Legislature(2013 - 2014)BARNES 124
03/27/2014 04:30 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB138 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 138 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
SB 138-GAS PIPELINE; AGDC; OIL & GAS PROD. TAX
4:39:19 PM
CO-CHAIR FEIGE announced that the only order of business is CS
FOR SENATE BILL NO. 138(FIN) am, "An Act relating to the
purposes, powers, and duties of the Alaska Gasline Development
Corporation; relating to an in-state natural gas pipeline, an
Alaska liquefied natural gas project, and associated funds;
requiring state agencies and other entities to expedite reviews
and actions related to natural gas pipelines and projects;
relating to the authorities and duties of the commissioner of
natural resources relating to a North Slope natural gas project,
oil and gas and gas only leases, and royalty gas and other gas
received by the state including gas received as payment for the
production tax on gas; relating to the tax on oil and gas
production, on oil production, and on gas production; relating
to the duties of the commissioner of revenue relating to a North
Slope natural gas project and gas received as payment for tax;
relating to confidential information and public record status of
information provided to or in the custody of the Department of
Natural Resources and the Department of Revenue; relating to
apportionment factors of the Alaska Net Income Tax Act; amending
the definition of gross value at the 'point of production' for
gas for purposes of the oil and gas production tax; clarifying
that the exploration incentive credit, the oil or gas producer
education credit, and the film production tax credit may not be
taken against the gas production tax paid in gas; relating to
the oil or gas producer education credit; requesting the
governor to establish an interim advisory board to advise the
governor on municipal involvement in a North Slope natural gas
project; relating to the development of a plan by the Alaska
Energy Authority for developing infrastructure to deliver
affordable energy to areas of the state that will not have
direct access to a North Slope natural gas pipeline and a
recommendation of a funding source for energy infrastructure
development; establishing the Alaska affordable energy fund;
requiring the commissioner of revenue to develop a plan and
suggest legislation for municipalities, regional corporations,
and residents of the state to acquire ownership interests in a
North Slope natural gas pipeline project; making conforming
amendments; and providing for an effective date."
4:39:36 PM
ROGER MARKS, Petroleum Economist, Contract Consultant to
Legislative Budget and Audit Committee, provided a PowerPoint
presentation titled "Evaluation of SB 138 & Associated Proposed
North Slope Natural Gas Commercialization Proposals." He
offered a brief personal background, slide 2, reporting that he
has been in private consulting practice specializing in
petroleum economics and taxation in Anchorage since 2008. Prior
to that, he was as a senior petroleum economist with Department
of Revenue, Tax Division, monitoring the feasibility of
commercializing North Slope gas, and was a petroleum economist
with the U. S. Geological Survey. Currently, he is continually
assessing the feasibility of the North Slope gas project. As
consultant to the Legislative Budget and Audit Committee, he has
submitted a report to the committee similar to today's
presentation, which includes the latest "lay of the land."
MR. MARKS said the administration has put together a thoughtful
plan that could lead to a successful project, and he will be
offering some observations, questions, and options to be
considered. He introduced slide 3, "Outline," and discussed the
pieces of his presentation: introduction, high-level decisions,
role of Alaska Gasline Inducement Act (AGIA), and taxation
provisions of CSSB 138(FIN) am.
MR. MARKS offered slide 4, "1. Introduction: Market Challenges,"
saying he believes the proposed project is far from certain, and
three big challenges will be the competition, the pricing of
natural gas in Asia, and the burden of the size of the project.
He pointed out that about 24 countries in the world are either
exporting, or preparing to export, liquefied natural gas (LNG)
with an eye on the Asian market. Also, Iranian gas, which is
currently embargoed, is a potential competitor in the market.
He reported that 30 percent of the nuclear electricity supply in
Japan has been moved to gas after the nuclear plant disaster,
although the Japanese government has expressed interest in
moving back to nuclear power given the concern in Japan about
increasing greenhouse gas emissions. China, he continued, is a
"big wild card."
