Legislature(2013 - 2014)Anch Temporary LIO
12/09/2013 10:00 AM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| Alaska North Slope Royalty Study - Study Highlights | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
December 9, 2013
10:05 a.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Dan Saddler, Co-Chair
Representative Mike Hawker
Representative Craig Johnson
Representative Paul Seaton
Representative Geran Tarr
Representative Chris Tuck
MEMBERS ABSENT
Representative Peggy Wilson, Vice Chair
Representative Kurt Olson
OTHER LEGISLATORS PRESENT
Representative Lindsey Holmes
COMMITTEE CALENDAR
ALASKA NORTH SLOPE ROYALTY STUDY - STUDY HIGHLIGHTS
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
DEEPA PODUVAL, Principal Consultant
Management Consulting Division
Black & Veatch
Overland, Kansas
POSITION STATEMENT: Presented a continuation of a PowerPoint
presentation on the Alaska North Slope Royalty Study dated
November 2013.
JOE BALASH, Acting Commissioner
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Answered questions during the continuation
of the PowerPoint presentation on the Alaska North Slope Royalty
Study dated November 2013.
REPRESENTATIVE LINDSEY HOLMES
Alaska State Legislature
Juneau, Alaska
POSITION STATEMENT: Asked questions during the PowerPoint
presentation on the Alaska North Slope Royalty Study dated
November 2013.
ACTION NARRATIVE
10:05:31 AM
CO-CHAIR ERIC FEIGE called the House Resources Standing
Committee meeting to order at 10:05 a.m. Representatives
Saddler, Tarr, Tuck (via teleconference), Hawker (via
teleconference), Johnson, Seaton, and Feige were present at the
call to order. Representative Holmes was also in attendance.
^Alaska North Slope Royalty Study - Study Highlights
Alaska North Slope Royalty Study - Study Highlights
10:06:00 AM
REPRESENTATIVE FEIGE announced that the only order of business
would be a continuation of the PowerPoint presentation by Black
& Veatch on Alaska North Slope Royalty Study - Study Highlights.
10:07:06 AM
DEEPA PODUVAL, Principal Consultant; Management Consulting
Division, Black & Veatch, introduced herself. She continued
Black & Veatch's PowerPoint presentation entitled, "Alaska North
Slope Royalty Study - Study Highlights" dated November 2013.
She referred to slide 37 entitled, "Fiscal Framework- Scope,"
which essentially shows the scope of the fiscal framework.
First, an overview of fiscal structures will help the committee
to understand fiscal structures relevant to other LNG projects
worldwide and to compare them with the proposed Alaska liquefied
natural gas project (AKLNG). Second, the study highlights and
analyzes incentives that the state could offer to help
facilitate the AKLNG project. Finally, Black & Veatch considers
the specific question related to royalty ownership position with
the options of royalty-in-kind (RIK) relative to royalty-in-
value (RIV), including implications to the state for these
options. Three main systems are in use in the oil and gas
industry around the world [slide 38]. First, the concessionary
system is similar to the one used in Alaska for oil and gas -
which is essentially a tax and royalty based system. Under the
concessionary system the host government receives royalties and
taxes, generally as a percentage of profit.
MS. PODUVAL indicated the second system is the production
sharing contract system, in which production "in kind" is shared
between the contractor and the government. The components of
the production sharing contract generally include royalty, cost
oil, profit oil, and any potential taxes.
MS. PODUVAL highlighted the third system, the contractual
service contract, which she described as when the contractor -
an independent oil company, is reimbursed and paid a fee,
typically in cash, for the services of exploring, developing,
and marketing. Of the three systems, concessionary systems
generally represent more prevalent and stable environments. In
fact, concessionary systems are used in countries, including the
United Kingdom (UK), the U.S., Norway, Australia, Russia, and
Canada - typically first-world countries. Whereas, contractual
systems are more dominant in locations with political or other
perceived risks so oil companies are generally more comfortable
with the terms locked down within the confines of a contract.
10:11:04 AM
MS. PODUVAL turned attention to slide 39 entitled, "Government
Take on LNG Projects, by Country." She stated the light blue
area indicates the government participation in commercially
operating projects or those with final investment decisions
taken. Typically, government take for LNG projects falls in a
fairly large range, from 45-85 percent. The actual government
take considers project specifics, the jurisdiction, and
individual risks such as risk profile, cost structure, and
anticipated profitability. For example, Equatorial Guinea, a
country with significant political uncertainty and substantial
risk, offered low fiscal terms in order to attract investors.
She turned to slide 40 entitled, "Government Take in Alaska is
between 70%-80% under SB 21/MAPA Fiscal Structure with
Significant Federal Government Share." She explained that slide
40 breaks out the government take in Alaska for the proposed
AKLNG project. She directed attention to the pie chart on the
left that shows the share of cash flow over a 30-year timeframe
by stakeholders. On the right, the pie chart shows the
discounted cash flows or the net present value (NPV), again,
over the same 30-year timeframe. She identified the projected
government share between 72-80 percent, which includes a
significant federal government share of close to 20 percent.
She described this as being one of the boundary conditions for
the LNG project since the state does not have much influence to
use that as a lever to improve economics.
10:13:04 AM
REPRESENTATIVE SEATON asked whether the calculations were based
on SB 21 [More Alaskan Production Tax (MAPA)] structure rate for
oil.
MS. PODUVAL answered that the rate assumed the SB 21/MAPA
structure - as it is today - without any modifications. Ms.
Poduval, in further response to Representative Seaton, responded
that Black & Veatch projected the state's rate under current law
for in state utilized gas; however, under the base assumptions
the government take is similar for Alaska's Clear and Equitable
Share (ACES), as well. She offered to provide more information
on this in the near future. In summary, Black & Veatch
envisioned the total project would include an in-state demand of
250-300 million cubic feet (mcf) per day, and further assumed
the gas will be subject to the $.17/mcf Cook Inlet production
tax rate, with an export of 17.4 million tons per annum.
10:15:25 AM
REPRESENTATIVE SEATON related his understanding that the project
includes consideration of all of the gas consumed in the state
as if it was produced on the North Slope.
MS. PODUVAL agreed that is correct.
10:15:46 AM
JOE BALASH, Acting Commissioner, Department of Natural Resources
(DNR), added that the study "ran numbers" for the tax rate on
all gas, including down to zero.
MS. PODUVAL turned to slide 41 entitled, "Fiscal & Non-Fiscal
Levers are Available to Influence AKLNG Project." Numerous
levers are available to provide incentives to the proposed AKLNG
project, including fiscal levers such as a reduction of royalty
or taxes. Other levers include non-fiscal options such as
stabilizing provisions often called fiscal certainty or
jurisdiction for arbitration and dispute resolution. These
levers are also important to oil companies, as well as the
ability to book reserves for the gas as part of the project.
She emphasized the ultimate goal as being to lower or defer the
government take. Equally important, another goal is to reduce
cost exposure for independent oil companies to reduce their risk
profiles. Of course, there are different ways to incentivize
the proposed AKLNG project to make it more attractive. It's
easier to measure the effect of fiscal levers such as internal
rates of return or NPV, but often non-fiscal levers tend to be
more subjective, she said.
10:17:57 AM
MS. PODUVAL directed attention to slide 42 entitled,
"Eliminating Royalty, Production Tax, or Property Tax Brings
Government Take for AKLNG Project down to 65-70%." As
Commissioner Balash previously mentioned, the study considered
the extent of incentives the state could provide to the AKLNG
project by cranking the three fiscal levers - royalty,
production tax, and property tax - to demonstrate how each of
the variables would affect the AKLNG project. She explained
that this slide demonstrates the share of cash flow when each of
the fiscal elements changes. For example, she said, the model
compares the effects of production tax essentially cut in half
and then completely eliminated. Next, the slide treats royalty
based on half royalty and no royalty. Finally, the production
tax rate was cut from 35 percent, to 15 percent, and then
completely eliminated. Similarly, Black & Veatch considered
scenarios for property tax from 2 percent in the base case, to 1
percent, then finally eliminating it. She concluded that
eliminating royalty, production, and property taxes can reduce
the government take to 65-70 percent. By applying fiscal
incentives the internal rate of return (IRR) for producers would
be reduced by 1 to 1.5 percent. In response to a question, she
responded that the circles on the right side of the chart
represent the producers' IRR.
10:19:48 AM
REPRESENTATIVE HAWKER asked if these figures highlight the IRR
based on Black & Veatch estimates or actual economics.
MS. PODUVAL responded that the estimates are based on the
assumptions on costs that would drive the AKLNG project. Of
course, a number of scenarios could change since significant
uncertainty surrounds the AKLNG project - given how early it is
in the project - plus cost profiles. She then turned attention
to slide 43, entitled, "Impact of Fiscal Levers Under Different
Price and Capex Market Conditions - NPV 10 ($2013 Billions),"
which examines the two biggest fiscal drivers - capital cost and
price - to determine their level of impact on the AKLNG project.
