alaska was
contemplating the Alaska Gasline Inducement Act (AGIA).
The expectation had been that Lower 48 gas prices would be
extremely high, that there would not be sufficient gas to
meet the country's own needs, and that it would be
necessary to import gas. She elaborated that a number of
regasification projects converted back into gas. With the
emergence of shale gas and a surplus of gas in the Lower 48
all of the projects were being converted with a
liquefaction facility; the cheap shale gas was converted
into LNG and use to serve markets such as Asia. The
projects all had low cost structures because they had no
upstream costs and used many of the same facilities that
had originally been built for regasification. The
liquefaction plants had to be constructed, but the
pipelines and storage tanks were already there. She
detailed that there were a finite number of projects with a
low enough cost structure that allowed them to offer a gas-
linked LNG price to the Asian markets. The Japanese buyers
were aggressively negotiating with the projects to include
the gas in their portfolio. However, the majority of LNG
projects did not have that low cost structure; the typical
cost structure was expensive enough to require an oil-based
price to make the projects profitable.
3:20:06 PM
Co-Chair Austerman noted that in the rest of the world,
market was not based on oil price, but on the cost of
moving gas. Ms. Poduval answered that the projects would
need an oil-linked type price level to support their high
cost structure, just like Alaska.
Representative Munoz remarked that all parties would assume
risk associated with the project. She asked why the state
would take the responsibility for TransCanada's investment
and risk if the project failed. Ms. Poduval replied that
TransCanada would essentially pay what the state would have
otherwise paid in the project's development stages. She
detailed that the off ramps represented that the state
would pay TransCanada what it would have paid anyway
without TransCanada in the mix.
Representative Munoz asked whether the costs were limited
to costs the state would have paid without TransCanada's
involvement or if they included the full costs put forward
by TransCanada. Ms. Poduval replied that the costs were
equivalent. TransCanada would pay what the state would have
paid for the portion of the project. Additional costs that
would accrue to the state if it exercised the off ramps
would be carrying costs associated with TransCanada's
money. Carrying costs would be slightly over 7 percent
annually for TransCanada's investment. She advised the
committee to think about what the opportunity cost to the
state would have been if it had made the investments; what
the state would have foregone and whether it would be more
or less than the 7 percent.
Co-Chair Austerman wondered whether risk involved in a
state and TransCanada partnership was neutral. He wondered
if the state would have the same risk if TransCanada fell
to the wayside. Ms. Poduval deferred the question to the
administration or the Department of Law.
Co-Chair Stoltze referred to a vote on the TransCanada
contract from the past. He recalled that he and Vice-Chair
Neuman had voted against the contract. He referred to
concerns that there had been a "handcuffing" to the
partner.
3:23:59 PM
Representative Gara recalled that when analyzing oil and
gas deals in the past the legislature had received a
comparison of the state's government take versus those in
other countries. He discussed the governor's proposal that
included a royalty plus a production tax rate of 7 to 13
percent. He asked if Ms. Poduval could provide a government
take comparison between Alaska and other countries with a
substantial natural gas business. He wanted to know where
the state would be on the royalty with a 7 percent or 13
percent tax rate. He did not want to hamstring the governor
by capping the number. Ms. Poduval replied that she would
provide the data.
Representative Gara discussed his understanding of the
state's relationship with TransCanada. He spoke to a
reduction in costs to the state and wondered if TransCanada
would be a proportionate owner. He asked if it was that
simple. He asked which of the three facilities TransCanada
would own and contribute to. Additionally, he wondered what
the state would get and what TransCanada was obligated to.
Ms. Poduval replied that as currently contemplated
TransCanada would hold shares in the GTP and pipeline only;
in all scenarios the state would hold the share of the LNG
plant. In a scenario where the state had an equity share of
25 percent, TransCanada would hold 25 percent of the GTP
and pipeline and the state would hold 25 percent of the LNG
plant. There was an option for the state to buy back up to
40 percent of TransCanada's holding company for the two
components. She elaborated that 40 percent of the 25
percent held by TransCanada would amount to 10 percent; if
the state exercised its buyback option, the state would
have 10 percent of the GTP, 10 percent of the pipeline, and
25 percent of the LNG plant. TransCanada would be left with
15 percent of the GTP and pipeline.
3:28:00 PM
Representative Gara spoke to the idea that a pipeline was
lucrative (as long as it contained gas). He discussed 10 to
14 percent rates of return and the guarantee of gas; he
remarked that the state would give up 60 percent of that
amount. He wondered about the value of the portion
TransCanada would not buy into. Ms. Poduval replied that
the items would be equally valuable; there was nothing that
would distinguish the pipeline from the GTP or LNG plant.
She discussed return that the pipeline would earn. She
explained that a similar commercial term would be
applicable to the GTP as well as the LNG plant; the same
return on equity could be obtained on any of the
components. The state could have a long-term service
agreement through any of the components that included a
return on equity that could be identical for all three
components (e.g. a 12 percent return on equity).
Representative Gara asked for verification that
TransCanada's share meant that it would pay its
proportionate cost to achieve its share. Ms. Poduval
replied in the affirmative.
Co-Chair Austerman thanked Ms. Poduval for her
presentation.
Co-Chair Stoltze discussed the schedule for the following
day.
ADJOURNMENT
3:31:18 PM
The meeting was adjourned at 3:31 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| B&V Royalty Study Summary Reference 3.19.14.pdf |
HFIN 3/19/2014 1:30:00 PM |
HOU HFIN DNR B&V |
| B&V Presentation HFIN HOA 3.19.14.pdf |
HFIN 3/19/2014 1:30:00 PM |
AK LNG HFIN |