4:45:08 PM
MR. MARKS explained that most of the consensus forecast for Asia
between now and 2030 is for twice as much supply as demand in
Asia, so there is a lot of competition. He said the pricing of
LNG linked to oil is falling as Asian buyers realize that
producers are making a windfall profit, and there is now greater
competition. Although the average prices are still high, they
reflect old contracts which have been in place for a long time
under old provisions. Newer prices are much lower and because
new prices are going to be based on cost, Alaska will be at a
disadvantage. He reported that recent projections by Rice
University are for LNG in Asia to be about $10 per million
British Thermal Units (BTUs), which is "not that good." He
suggested that the cost estimates for the Alaska pipeline have
probably increased, and that other projects around the world do
not face the same challenges as an 800 mile pipeline through the
Arctic. A lot of gas must go through the pipeline to keep the
costs down, and this creates a marketing burden for capturing a
large incremental share of the Asian market in a short amount of
time. A partially empty pipeline has bad effects on the rate of
return. A full pipeline will capture about 30 percent of the
annual incremental Asian market, which is "a pretty ambitious
task." Alaska has a much higher break-even price than much of
the competition.
MR. MARKS discussed slide 5, "New LNG Projects are Expensive,"
by PFC Energy, which shows the break-even prices for gas
projects around the world as ranging from $8-$13 [per million
BTUs], whereas his estimate for Alaska is $11-$17.
4:49:19 PM
REPRESENTATIVE KAWASAKI, referencing slide 5, asked whether the
break-even rate is calculated on the size of the project.
MR. MARKS replied it is based on the current project cost range
of $45-$65 billion, and a range of hurdle rates between $8-$12
all based on the current tax proposal for the state taking its
gas in-kind.
REPRESENTATIVE KAWASAKI, referencing slide 4, asked about the
prices falling to about $6.
MR. MARKS replied Russia has sold LNG for as low as $6 to Korea.
CO-CHAIR SADDLER requested clarification regarding the high
range of break-even in Alaska.
MR. MARKS explained it depends on whether it is "$45 or $65" and
whether the hurdle rate is 8 percent or 12 percent; however, he
said, he does not know what hurdle rates were used by other
folks.
4:51:09 PM
MR. MARKS turned attention to slide 6, "Timing Landscape." He
said the State of Alaska needs the project as soon as possible,
and it has been received with a certain amount of "momentum"
according to the administration. He related the administration
is emphasizing the momentum with a present value of $800 million
for every year the project is delayed. He reflected on present
value and whether there is relevant context for the discussion.
Present value means the time value of money and its current
worth compared to that worth in the future. Moving to slide 7,
"How Present Value is Calculated," he referred to the chart
which depicts the nominal flow of $1 million annually with a
discount factor of 7 percent, and the loss of value for each
subsequent year, for a preset value in 2048 of $13,854,009. He
said the discount factors get lower and lower with each
subsequent year and nothing that happens after 10-15 years
matters very much, so he is unsure that this is the best way to
look at this project in terms of looking at its timing.
MR. MARKS returned attention to slide 6, noting the proposed gas
project is for the benefit of the next generations of Alaskans.
The concern Alaskans will have in 20 years will be about how
much gas revenue the state is receiving and its use in the homes
and businesses of Alaskans. He pointed to current gas billings
which include the price of the gas, the price of the pipeline,
and its capital terms. He suggested that better capital terms
could annually save Alaskans money: in 20 years Alaskans will
be less concerned whether the present value in 2014 was
maximized and more concerned with the gas revenue and its cost
to Alaskans. He suggested that an option for a modified deal
starting a little later could create more long-term benefits to
the state for higher revenues and lower priced gas to Alaskans.
He allowed that it is important to find cheaper heating fuel for
Fairbanks and rural Alaska, but that present value may not be
the way to look at this. He said there is not any short-term
window of opportunity, as the demand in Asia will continue to
grow. Some aspects could proceed while different arrangements
are made, some legislation could be passed to give producers
direction, and producers could begin the process without the
state; the process could continue even while the state reviews
some options that take time.
4:57:50 PM
MR. MARKS drew attention to slide 8, "2. High Level Decisions
under Proposal." He said that the three high level decisions
for the state are to take its production taxes and royalties in-
kind; not to regulate tariffs and expansions; and for
TransCanada, and perhaps the State of Alaska, to have
partnership for the pipeline and gas treatment plant (GTP) and
for Alaska to own the LNG facilities. He opined that the
administration has designed the project "to amicably transition
out of AGIA."