10:21:02 AM
MS. PODUVAL turned attention to slide 43 entitled, "Impact of
Fiscal Levers under Different Price and Capex Market Conditions
- NPV ($2013 Billions)." This slide extends the analysis to
consider price sensitivity and capital costs. Specifically,
price uncertainty contemplates lower prices tied to Henry Hub
(HH). In light of significant changes in the LNG market,
considerable discussion has been ongoing on whether oil-linked
prices will be sustainable given the LNG availability in the
Lower 48. Consequently, some pressure exists to move towards
gas-linked prices. Therefore, Black & Veatch contemplated a low
LNG price world in which HH is $4 and adds $6 for liquefaction
and shipping the LNG. Additionally, this slide also considered
the high price environmental cost compared to the baseline at a
$90 real flat price. Therefore, it used $120 and a more
aggressive multiplier to arrive at an LNG price. This slide
helps illustrate how sensitive the AKLNG project can be, as well
as the effect of the state contribution by moving the fiscal
levers.
MS. PODUVAL directed attention to the chart at the right
entitled "Midstream Capex Sensitivity." This used a 20 percent
up and down range for capital cost, which ties into the capital
cost range the producers have shared in their public
announcements. She concluded that the market prices by far
dominate the AKLNG project's economics and dwarf all other
variables. Royalty, property tax, and production tax reductions
are all very beneficial in improving the producer NPV and IRRs,
as well as reducing the state's take. Above all, one thing that
jumps out is the overall government take is dampened due to the
35 percent federal government income tax. She explained the
result is that 35 percent of the value of the state's transfer
to producers flows to the federal government through federal
income tax. This leads to exploring ways the state can add
value and minimize leakage to the federal government.
10:23:46 AM
MS. PODUVAL referred to slide 44 entitled, "Royalty Alternatives
In Kind or In Value." One important option related to Alaska's
royalty rights is the choice of its royalty share: royalty in
kind (RIK) or royalty in value (RIV). Each method has
advantages and disadvantages, depending on the state or
producer's perspective. Comparisons to RIK and RIV are outlined
in slide 45 entitled, "Royalty In Kind Versus Royalty in Value."
In particular, RIK is attractive to producers since it reduces
valuation disputes and removes the responsibility of treating,
transporting, liquefying, and marketing the state's share of
royalty gas. Moreover, RIK can reduce commercial uncertainty
for the AKLNG since it would be considered attractive to the
producers. One advantage from the state's perspective - by
being a participant - is that RIK can provide the state with
better market insight.
MS. PODUVAL listed some disadvantages, including that RIK
exposes the state's to various additional risks and could
require modifications to current legislation and authority.
Further, RIK would also require the state to have international
marketing expertise - which the state currently lacks. Further,
RIK would require the state to add credit requirements for
shipper agreements.
MS. PODUVAL pointed out the royalty in-value option (RIV), on
the bottom half of slide 45, noting one of the biggest
advantages in that RIV represents the status quo. Certainly,
the state has familiarly, as well as established auditing and
management capabilities. Further, the state would not have any
direct firm capacity commitments. Some disadvantages of RIV
include a lack of transparency since the state may not have
access to confidential information on the project. Again, third
party access would be a challenge, and valuation disputes could
occur since a "higher of provision" option and actual market
price realized are areas that historically have created disputes
between the state and producers. Of course, the state could
also be subject to gaming over cost deductions given that the
producers have the fiduciary responsibilities to maximize value
to their shareholders and those interests don't always line up
the state's best interest. Finally, RIV would not be the
preferred choice of producers, she stated.
10:26:51 AM
MS. PODUVAL turned to slide 46 entitled, "RIK Risk Profile is
Influenced by the Location of Title Transfer from the State to
Buyer."
10:27:06 AM
REPRESENTATIVE SEATON recalled it's often proposed that the
state's participation in a pipeline would align its interest
with those of the producers. He asked whether either RIK or RIV
puts the state in alignment or out of alignment.
MS. PODUVAL answered that either could work in terms of
alignment with the producers, but it would depend on the details
of the royalty structure. She offered her belief that equity
participation is almost a separate question since it means a
seat at the table and an alignment with producers. Anyway,
solutions to the disadvantages to each valuation option also
exist so RIK and RIV could both work in terms of alignment with
producers; however, it is a matter of identifying the trouble
spots. For example, with RIV the focus would be on valuation
disputes whereas with RIK one of the biggest issues would be the
state's lack of expertise to market the LNG. Certainly, these
problems can be solved to achieve alignment, she said. She
emphasized Black & Veatch's opinion is that in terms of
alignment using one royalty valuation would not necessarily have
advantage over the other; however, RIK does represent
significant risks to the state.
10:29:16 AM
REPRESENTATIVE SEATON asked for further clarification on
alignment in instances in which producers own the product, but
one party is not a partner. He asked how alignment could be
achieved under those circumstances using RIK given the interests
of the two parties.
ACTING COMMISSIONER BALASH responded this question introduces
capacity as part of the equation. In fact, equity and capacity
in the infrastructure is different than the specific and narrow
comparison between RIK and RIV. He acknowledged that how
equity, capacity, and production line up will be the key to
alignment. In terms of production, the question becomes whether
royalty will be RIK or RIV. Still, [capacity] is another
dimension to consider prior to considering expansion scenarios
and third party access. The specific focus, as it relates to
the proven resource at Prudhoe Bay and Point Thomson, will be
how to evaluate RIK versus RIV. He recalled Ms. Poduval
previously mentioned that RIK is sometimes used as shorthand for
equity participation; however, while the two have been linked
historically during policy discussions, they represent different
choices and different decision points. He hoped the committee
can take away that distinction. Certainly, with some aspects it
would make more sense with state participation to use RIK, but
in other regards it does not. The distinction between the RIK
and RIV decision does not represent whether the state should
participate, but instead, it is the recognition that state
participation brings in the element of also considering
capacity, which will become an important commodity itself on the
North Slope to get [LNG] to market.
REPRESENTATIVE SEATON responded that he did not wish to
interject ownership into the conversation; however, he expressed
interest in further analysis of RIK and RIV, in terms of
alignment regardless of ownership of the pipeline.
10:33:47 AM
CO-CHAIR FEIGE asked whether it was fair to assume that the
state doesn't necessarily take all royalties "in value" or "in
kind," since the state could take a certain percentage.
ACTING COMMISSIONER BALASH answered that it would depend on the
parameters of the project and the quantity of the resource.
Considering the size of the AKLNG project and proven resource,
any switching between "in kind" to "in value" could have a
ripple effect in the commercial agreements necessary to support
the project in the first place, he said. The state would need
to have a series of agreements in place for either "in kind" and
"in value" royalty, although he cautioned against the state
attempting to have "a foot in both camps" since it will
ultimately increase the number of agreements needed to move
forward with the project.
10:35:36 AM
MS. PODUVAL directed attention to slide 46 entitled" RIK Risk
Profile Is Influenced by the Location of Title Transfer from the
State to Buyer." This slide attempts to demonstrate within the
context of RIK, that the risk to the state increases as it moves
further downstream in the supply chain. This slide shows the
transfer of proven reserves for Point Thomson and Prudhoe Bay to
the GTP, through the pipeline to the LNG plant, and shipped to a
market where it is regasified and utilized by end users. She
said if the state took its gas "in kind" but found a buyer for
the gas at the wellhead the state would be exposed to volume
risk and price risk. First, this is because the state does not
control what the producers produce; and second, since the state
doesn't control market price. Again, these represent the two
dominant risks if the sale occurred at wellhead, she also said.
MS. PODUVAL described the increased risks for the state as it
moves downstream to the GTP, the LNG, and the regasification
stages. If the state moved further downstream and sold gas at
the tailgate of the GTP, the state would be subject to the
aforementioned risks as well as the following: 1) capital costs
for the GTP; 2) operational risks for the GTP, such as instances
when the plant shuts down for maintenance; 3) carbon dioxide
disposal and gas quality; 4) balancing and scheduling volumes
through the GTP; 5) credit risk for contracting for gas
capacity; and 6) any force majeure risk if plant down for a few
months. Certainly, as the state moves down the supply chain,
more components are added and the state's risk profile would
escalate, accordingly, but of course, rewards also come with
taking the risks, she said.
10:38:43 AM
MS. PODUVAL summarized that the state can achieve the highest
market price for its gas at the end of the supply chain. As the
state moves further upstream, it would deduct the cost of
shipping, the LNG plant, and the GTP, but generally at a
premium. For example, the state might achieve $15 delivering
gas at a Japanese port, with the cost of shipping gas from
Alaska to Japan at $1. If the state sold its gas at Nikiski
instead, the market price would be less than $14, since the
shipper would take the increased risk and would want a premium
for it. She pointed out that as the state increases its risks,
the risks are magnified as each element of the supply chain is
added; however, there is a risk premium associated with that, as
well. The state must decide what profile of risk the state will
be comfortable with, and if the state will be adequately
compensated for its risk. In response to a question, she agreed
the rewards line read 15 percent of the Japan Crude Cocktail
[JCC] minus the cost of shipping, minus the LNG cost, and so on.
She further explained that "reward amount" identifies the
increased rewards as gas proceeds down the value chain.
REPRESENTATIVE SADDLER asked for clarification on the risk
premium from .5 percent to 1.5 percent.
MS. PODUVAL answered that it would be an increase in the JCC.
For example, if the LNG price at Japanese port is 13 percent of
JCC, and the state is not taking on the shipping, it should
expect to see a discount of .25 percent to .75 percent of JCC.
10:41:46 AM
MS. PODUVAL reiterated that the LNG price is a percent of oil
price and this example uses the JCC as indicative of the oil
price. The price at the regas point on this chart is 15 percent
of JCC. For example, if the JCC price is $100, the LNG price
would be $15. The risk premium would be .25 percent to .75
percent - without taking on the shipping - so instead of 15
percent it would be between 14.25 and 14.75 percent of JCC, she
said.
10:42:39 AM
REPRESENTATIVE SEATON, referring to the shipping component,
asked whether the shipping component is different for the owner
than the shipping contractor. He asked whether an owner would
build in shipping profit margins similar to privately contracted
shippers.
MS. PODUVAL answered yes; that someone should have an
expectation of return for the shipping component, such as the
producer or a third-party contractor. Typically, shipping is
handled as a long-term lease similar to a pipeline contract and
producers would pay a return to the shipping company.
REPRESENTATIVE SEATON asked for clarification on the risk
premium price adds to the shipping component.
MS. PODUVAL offered that when producers contract with a shipping
company the shippers take on other responsibilities, such as
scheduling ships, nominating volumes, and other operational
issues. Therefore, additional risks are involved with each
supply chain element, including administrative duties.
10:45:45 AM
REPRESENTATIVE SEATON asked whether overhead costs are built in
to the shipping component.
MS. PODUVAL answered no.
10:45:58 AM
ACTING COMMISSIONER BALASH offered another way to think about
this. He characterized the projects as being a "daisy chain" of
contracts. At one end is the buyer at the other end the
upstream, or the royalty perspective for the state. Ultimately,
a series of contracts ensues and the buyer and seller intersect
at some point. Depending on how close or far that intersection
point represents the additional risk the buyer will take on. Of
course, the buyer will request a discount in the ultimate sales
price to compensate them for its risk. Again, as previously
mentioned, LNG projects do not have a transparent market.
Instead of transparency or liquidity, each project stands alone
and as haggling ensues between the buyer and the seller, each
one will be willing or unwilling to take on the
responsibilities. Of course, it will need to be worth their
while to do so, which is the concept that slide 46 lays out for
policymakers as choices are discussed.
10:47:48 AM
MS. PODUVAL continued with slide 47 entitled, "Implementing RIK
Presents Challenges and Hence, Costs for the State Relative to
RIV." She explained this slide lists factors that can create a
separation and value to the state between the RIK and the RIV
options. She identified some cost drivers, including GTP costs,
upstream field cost allowance (FCA), higher of provision, sales
price discount, marketing costs, and credit costs. The overall
GTP costs - and whether these costs are included as a deduction
or cost - can shift the royalty value obtained by the state for
RIV or RIK. For example, Prudhoe Bay is currently allowed an
upstream field cost allowance and it is not resolved whether the
FCA would be applicable within RIK for all fields. The "higher
of provision" adds value to the RIV alternative since it creates
some price protection for the state. The higher of provision
allows the state to receive the higher of the producer "A" value
or the average of producer "B" or "C" in a given market. For
example, if one producer reports an unusually lower value, the
higher of provision would offer the state some protection, which
would not be available under RIK.
MS. PODUVAL explained the sales price discount. Theoretically,
under RIV the state receives a portion of what producers earn
marketing and selling the LNG. Moving to RIK represents the
most significant risk to the state because the state doesn't
have experience in international marketing. In fact, she
pointed out Asian companies particularly value a long-term
relationship of having done business together. The lack of
market experience and the lack of supply diversity are expected
to drive a significant discount to the state when it tries to
market its gas.
MS. PODUVAL explained that supply diversity is important since
the producers have a portfolio of LNG projects and access to LNG
in the short term if a force majeure or other event would not
interrupt LNG. The state would only have access to the AKLNG
project, since it does not have LNG projects worldwide to use
for ebb and flow. Thus this would create an additional risk for
RIK. Marketing costs would entail setting up a marketing
organization to market the LNG and help administer the
contracts. Finally, credit costs associated with entering into
long-term commitments are borne by producers with RIV and by the
state for RIK. She directed attention to the chart on the right
as it demonstrates that the state could essentially lose up to
75 percent of the royalty values with the RIK structure.
10:52:24 AM
REPRESENTATIVE SADDLER asked for distinction in colors on the
chart.
MS. PODUVAL clarified the chart relates to Royalty NPV 10. The
light blue bars show the range of royalty dollars at risk for
each of the factors on the x axis. For example, under price
discounts the royalty value could be as low as $700 million NPV
or as high as $2 billion depending on the assumptions used and
how much discount the state suffers trying to market its own
LNG. In further response, she explained that the NPV multiplier
is 15 percent of JCC previously discussed.
10:53:49 AM
REPRESENTATIVE SEATON referred to price discounts and asked
whether the RIK is a positive up to $2 billion or if it only
represents a potential loss.
MS. PODUVAL answered that it represents a potential loss of $2
billion since Black & Veatch did not envision a scenario in
which the state would achieve a premium relative to the market
price that producers could achieve. Therefore, the state could
suffer 1 to 3 percent of the LNG multiplier as a price discount
relative to what the state would receive under RIV with the
producers marketing the LNG. In response to a question, she
agreed the chart shows the RIV $ 2 billion with RIV and a loss
of $1.3 billion under RIK.
10:55:22 AM
CO-CHAIR FEIGE commented on the lack of diversity of supply for
the sales price discount cost driver. He related a scenario, in
which the state attempts to market gas, but if an interruption
of the gas delivery from the North Slope occurred, it would
effectively cut the state off from marketing its LNG; however,
other producers could fulfill contracts from their portfolio of
LNG holdings. Thus, the producers could command a higher price,
but the state would need to assume the risk of the state losing
its supply.
MS. PODUVAL answered that is correct.
10:56:02 AM
REPRESENTATIVE TARR brought up the state's lack of expertise.
She asked whether the state would have an opportunity to engage
with a consortium with another marketing company with
experience.
MS. PODUVAL said that certainly would be an option. The state
could join an organization and grow its own expertise in
marketing. Keep in mind that the state would take on different
risks to do so when arguably the oil and gas companies are among
the best at marketing. Certainly, the state has the alternative
to access that expertise, she said.
10:57:14 AM
MS. PODUVAL turned to slide 48 entitled, "RIK Creates Additional
Risk and Cost of the State Relative to RIV." She recapped the
risk and costs, such that the state would need to build its own
marketing organization to address origination, logistics,
contract administration, and accounting to market the LNG.
Additionally, the state would face challenges in competing with
the producers who have well established LNG marketing expertise
and global portfolios. Further, the state would be subject to
counterparty risk in all of its contracts across the LNG supply
chain. Next, the state would need to make firm capacity
commitments along the LNG supply chain, which could total up to
$1 billion per year. She cautioned that the state could be
exposed to negative royalties if the LNG price is too low.
Finally, the state could face short-term and long-term
production volume risk since it has no control over production
volumes.
MS. PODUVAL concluded that the producers have the experience
dealing with market uncertainties and they are best equipped to
help the state address those risks.
10:59:09 AM
REPRESENTATIVE SEATON asked to have the volume risk discussed.
He related his understanding that if a volume risk exists
downstream, the economics are chaotic. He asked whether a
volume risk exists relative to producers or just with sufficient
gas volumes available on the North Slope to fill the pipeline.
MS. PODUVAL answered that one of the main differences between
the volume risks assumed by the state in RIK is related to
capacity commitment. This study estimates the level of capacity
needed through the GTP, the pipeline, and the LNG plant when
making sales commitments. It's important to realize that when
volumes produced are higher or lower than the capacity
commitments, they both represent risks to the state. Under RIV,
producers can manage their risks and aided by their long-term
forecasts can better manage their production and capacity
requirements. Conversely, the state would need to rely on the
producer's estimate and the state's 12.5 percent royalty. Under
RIK, the state would base its decision on the volume capacity
through the supply chain commencing once the project is built
and rely on information the producers provide.
11:01:10 AM
REPRESENTATIVE HAWKER remarked that he has been hearing
significant absolute statements from the consultants today in
terms of the state's marketing under RIK. However, little has
been said about contractual risk mitigations under RIK, which
could answer some of the questions raised, he said. He asked
whether all of risks could be mitigated contractually through
complex joint marketing agreements in the final commercial
structure of the pipeline project.
MS. PODUVAL answered yes; absolutely.
11:02:18 AM
REPRESENTATIVE JOHNSON asked how it would affect the economics
of the project if the state used RIK for in-state consumption,
which would exclude the need to liquefy. He understood that
currently the market isn't available to sustain the AKLNG, but
he suggested that perhaps 30 years from now the market could be
sustained. He wondered how it would affect economics if the
state "grew" its RIK as industry continues to grow. For
example, as development happened and new mines opened and
operated that need gas, it would also affect the demand.