MR. MARKS, referencing slide 9, "A. In-Kind Gas," said there is
a very compelling reason for the state to take its taxes and
royalties in-kind, as this considerably helps the economics of
the project for the producers and sponsors. Moving to slide 10,
he explained that the producers would pay the state its taxes
and royalties in-value an amount of money equal to that
percentage of the gas. Under this system, the producers pay for
the capacity in the pipeline and slowly get it back over time
with the tariff deduction. Once the pipeline is constructed it
cannot be cancelled, he said, and this is the owner of the
pipeline's problem. Under the current proposal, when the state
takes its taxes as in-kind gas, the state takes on the long-term
firm transportation liability, as well as other risks. The
state will pay to ship the gas, no matter where, and this
includes the capital charges: depreciation, return on debt and
equity, and income taxes. The state will also incur a long-term
liability for the firm transportation capacity, and then this
liability becomes an asset to the owner of the pipeline, as it
is a 25 percent reduction in the capital cost of the pipeline
for the project sponsors. Mr. Marks said he calculates this 25
percent reduction to be worth about $1-$2 in reducing the break-
even price, and about 1-2 percent for increasing the rate of
return. The state does not need to own the pipeline to take the
gas in-kind, as it is much more important to the producers'
economics. He noted that, should the state take its gas in-
kind, it must market the gas; whereas under the current system
of receiving gas in-value, the state has the marketing support
of the producers. In-kind could create a competition between
the state and the producers for marketing of the gas. He
pointed out that the Heads of Agreement has an option for
negotiation of agreement to purchase and dispose of the state's
gas. He suggested that the proposed bill "beef that up." In
exchange for the state taking the gas in-kind, the producers
could agree to market the state's gas along with their gas for
the same price. He reported that the in-value system offers the
state a better opportunity to understand the market. He
reminded the committee that anything in statute has more clout
than any negotiations.
MR. MARKS turned to slide 11, "B. Regulation," saying that the
proposal under the Heads of Agreement is for the Federal Energy
Regulatory Commission (FERC) to regulate the pipeline under
Section 3 of the Natural Gas Act. This section is mainly
designed for licensing the siting, construction, expansion, and
operation of the LNG import and export terminals, which would
also include the pipeline and the treatment plant because it
includes facilities used to transport and process gas.
5:04:38 PM
CO-CHAIR SADDLER requested clarification in regard to the FERC
regulation regulating the entire pipeline.
MR. MARKS replied that the definition for terminals in Section 3
includes facilities to transport or process gas, which would
include the pipeline and the treatment plant.
CO-CHAIR SADDLER asked whether there are any other similar FERC-
regulated pipelines.
MR. MARKS answered that Oregon LNG had applied for an interstate
FERC permit to take gas out of Washington and export it out of
Oregon. He said he did not know of any active LNG terminals
under these parameters. He suggested it would be useful to
consult with FERC as this is a lynchpin to much of the plan. He
noted that the pipeline, the terminal, and the treatment plant
would not be a common or contract carrier, but would instead be
four separate industrial feed lines for the three companies from
the North Slope to Japan. Hence, there would not be any
regulation of tariff or expansion, although state ownership of
the pipeline would be necessary.
5:08:12 PM
MR. MARKS offered an example for the expansion of in-state
needs, slide 12, "Example." He posed a scenario in which the
pipeline has an initial disposition of 2.4 billion cubic feet
per day, with the state receiving 25 percent, or 0.6 billion
cubic feet per day. He suggested that a need for in-state gas
that is not being received could be considered with a provision
to the producers to include any necessary increase for in-state
gas. He discussed another regulatory issue for the producer gas
getting to the consumers. There is an issue for maintaining a
transparency for the netback price to the value of the gas on
the North Slope, which would be covered with regulation. He
suggested a provision in the statute which says that gas bought
by the state from the producers would be reasonably priced.
MR. MARKS referred back to regulations on slide 11, and offered
an alternative for the Regulatory Commission of Alaska (RCA) to
regulate in-state and export pipeline gas treatment under
AS 42.08. He recognized that regulation is burdensome to the
producers, but said it is the trade-off for a natural monopoly
with the pipeline right of way. The public gives away the right
of way in exchange for regulation. He said treatment plants and
LNG facilities are not regulated in the same way, as there could
be multiple facilities. He suggested that market efficiencies
could be enhanced with a transparent pipeline cost. He said a
very efficient market system is currently in place to deal with
oil sales on the North Slope, as most of the small producers
sell their oil to the producers that own the pipeline. The
Trans-Alaska Pipeline System (TAPS) tariff is available to
determine a reasonable wellhead price. In this situation, if a
small producer finds gas, but does not want to build an LNG
facility, it could make sense to sell to the producers,
especially as the throughput starts to decline. It would be
necessary to have transparency to avoid any monopoly controls.