ACTING COMMISSIONER BALASH acknowledged he previously mentioned
the department has additional work underway to examine the in-
state energy perspectives and implications, as well as
expansions to the state in a project such as this. Those two
modules will be discussed with the consultants during the next
few days, he said. While, the department hasn't hit the "go"
button just yet on the work, it would likely do so in the next
48 hours.
REPRESENTATIVE JOHNSON answered that he was encouraged by the
short timeframe of 48 hours. He relayed his constituents'
belief that the greatest use of Alaska's gas is for Alaskans.
While he understood the export component, he offered his belief
that [the legislature and the state] must perform due diligence
on in-state gas or it will do a disservice to the communities,
the legislature, the administration, and perhaps the
consultants. Certainly, this must be part of the discussion
since it brings it down to the level of considering heating
homes, or creating jobs, and his constituents have that concern,
he said. He emphasized that in-state gas is his number one
priority in terms of the proposed LNG pipeline since the long-
term benefits represent jobs and the welfare of the state. In
turn, he expressed a willingness to take more risks for his
constituents than for exporting gas Japanese consumers.
11:06:23 AM
CO-CHAIR FEIGE recalled a discussion on royalties, equity, and
capacity. He asked whether the design capacity has been
discussed when it comes to the future ability to meet in-state
demand.
ACTING COMMISSIONER BALASH answered at some point during the
development of the project commitments to capacity - specific
volumes in each component - will be required. He acknowledged
that the risks will need to be assessed, such as whether the
state would initially start off with a full share of the
liquefaction and tailor contracts for the sale of LNG to step
down overseas volumes in order to keep more at home. Another
option to address the concern, in terms of volume of supply
available, will be to ensure that the pipeline can be expanded
as necessary. He acknowledged the North Slope gas resource is
tremendous and it could serve the state as the economy grows and
additional exploration of North Slope gas occurs - non-LNG gas.
He also acknowledged that at some point the state will need to
identify much of Alaska's royalty gas to reserve for in-state
use.
11:08:37 AM
REPRESENTATIVE SADDLER asked for clarification on negative
royalties.
MS. PODUVAL responded that the value received for royalty for
gas "in kind" would be lower than the cost for the capacity
commitment.
11:09:04 AM
REPRESENTATIVE SADDLER asked for clarification on counter party
risk.
MS. PODUVAL pointed out a "daisy chain" of contracts binds an
LNG contract together. This includes the sales and purchase
agreements - with buyers at the end market - shipping contracts,
various marketing contracts, and capacity commitments throughout
the supply chain. Therefore to some extent, the state can be a
counter party to any or all of these contracts. She related a
scenario in which the state is "at the other end of the
agreement" selling to an Asian company. In that scenario, the
state and the Asian company would both be counter parties to
each other. Furthermore, if any of the people are not
creditworthy over the 20-year contract timeframe, the state
would be exposed to that risk, she said.
11:10:28 AM
CO-CHAIR FEIGE asked whether the state could be put in the
position of bidding against its partners. He related a scenario
in which ExxonMobil Corporation, ConocoPhillips [Alaska, Inc.],
and BP Exploration (Alaska) Inc., all sought to sell gas in the
marketplace. He asked whether the state would be competing with
itself if it was also attempting to sell a share of the same
stream of gas.
MS. PODUVAL answered yes.
CO-CHAIR FEIGE asked whether the state could be played by the
buyer.
MS. PODUVAL agreed it could happen.
11:11:27 AM
REPRESENTATIVE SADDLER asked for examples of contractual
mitigation steps to reduce risk.
MS. PODUVAL said one option discussed earlier was to set up a
consortium with smaller LNG sellers to create a diversity of
supply, which could be an example of potential contractual
agreements to help mitigate risk. Another possibility would to
address the issue within the sales agreement and transfer the
risk of supply loss to buyers. Typically, a standard sales and
purchase agreement (SPA) would identify the volumes the seller
is obligated to provide over time and the sales price associated
with it. However, the state could modify the contractual terms
to identify exceptions - such as a force majeure at the LNG
plant, or if production on the North Slope falls below a certain
volume - and contractually transfer the risk. However, the
exceptions would come at a cost reflected in the sales price.
REPRESENTATIVE SADDLER asked whether it is possible to divest
risk.
MS. PODUVAL answered yes; however, it will come at a cost since
the counter party may be willing to take risks not normally
taken in the market. It's important for the state to identify
the best way to mitigate its risk given the options it has
available. Certainly RIV would be one option and it could
transfer many inherent risks to the producers, who arguably have
better tools to mitigate the risks. Alternatively, with RIK
methods do exist to transfer risks contractually for a price and
the state must decide the direction to proceed once the options
are offered.
11:14:40 AM
REPRESENTATIVE SADDLER remarked it seemed important to maintain
the relationship with the producers and market RIV gas as
another way to increase alignment.
11:14:58 AM
REPRESENTATIVE JOHNSON asked whether marketing consortiums exist
today.
MS. PODUVAL asked to defer the question to a later date,
although she commented she was not aware of consortiums in the
sense that Representative Tarr previously mentioned.
11:15:28 AM
REPRESENTATIVE HAWKER offered his belief that the aforementioned
mitigation under discussion related to a consortium of small
companies. The state would contract with the major shippers to
mitigate and share risk, although the composition wouldn't
restrict the consortium to small players or non-shippers. He
related his understanding that this would refer to a general
mechanism related to commercial agreements and not royalty
agreements.
11:16:34 AM
MS. PODUVAL turned attention to slide 49 entitled, "Summary:
Alaska Fiscal Framework." She concluded that 70-85 percent is
high for the government take given the complexity of the AKLNG
project. Further, the projected IRR of approximately 15 percent
may be insufficient for producer investment relative to their
alternatives. She further concluded that well-designed
incentives to lower project costs and modify fiscal structure
can help make the AKLNG project competitive in market. For
example, as discussed earlier, measures can reduce leakage to
the federal government and make the project more competitive in
the market. Ms. Poduval emphasized that the state taking its
royalty as RIK could substantially increase risk and creates
loss of value to the state. In particular, producers have more
experience navigating the LNG supply chain and managing
associated risks.
11:17:46 AM
REPRESENTATIVE SEATON asked for clarification whether that means
when the state assumes greater risk that the IRR for the
producers is actually enhanced.
MS. PODUVAL answered that the specific question of RIK and RIV
would be considered intangible benefits. Theoretically if the
royalty method works efficiently it should be revenue neutral
for the state and the producers; however, she was uncertain
whether the producers necessarily gain value in dollars by the
state taking its royalty "in kind." She offered her belief that
from the producer's perspective, RIK would avoid valuation
disputes and therefore, it would reduce administrative burden,
which would benefit producers.
REPRESENTATIVE SEATON understood the royalty options as being
negative to the state, but he pointed out that [RIK] is not a
positive either.
MS. PODUVAL answered that producers would definitely consider
RIK as being beneficial to them; however, she was unsure that
benefit is achieved as a dollar amount. In other words, the
producer's revenues aren't going to be higher if the state takes
its royalty "in kind" versus "in value". Instead, she
reiterated that the producer's benefit and dollars may be gained
by avoiding valuation disputes and subsequent legal disputes, as
well as reducing their administrative burdens.
11:20:20 AM
MS. PODUVAL turned attention to slide 50 entitled, "Risk
Allocation & Commercial Structure - Scope." She highlighted
that the goal was to understand how key risks could impact the
AKLNG project and stakeholders as well as to provide an
assessment of the alternatives for financial and equity
participation by the state in the AKLNG project. She turned to
slide 51 entitled, "There Are Various Uncertainties Related to
the AKLNG Project that Could Impact the Economic Benefits to the
Different Stakeholders." After all, many of the risks are
beyond the control of the state and beyond the producers, but
price and capital costs are two key drivers. Additionally, the
project schedule, the cost of debt, and escalation tie into the
aforementioned key risk factors.
11:21:45 AM
MS. PODUVAL explained two charts on slide 52 entitled, "Price
and Capital Cost Related Uncertainties Emerge as the Key Factors
Driving the Project Economics." These charts show the NPV to
the state and producers. Essentially, the charts are set up as
a tornado plot with the black line intersecting the middle
identifying the "base case" level. By varying the uncertainties
[listed on the vertical axis] the slide shows the impact on the
NPV for the state as well as for the producers. She explained
the graphs, such that price and capital costs represent, by far,
the dominant factors that affect NPV. Escalation, project
capital cost, and cost of debt are other key uncertainties, as
well, she said.
11:23:18 AM
MS. PODUVAL moved to slide 53 entitled, "Risk Allocation and
Management." She said this slide explores risk allocation, risk
mitigation, state participation, and implications. First, with
respect to risk allocation, the two factors of cost and time
risks in project execution are highly dependent on the nature
and extent of the project organization. She pointed out most of
the recent LNG projects have a single operator through the
supply chain [upstream, transport, and liquefaction], as well as
having an integrated consolidated control, which helps reduce
the capital and scheduled risk. Second, with respect to risk
mitigation, risk management is executed in several ways: 1)
pre-final investment decisions (Pre-FID) commitments from the
buyers - which are almost mandatory. In fact, the majority of
project volumes are contracted before FID to ensure market to
verify that the market exists prior to committing capital; 2)
end user participation, which is a trend that entails buyers to
have an equity stake in the project. It helps to have some skin
in the game and to ensure market for the volumes; and 3)
government participation, in which the host country participates
in LNG projects, typically through a national oil company (NOC)
in combination with the independent oil companies - these are
typically LNG majors who bring international LNG experience to
the project. Further, the state's equity participation can
allow the host company to capture an upside in prices; however,
it also exposes the state to a downside since it must commit
capital to the project.
11:25:50 AM
MS. PODUVAL turned specifically to Alaska with slide 54
entitled, "Equity Participation by the State of Alaska Could
Have Tangible Benefits for the Project as Well as the State."
First, to the extent the state transfers some value to the
producers through modification of fiscal terms, obtaining an
equity interest in the project in exchange for that transfer of
value is far more beneficial to the state than a simple
reduction in fiscal take. For example, as previously discussed,
the effect and impact the state can have in reducing or
eliminating its royalty production tax and property tax would
transfer value to the "other end of the table" and benefit the
state. Equity participation can also create a greater alignment
of economic interests between the state and producers.
Additionally, state ownership would lower the upfront capital
cost to producers, which could create potential economic uplift.
In fact, this is especially important when it is a high-cost
project with AKLNG. Equity participation would allow for
TransCanada PipeLines Limited (TCPL) equity participation and
operation of the pipeline and GTP. Next, equity participation
could help facilitate greater transparency in the AKLNG process
and access to information. Additionally, equity participation
also allows the state to influence access for third parties in
the most critical potential bottlenecks of the project -
pipeline and marine terminal. Although equity investment in the
supply chain allows the state a seat at the table, it does not
necessarily provide for a vote in the decision-making process.
Thus, joint venture agreement structuring is critical in helping
ensure the benefits are achieved.
11:28:24 AM
CO-CHAIR FEIGE referred to transferring value to the producers
and exchanging royalty value for equity value. He asked whether
the implication is that it should be done on a one to one ratio
or whether the ratio should be different.
MS. PODUVAL answered that it would depend on how the state wants
to structure [its agreement]. If the state wants to provide an
incentive to the producers, rather than reducing production tax
or royalty, it should use dollars for an equity stake since that
would reduce the producers' cost while also giving the state
value.
CO-CHAIR FEIGE understood a certain amount of leverage would be
gained, as well.
MS. PODUVAL answered yes; absolutely.
11:29:43 AM
CO-CHAIR FEIGE asked what benefit the state would achieve if it
granted TCPL equity participation since the Alaska Gasline
Inducement Act (AGIA) does not currently give TCPL an equity
position in the proposed AKLNG project.
MS. PODUVAL answered that the state could obtain several
tangible benefits with TCPL participation. First, TCPL is an
experienced pipeline company with experience in Arctic
pipelines. Thus having TCPL's expertise as
builder/owner/operator of the AKLNG pipeline could help maximize
the state's equity in the AKLNG project. Further, another
benefit would be that TransCanada as a third-party non-producer
could attract more shippers on its portion of the project.
Therefore, having TCPL involved could help the state achieve its
objectives of open access and open the North Slope for other
exploration and production.
11:31:07 AM
CO-CHAIR FEIGE suggested it could be argued that the state could
hold the equity shares and offer that same additional capacity.
MS. PODUVAL agreed that the state could do so, as well.
11:31:16 AM
REPRESENTATIVE SADDLER asked how TransCanada would acquire
equity participation. For example, he asked whether it would be
subrogated.
MS. PODUVAL answered that the equity portion could range from
zero up to the level of state's equity stake.
REPRESENTATIVE SADDLER suggested the state's participation in
the equity position may be dependent upon giving TransCanada a
portion, as well.
MS. PODUVAL agreed.
11:31:47 AM
ACTING COMMISSIONER BALASH responded to the question whether the
state could offer interests or opportunities for expansions to
third parties directly rather than relying on a company such as
TransCanada. He offered his belief that it wouldn't be a
perfect comparison, but it goes back to the RIK and RIV issue of
who is best equipped to market the gas. Certainly, expertise
has value, and a company whose core business is pipelines knows
the problems from a technical perspective and a commercial
perspective. In fact, pipeline companies have a well-defined
and well-understood set of solutions to various problems that
might occur. Again, he reiterated the value of expertise
obtained from pipeline company participation.
11:32:52 AM
REPRESENTATIVE SADDLER asked whether it would be possible to
transfer some of the state's outstanding obligation in matching
funds to TransCanada to convert it to some equity position.
ACTING COMMISSIONER BALASH answered that anything is possible.
He said he didn't want to "go down a rabbit trail," but what
becomes of the AGIA license and whether it continues to function
or if the state can step out of the license into a different
arrangement (with TransCanada) is all very much in question.
11:33:50 AM
REPRESENTATIVE SEATON referred to the bullet point on equity
participation related to greater transparency. He recalled
under Governor Murkowski's administration that the operating
agreement and owner rights were secret and still remains so. In
fact, he pointed out this information was never released to the
legislature. He highlighted that this has created problems for
the legislature, which he characterized as an "end game hand
grenade." He asked how the state can work the project terms
into a transparent agreement to avoid the aforementioned issues.
ACTING COMMISSIONER BALASH responded that at various times along
the way Governor [Parnell] has laid out benchmarks leading to a
specific course of action, stage, or gate in the AKLNG project
development. He said, "One term I've heard him use publically
as well as privately is the need for commensurate steps. That
as the project sponsors take steps towards development and get
more committed to the project, the state is prepared - at least
under his direction - to take additional steps." He likened it
to being "a series of pops as opposed to a bang. "That is one
thing that could distinguish what it is we're trying to achieve
here, versus prior attempts to bring the parties together."
11:36:21 AM
REPRESENTATIVE SEATON said he appreciated the response and the
broad goal pieces; however, he cautioned that it is the details
that matter. He recalled that the partners previously were
opposed to operating agreement details being released. He
wondered whether the administration was confident that the
situation would be different if the state enters into an equity
investment with potential partners. He expressed concern that
the legislature might be asked again to ratify whatever the
administration negotiates and finalizes.
ACTING COMMISSIONER BALASH offered his belief that the state's
administration understands the issue better than its
predecessors; however, he wasn't prepared to speculate what
other parties are thinking.
REPRESENTATIVE SEATON asked to put it on the table that the
state needs to be concerned about the confidentiality issues
interfering with the need for transparency.
ACTING COMMISSIONER BALASH interpreted Representative Seaton to
say, "We can't have anybody stand up and say, 'You have to vote
for it to find out what's in it.'" He commented that he was
fairly certain everyone learned that lesson.
11:39:42 AM
CO-CHAIR FEIGE understood the process would instead be for the
administration to work with parties and incrementally reach
agreements.
ACTING COMMISSIONER BALASH answered that he is correct.
REPRESENTATIVE HAWKER stated he was glad to hear the
administration's intentions.
11:40:42 AM
MS. PODUVAL moved to slide 55 entitled, "Alternatives for the
State to Participate with an Equity Investment in the AKLNG
Project - Description." She explained that three alternative
structures for equity participation were considered. First, an
equity alternative, in which the state makes an equity
investment and receives an equivalent share of gas produced as
royalty and tax gas. Under this scenario royalties would
continue to be received under the SB 21/MAPA structure with all
upstream costs being allocated to oil. She highlighted that
this analysis assumes a 70/30 debt equity structure for the
state's investment, with a 5 percent and 12 percent return on
equity, as well as considering equity investment at 15 percent
and at 35 percent.
MS. PODUVAL highlighted the second scenario. Black & Veatch
considered an equity alternative in which the state completely
owned the pipeline. Under this structure the producers would
pay a tariff to the state for transportation services on the
pipeline. Producers would benefit from the lower cost of debt
as well as a low return on equity required of 6 percent -
intended to provide an incentive to producers, while the state
would benefit through lower netbacks for royalty and production
taxes. Alternatively, comparisons were made with one financed
with 100 percent debt and the other with 100 percent equity.
Third, Black & Veatch considered a scenario in which the state
had a 12.5 percent equity stake through the supply chain GTP and
LNG. This would be an approximation of the state's royalty
share. The state's share of capacity would be used to treat,
transport, and liquefy royalty gas. The state would benefit
with lower cost of debt at 5 percent and a lower return on
equity requirement. For comparison, again, the upper and lower
bound assumed financing at 100 percent debt and next with 100
percent equity.
11:44:09 AM
MS. PODUVAL turned to the graph on slide 56 entitled, "State
Equity Participation at Appropriate Levels Could Allow SOA and
Producers to Retain Higher Share of Project Revenues." This
showed stakeholder NPV 10 comparisons with the various
stakeholders. She explained that the first bar of the graph
shows the base case. The next two sets of bars show the equity
alternative, with the [fourth and fifth] bars with the state
owning the pipeline, and the final set of bars shows 12.5
percent state investment. Essentially, the slide demonstrates
that midstream investment - the option at the very right of the
slide - reduces the netback for royalty and increases royalty
and production tax to the state. Thus, this would benefit the
state, but producers would lose a portion of the project the
state owns. The 100 percent pipeline ownership scenario can
benefit the state and the producers since it would lower the
overall cost for one critical element of the supply chain. This
would benefit the state when the state uses debt to finance its
investment rather than equity. However, the equity alternative
can benefit both the state and the producers at an appropriate
level of investment. She offered to cover this alternative in
more detail in subsequent slides.
11:45:48 AM
MS. PODUVAL, referring to the gray bars on slide 56, explained
that this makes sense since the producers benefit across all of
the scenarios. One of the factors that makes the equity
alternative more attractive is the state would participate
across the entire supply chain. Certainly, this can be powerful
for the state since it creates a path through the entire supply
chain. For example, the state could use it for itself or to
create access for other producers with activity on the North
Slope.
11:46:47 AM
REPRESENTATIVE SEATON, referring to slide 55, asked for
clarification on the statement that the state would benefit
through lower netbacks for royalty and production tax. He
further asked for the rationale that would result in a lower
netback with 100 percent state ownership.
MS. PODUVAL answered that state investment in the pipeline would
essentially lower the cost of the pipeline for everyone since
the state enjoys a lower cost of debt. Additionally, the
state's expectation for return on equity will be lower than
producers demand for return for their investment. Thus, it
would be an incentive the state would offer to producers by
requiring a lower rate of return. The computation for the
tariff across the pipeline when using two assumptions of lower
cost of debt and lower return on equity, would lower the per
unit cost of transportation for the pipeline. Therefore, since
it results in a lower pipeline tariff and it would make the
royalty calculation higher because it allows a smaller
deduction.
11:48:16 AM
REPRESENTATIVE SEATON related his understanding that it doesn't
relate to lower netbacks for royalty; instead, it would result
in higher netback for royalty and a higher wellhead price.
MS. PODUVAL agreed that the wording is confusing. She
reiterated that it would result in a higher netback to the state
because of lower deductions.
REPRESENTATIVE SEATON related his understanding the difference
in scenarios calculations is that the state would have less of a
NPV, perhaps 6 percent instead of 12 percent. Referring to the
aforementioned scenarios, he asked for further clarification on
whether the state would be willing to accept less interest on
investment than the producers. For example, if the producers
held a large part of the project, the transfer of value would
lower the overall project cost, while increasing producer return
on investment.
MS. PODUVAL acknowledged that is the underlying assumption for
the alternatives shown [on the chart]. Certainly, it is also
feasible the state would want an equivalent 12 percent return on
equity on its investment; however, participation could also be
beneficial to the producers since it would reduce the upfront
capital cost due to the $10 billion it would not need to invest.
11:50:29 AM
REPRESENTATIVE SEATON asked for further clarification, if the
interest rate was the same, that it would still gain value and
not reduce the state's interest.
MS. PODUVAL acknowledged that the producers would gain value due
to the reduction in the upfront capital investment.
11:50:46 AM
CO-CHAIR FEIGE asked whether the tariff would be set by FERC or
the Regulatory Commission of Alaska (RCA) if the state owned 100
of the pipeline.
ACTING COMMISSIONER BALASH responded that the decision on
jurisdiction and specific authority for either regulatory body
is fact specific. Certainly, an argument could be made that a
very large LNG export project would be subject to Section 3 of
the Natural Gas Act (NGA); however, an argument also exists that
Section 3 would be limited to liquefaction, but Section 7 [NGA]
would apply to the pipeline. Still, another argument could be
made that Section 7 jurisdiction on the pipeline and GTP does
not apply, since the RCA has jurisdiction. Ideally, the state
would avoid endless litigation and achieve a result that would
protect the broad interest of all parties as well as the public.
11:52:27 AM
CO-CHAIR FEIGE remarked that the uncertainties need to be
resolved. He asked whether the administration has taken any
action to resolve jurisdictional issues.
ACTING COMMISSIONER BALASH answered that the options range from
"crystal clear" certainty from the Congress - which could take
time - to seeking a preliminary declaratory order from the FERC
to some negotiated resolution.
11:53:09 AM
REPRESENTATIVE LINDSEY HOLMES, Alaska State Legislature asked
whether the first scenario, the equity alternative would assume
the state takes its royalty "in kind."
MS. PODUVAL answered not necessarily, since it could be either
RIK or RIV.
REPRESENTATIVE HOLMES related her understanding that the equity
alternative also assumed a 70/30 debt to equity ratio; however,
it changes under the third scenario - the 12.5 percent SOA - and
assumes either 100 percent debt or 100 percent equity. She
asked for clarification on the change in assumptions.
MS. PODUVAL responded that the scenarios Black & Veatch used
attempts to identify a reasonable range of alternatives for the
state. An equity amount hasn't yet been determined, so 15
percent and 35 percent equity were selected. The 70/30 debt to
equity ratio used represents a base case assumption - typical
for investment on LNG projects - which the state would likely
use to structure its investments. Certainly, additional
scenarios could have been provided, such as 15 percent equity
participation with 100 percent debt; however, Black & Veatch
chose to pick the mid-point of the debt to equity structure.
11:55:31 AM
REPRESENTATIVE HOLMES acknowledged significant discussion has
occurred with respect to a potential 12.5 percent alignment
since it represents the current royalty share. She asked for an
estimate using a 12.5 percent using a 70/30 debt to equity
ratio.
MS. PODUVAL answered that it would fall somewhere between the
results of the two scenarios [100 percent debt and 100 percent
equity].
11:55:57 AM
REPRESENTATIVE SEATON surmised the source of the state's
investment would be from the constitutional budget reserve (CBR)
account or more likely the state would use Alaska Permanent Fund
(APF) with a projected 8 percent return on investment. He asked
whether any issues arise in using the APF's equity and investing
it at less than the projected 8 percent long-term return.
ACTING COMMISSIONER BALASH offered to address a couple of
things. First, the returns cited are based on a general return
that the U.S. Department of Treasury has managed in its
portfolio, which includes more than just the CBR. Second, with
respect to the Alaska Permanent Fund Corporation (APFC) funds,
Commissioner Rodell [Department of Revenue (DOR)] has made it
clear that the state does not direct the Alaska Permanent Fund.
He then said, "If the investment opportunity is attractive to
the trustees in the APFC, then so be it." Therefore, the
department has chosen not to suggest the APFC might be the
source for capital for a state investment. Finally, in terms of
an equity position, it is fluid so where the state starts might
not be dictate where it will end up. Certainly, this goes back
to the potential for a TCPL role. For example, if the state's
share of midstream project costs $5 billion or $6 billion,
having any pipeline company partner to take on the role of
providing midstream transportation services, with acceptable
terms, means the state would not need to come up with the $5-6
billion to finance the pipeline. The state should keep this in
mind as it contemplates the source of capital to fund the AKLNG
project. In response to Co-Chair Feige's comment on the
possibility of selling it to lessees, Committee Balash remarked
that the administration would not enjoy options unless it starts
with the equity position.
11:59:12 AM
MS. PODUVAL moved to slide 57 entitled, "Appropriate Level of
State Equity Participation Needs to be Balanced to Achieve
Benefits to SOA and Producers." As previously discussed, the
equity alternative is most likely to be attractive since it
involves participation in each element of the LNG supply chain;
however, it does raise the question of the appropriate level of
state participation in the AKLNG project. The purpose of the
next few slides delves into this specific question and considers
what it would mean to the state if its participation is 15
percent equity participation versus 35 percent level. She
stressed that the project economies are extremely sensitive to
the assumptions regarding capital cost and market prices. She
highlighted that the slides outline nine scenarios that consider
the combination of high and low capital costs and market prices
to identify the effect it has on the state. More specifically,
it projects whether the state is better or worse off at these
two levels under each of the proposed scenarios.
12:00:43 PM
MS. PODUVAL explained that the SB 21/MAPA fiscal structure did
not include any production credits for gas so the analysis
included a modified status quo, wherein the production credits
that currently exist for oil are extended to gas. For example,
a $5 per BOE credit for gas would be equivalent to reflect new
oil. The analysis examines the project economics under the
modified status quo and under the equity alternative for both
the state and the producers across a combination of scenarios.
Turning to slide 58 entitled, "Equity Participation at 35
[percent] More Beneficial to State than at 15 [Percent]," she
noted the top two charts assuming a 15 percent state investment
and the bottom two charts assume a 35 percent state investment.
MS. PODUVAL elaborated that the two charts on left show the
state's NPV through the 30-year analysis period, whereas the two
charts on the right show the producer's NPV for the same
timeframe. The blue bars project the modified status quo
whereas the green bars depict the equity alternative. She
explained when the green bar is at or above the blue bar that
means the equity alternative is equivalent or better than the
status quo. The top left chart indicates that the green bar is
lower in six of the nine scenarios so at 15 percent investment,
the state is better off staying in a modified status quo than
investing in the AKLNG project. However, keep in mind that in
addition to the project investment, the state agrees to take its
tax as a gross share of production. Thus under the equity
alternative state's take would be the 15 percent equity
investment in the project and 15 percent share of the gross
production, she said.
12:03:17 PM
MS. PODUVAL directed attention to how the scenarios affect
producers, noting with 15 percent equity, the producers do
better in 6 of 9 scenarios. Changing to 35 percent state
investment, the state would be better off in 8 of 9 scenarios
than maintaining the status quo as modified by SB 21/MAPA.
Whereas, the chart on the right shows that at 35 percent the
producers do not lose much value either. Therefore, these
charts show how equity participation can potentially benefit the
state and the producers. She acknowledged while 35 percent does
not represent the correct number, it is getting closer. In
fact, by adjusting the figure a little lower, it approaches the
number in which the state benefits, but perhaps not as quite as
much as shown on the chart. One of the factors that helps make
this work is federal leakage. To the extent that the state
participates, it represents the portion of the project that is
shielded from federal taxes and the value could be effectively
shared between the state and the producers.
12:05:50 PM
CO-CHAIR FEIGE commented that the funds could be kept in Alaska
as opposed to being passed on to the federal government.
MS. PODUVAL agreed it could be shared between the state and the
producers versus the state passing the value to the producers,
who in turn pay a portion to the federal government.
12:06:07 PM
REPRESENTATIVE SEATON referred back to the analysis on slide 57.
He asked how much $5 BOE would be compared to the value of a
barrel of gas.
MS. PODUVAL said it assumes 6 as a thermal conversion factor so
$5 is equivalent to $.83/MMBtu of gas. She repeated the
equivalent at $.83/MMBtu.
12:07:16 PM
MS. PODUVAL turned to slide 59 entitled, "State Equity
Participation Between 20% and 30% Offers NPV 10 at or above the
Modified Status Quo Levels for the State." She commented that
the bars would need to be equal in order to work for the state
and producers. In essence, 15 percent and 35 percent equity
participation doesn't achieve that effect, although 35 percent
is closer to the right figure, she said. Next, Black & Veatch
considered the equity level of participation that would make the
bars the same height. In other words, Black & Veatch sought the
percentage that could make the state's position under modified
status quo the same as what it would achieve through equity
participation. Of course, that figure varies depending on the
assumptions for capital cost of the project and market since
those factors drive the amount of royalty and production tax
under the status quo. She referred to the investment prices
listed on the bottom of slide 59, including low, base, and high
price. Each of the three price assumptions represents different
levels of investment. She directed attention to the middle of
the chart, and said that somewhere between 20-30 percent feels
like the right level of state equity participation, which would
allow the state to match or better the status quo.
12:09:01 PM
REPRESENTATIVE SADDLER asked whether the modified status quo
assumes significant value would go to the federal government.
MS. PODUVAL answered yes; that the producers would be subject to
35 percent taxation.
12:09:20 PM
MS. PODUVAL directed attention to slide 60 entitled, "SOA Equity
Investment in AKLNG Creates Risk Exposures that Need to Be
Considered and Managed," which highlights that equity investment
doesn't come without its own risk exposure. She noted this will
need to be carefully considered and managed. This slide lists
five bullets that identify the state's risk exposure. One, the
state would risk exposure due to cost overruns and "cash calls"
above the appropriation levels - to the extent that the actual
capital costs exceed the budgeted amount. Two, as an equity
investor in the project, the state would be obligated to make
available its share of capital cost contribution. In fact, this
represents a significant and real risk of the AKLNG project
given its very high costs structure and strong inflationary
pressures in the LNG market. The state would assume all force
majeure risk through the GTP pipeline and the LNG terminal.
This was previously discussed in terms of RIK, but would be very
much true as an investor in the project. Three, the state has
no control over upstream operations and volumes produced. This
means the state could have excess or insufficient capacity
relative to volumes produced. Further, balancing production
volumes and volumes through the supply chain on a short-term and
long-term basis would be a risk the state would have to actively
manage and mitigate. Four, if the state assigns its equity
position with a third party, such as TransCanada, and contracts
for capacity with the third party, the state will likely have to
provide credit support to the entity. It would do so through
long term contractual commitments, she stated. Finally, if that
were to happen, the state would be responsible for all demand
charge obligations throughout the life of the contract
regardless of gas supply availability and market conditions. As
previously discussed with the RIK option, this presents another
scenario in which the revenues earned on LNG sales may not
offset the costs of capacity charges [for treating, transport,
and liquefaction, which could result in a negative cash flow to
the state].
12:12:01 PM
REPRESENTATIVE JOHNSON, referring to the second and last
bullets, asked whether the state would be responsible for all
risks or a proportionate share.
MS. PODUVAL responded that the state would be responsible for
every project component, proportionate to its share of the
project. In further response, she agreed that the state would
not assume all the risk.
REPRESENTATIVE JOHNSON asked whether that would also apply to
demand charges.
MS. PODUVAL agreed it would apply to all contractual demand
charges, but it would not be proportionate since the terms would
be contractual. In response to Representative Seaton, Ms.
Poduval answered that the $5 BOE is equivalent to the production
credit given to new oil, which would remain flat at $5 per
barrel.
12:13:59 PM
CO-CHAIR FEIGE asked for clarification on the force majeure risk
since the state is currently self-insured. He further asked
whether the state could cover some risk with an insurance policy
and the availability of such insurance.
MS. PODUVAL answered that she was unsure.
ACTING COMMISSIONER BALASH explained that commercially insurance
options are available, but he was unsure of whether the state is
eligible since it self-insures. He offered his belief that the
department would need to discuss this further with the DOA.
12:15:09 PM
REPRESENTATIVE SEATON recalled Representative Hawker previously
raised the issue of commercial agreements with a third party.
He asked whether those types of agreements are available
globally, such that one company or entity has alternative
sources of supply agreements with other suppliers.
ACTING COMMISSIONER BALASH answered that unusual risk policies
can be tailored by high-end firms such as Lloyds of London. He
related his understanding that the company could write an
insurance policy for anything, but it is a matter of the charge.
He identified the "what, when, and where" variables would need
to be considered. With respect to the counter party risk
question, he remarked that, "You're only as strong as your
weakest link," he said. So where the link breaks will dictate
the amount of exposure. For example, how much demand charges
will be owed to various parties depends on how far the buyer had
to come upstream in order to assume the risks, counter party
claims, and obligations. He said he was unsure of whether the
state would want an insurance policy for the GTP; however,
without a GTP the state will not have LNG since the carbon
dioxide must be removed prior to any liquefaction trains.
12:17:42 PM
REPRESENTATIVE TARR, referring to the first and fourth bullets,
asked whether it was possible to compartmentalize. She related
a scenario in which TCPL was the owner/operator of the pipeline,
so the pipeline would be removed from the GTP and liquefaction
terminal part of the project. She asked for clarification on
how the state could assess opportunities, for instance, how to
become equity partners in the aforementioned scenario. She
further asked whether anyone would be a better operator for the
terminal than TransCanada.
ACTING COMMISSIONER BALASH acknowledged that those opportunities
would exist. He said he could identify a handful of companies
who have expressed either an interest in building a liquefaction
plant, participating in a liquefaction plant, or some other part
in the proposed LNG project. Certainly, the state would need to
clearly weigh the relationship of that party to the buyers, he
said. He recalled that former DOR Commissioner Harold Heinze
addressed the Royalty Oil and Gas Development Advisory Board
recently and had emphasized his view that it's important to get
the buyers invested in the infrastructure in some manner so they
don't ever walk away from the sales contracts. This would leave
a handful of companies within each of the LNG buying countries,
with a significant amount in Korea in Cogas, and a wider
selection of parties would be interested in Japan, he said. For
example, Mitsubishi has historically been interested, but there
are others as well.
12:20:04 PM
REPRESENTATIVE JOHNSON related a scenario in which he assumed
the state did not take any royalty gas "in kind." Referring to
the second bullet, he asked whether the state would have any
delivery risk throughout the GTP, pipeline, and LNG terminal.
In other words, the state would only have to replace "what's
broken" as opposed to the gas delivery.
MS. PODUVAL answered that it would depend on the arrangement the
state makes for that gross share of production attributable to
the state under this alternative.
12:21:03 PM
REPRESENTATIVE JOHNSON assumed the state would not be subject to
risk for the supply for the upstream and midstream activity if
the state obtained RIV and delivered it to the terminal without
shipping or marketing its gas.
MS. PODUVAL offered her belief that would generally be true, as
previously discussed the state would have operational and
capital risk for each of the midstream components, but not be
the counter parties to those agreements.
REPRESENTATIVE JOHNSON remarked that the state would not need to
buy gas for Japan on the open market; instead the state would be
responsible to only fix what was "broken" such as the GTP or
pipeline. He asked for clarification that the state would only
be subject to operational risks.
MS. PODUVAL answered that is correct.
12:21:58 PM
MS. PODUVAL turned to slide 61 entitled, "Ensuring Transparency
& Open Access will Depend on the Actual Terms Negotiated for
State Participation." She explained this slide highlights the
importance of the term details. First, state equity
participation and investment in the project could have
significant benefits as has been discussed today. Again, the
details that constitute any agreement between the state and
producers will be critical to achieve the aforementioned
benefits and help ensure transparency and open access. Equity
participation should provide transparency as well as access to
each segment subject to equity participation in the AKLNG
project. Second, having a position on the management committee
should help ensure transparency and access to information.
Third, participation through secondees - the actual teams - on
the GTP, pipeline and LNG plant would demonstrate yet another
way the state could have access to information and achieve
transparency through its equity participation. Fourth,
structuring an undivided joint interest or creating a "pipe
within a pipe" could also help facilitate expansion. In short,
while significant benefits exist with equity participation, the
state must intelligently manage and mitigate associated risks.
Finally, the state must be mindful of the details of the
negotiated agreement to achieve transparency and access to
information.
12:24:48 PM
MS. PODUVAL directed attention to slide 62 entitled, "Summary:
Risk Allocation & Commercial Structure." To summarize, the
AKLNG faces risks that could affect the economic benefits to the
stakeholders with market prices and capital costs as the two key
risks identified. Next, direct equity participation by the
state can offer benefits to all parties involved in the AKLNG
project, but the accompanying risk profile changes should be
managed. Finally, the various commercial terms related to the
state's equity participation will determine whether the state
can achieve its transparency and reach its objectives. She
characterized this as being a classic case of "the devil being
in the details." She offered her belief that the [AKLNG] idea
is a good one but the execution is very critical. She concluded
her PowerPoint presentation.
12:25:48 PM
REPRESENTATIVE JOHNSON returned to liability issues. He
remarked that parties sue the "deep pockets" in the U.S. courts.
He related a scenario in which the state is an equity partner up
to the tidewater. He asked whether the state can be held liable
for the natural gas shortage and if the state can be sued as a
"deep pocket" prior to any gas delivery.
MS. PODUVAL answered yes; it is a possibility. Naturally lots
of people exist who are ready to sue. However, the likelihood
of success in litigation against the state also depends on how
the contracts are structured. She offered her belief that this
is a risk that can be managed.
12:27:13 PM
REPRESENTATIVE JOHNSON asked whether any minority equity partner
in a pipeline has successfully been sued - anywhere in the world
- for failure to deliver gas.
MS. PODUVAL answered no; not that she was aware.
12:27:31 PM
REPRESENTATIVE SEATON asked whether the administration has
developed a list of potential conflicts of interest for the
state as a participant in a commercial operation.
ACTING COMMISSIONER BALASH answered that this study was
commissioned to assist in understanding the value proposition as
it specifically relates to the state's royalty. He explained
that the administration "opened the aperture" to examine some
tax implications to better understand the economics of the
netback on royalty. He acknowledged the issues in question are
ones that a state agency has previously examined. He advised
Representative Seaton that a body of documents was generated
near the end of former Governor Knowles' administration in the
early 2000s that touches on some of the issues. Granted, some
of the issues will be different since the agency examined a
North America pipeline rather than an LNG project so the needs
or benefits will change; however, but a number of the issues
remain relevant. Fortunately, earlier this year, the
legislature passed and the governor signed HB 4, which
establishes a separate legal entity, a public corporation of the
state, but one that is separate from the state. Certainly, that
would offer one avenue for the state to shield the general
treasury and agencies from some actions and commercial
entanglements. At the same time, how the state might
effectively use that corporation depends on the circumstances
involved.
REPRESENTATIVE SEATON commented that equity participation and
ownership was critically important to the previous conversation
so his interest is for the administration to identify the
potential conflicts of interest and how to overcome them.
12:31:13 PM
REPRESENTATIVE SADDLER referred to slides 58 and 59, and asked
whether the low, base, and high prices could be characterized as
20, 25 and 30 percent participation.
ACTING COMMISSIONER BALASH answered that the low base and high
base on investment refers to whether the Capex estimates came in
on budget, under budget, or over budget.
12:31:47 PM
REPRESENTATIVE SADDLER acknowledged he may be missing something.
He asked why gaining the equity participation rate equivalent to
the modified status quo is to the state's benefit. He further
asked whether the benefit was related to the taxes or if she
could identify the net benefit for the state or the producers.
MS. PODUVAL responded that the study attempts to determine if it
is possible for the state to provide value and incentives to the
producers, but not lose value itself. In essence, it asks the
question of what is the level of equity investment necessary so
the state does not lose value. As a result the analysis showed
that somewhere from 20 percent to 30 percent is the point at
which the state has incentivized the producers by contributing
significant capital to the project, yet the state would achieve
sufficient value and not lose value relative to status quo.
12:33:12 PM
REPRESENTATIVE SADDLER referred back slide 58 and asked Ms.
Poduval to identify the equilibrium point.
MS. PODUVAL pointed out that two levels of state investment on
slide 58 are charted: 15 percent and 35 percent. She explained
that 15 percent represents the state's investment in the project
and the 15 percent gross share as royalty and production tax
paid by producers. As the slide indicates, at 15 percent level
the state has lost value in the process [in most instances].
Basically this is because the status quo almost always better
than the equity investment in the project. It follows that 15
percent isn't the right percentage for the state to incentivize
producers without losing value. At 35 percent equity
participation, while the state benefits across eight of the nine
scenarios the producers may or may not benefit. Therefore, 35
percent gross share of production and 35 percent investment
would be set too high she said. Referring to slide 59, she
pointed out that this slide examines the capital cost and price
to identify the level when the two are equal. Of course, it
isn't a number since the point moves with the cost of the
project and market prices achieved, she said.
12:34:46 PM
CO-CHAIR FEIGE commented the charts don't identify intangible
benefits to the state in moving the project forward.
MS. PODUVAL agreed.
12:35:13 PM
REPRESENTATIVE TARR related her understanding that going beyond
35 percent is not being considered since it would further impact
producers negatively.
MS. PODUVAL answered that is correct.
REPRESENTATIVE TARR asked whether the consultant has considered
which portion of the project makes most sense for the state to
invest in and also develop expertise going forward to make the
state more competitive in the market.
MS. PODUVAL answered that pipeline ownership is one component of
the project, which is why state investment makes sense.
Certainly, the biggest reason would be that the pipeline could
create the most significant bottleneck in terms of access. The
LNG plant could also be expanded in trains - modular units that
can expand the LNG plant itself. Similarly, a similar approach
could be applied to the GTP, as well. She explained that the
pipeline - depending on how it is sized - can be expanded using
additional compression up to a certain level, but beyond that
any expansion can only be achieved by looping, which is
prohibitively expensive. Therefore, it represents a good
component for investment since the state would have control over
the pipeline structure and development.
12:37:17 PM
CO-CHAIR FEIGE noted that before gas can be removed from the
North Slope, the Alaska Oil and Gas Conservation Commission
(AOGCC) must render a decision on the allowable amount. He
asked whether the administration taken any steps in that regard
or if this is not a concern yet.
ACTING COMMISSIONER BALASH agreed that it will be a concern, but
the department has not taken any formal steps to date. He
acknowledged some informal conversations have occurred with
individual members of the AOGCC in terms of timing and
requirements. He offered his belief that the success case and
path will involve the support of all of the working interest
owners as well as the operator being in the lead. In fact, the
operator has an incredible body of technical data, reservoir
information that cannot be matched. Their participation and
engagement with the commission in a success case will be the
lead. Certainly, the administration can consider and examine
certain things. In fact, in the resolution of the Point Thomson
litigation, the state engaged with the working interest owners
in matters that specifically related to Point Thomson, but also
tangentially to Prudhoe Bay, he advised.
12:39:16 PM
CO-CHAIR FEIGE referred to space capacity in the pipeline. As
Ms. Poduval previously stated, the ability of the new entrants
to North Slope gas exploration scenarios will depend on the
ability to get the gas to market, plus spare capacity in the
line. He offered his belief producers have come up with a
project that the economics will work out to cover capital
expenses. However, spare capacity will be necessary to ensure
future access for exploration or access for future discoveries,
for example in the National Petroleum Reserve - Alaska (NPRA) or
on the North Slope - at White Hills. He further asked how much
spare capacity is needed to be built into any pipeline. The
state could build a line for existing capacity, but generally
speaking, the state needs to decide how much extra capacity will
be needed, the cost, and whether the state should fund it as
additional equity in the pipeline portion of the midstream
supply chain.
ACTING COMMISSIONER BALASH acknowledged these are excellent
questions, which are ones the department has already considered
internally. He suggested the committee could obtain some
information from some of the known companies, such as Anadarko
Petroleum Corporation, BG Group. He remarked that Shell
[Western E&P Inc.] could present a perplexing set of
considerations if the producers brought in natural gas from the
offshore since no royalty interests or direct production tax
implications. Likewise, how that would be reconciled within the
structures being considered would likely be important to them,
too. He surmised that in order to bear the costs of offshore
development, the producers would need a large volume of
hydrocarbons. Certainly, this raises some questions, which are
a little further off, he said. The questions that relate more
directly would be that some of the other companies or some newer
lessees, such as Repsol [S.A.] and ENI who certainly have a
presence in the LNG marketplace and have likely considered some
opportunities in Alaska.
12:43:29 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 12:43 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES 12.9.13 Agenda.pdf |
HRES 12/9/2013 10:00:00 AM |
|
| Black & Veatch Study Highlights .pdf |
HRES 12/9/2013 10:00:00 AM |