MR. MARKS moved to slide 13, "Ownership and Partnership,"
pointing out that the state would own a part of the facilities
commensurate with its share of the gas, currently about 25
percent. It is proposed for TransCanada to own the treatment
plant, with the state having an option to purchase 40 percent of
this. The state ownership allows for no regulation on tariffs
and expansion, and there would be lower tariffs through lower
cost of capital. He offered two reasons for the state's need of
partnership: help with cash flow and expertise. He suggested
the state does not need a partner for expertise because the
producers would be guiding the project and the Alaska Gasline
Development Corporation (AGDC) could offer expertise as it would
own 100 percent of the state's share and could hire technical
expertise. He pointed to the earlier stand-alone pipeline,
which had been planned to move forward without partners.
5:17:28 PM
CO-CHAIR SADDLER asked whether the state money paid to
TransCanada was to develop expertise or necessary information.
MR. MARKS clarified the state has paid $400 million to AGDC.
MR. MARKS questioned TransCanada's expertise for gas treatment,
and suggested asking them. He noted that in the original AGIA
agreement, TransCanada had declined to do gas treatment,
although the state had encouraged TransCanada to hire an expert.
REPRESENTATIVE HAWKER, regarding TransCanada and the sequence of
transactions as proposed to the legislature, inquired whether
Mr. Marks is talking about upstream gas treatment or the LNG.
MR. MARKS replied the upstream gas treatment.
5:19:11 PM
MR. MARKS continued his discussion of slide 13, noting the state
does not need a partner for expertise, but may need a cash
partner. Thus, he said, the state does not necessarily need a
pipeline company for a partnership, but rather a general
investment partner, of which there is no shortage as far as
large investment banks or private equity firms that could serve
that function.
MR. MARKS moved to slide 14 to address the question of whether
the state needs a cash partner. He suggested "possibly not."
When AGDC was preparing its financing plan in 2011, it hired
Citigroup, the third largest commercial bank in the U.S., to
advise them. Citigroup discussed the possibility of 100 percent
debt financing through a combination of revenue bonds and state
backing. He offered his belief that the currently proposed
[Alaska LNG Project] is less risky than AGDC's $8 billion stand-
alone bullet project that is without a partner. He pointed out
that the three large oil producers are participating in the
[Alaska LNG Project] and there are much larger gas revenues
involved than in the stand-alone line. He said 100 percent debt
financing would offer the possibility for deferral of most cash
flow until gas starts flowing, given that the payment of
interest during construction is something that is negotiable.
This could have a short-term impact on the state's credit rating
during the five-year construction period, but that would be
reversed once gas revenue starts coming in.
5:21:54 PM
MR. MARKS returned to slide 10 to continue discussing the issue
of whether the state needs a cash partner and the issue of
limits on the state debt capacity. He reiterated that under the
[Alaska LNG Project] proposal "when the state takes its taxes
and royalties as in-kind gas, the state will take on a long-term
firm transportation liability to TransCanada for the state's
share of the pipeline and gas treatment plant." Moving to slide
15, he said "it has been suggested that there are limits on how
much the state can finance to own the whole 25 percent because
of limits on its debt capacity." Continuing, he said "if the
state is taking its taxes and royalties in-kind, for any part of
the project the state does not own it will have to make a firm
transportation commitment on that capacity, and this commitment
is a long-term liability, it is a debt." He detailed that the
firm transportation commitment is ship or pay, so no matter what
the cost of the line, or what happens to the market or reserves,
the state "is on the hook for the ship or pay commitment."
These firm transportation commitments are used by the pipeline
company as collateral for financing, and the pipeline company
has priority claims on the project cash flows. He pointed out
that this debt will have no different impact on the state debt
capacity than debt used to finance ownership. So, put
succinctly, there are two ways to borrow money with identical
obligations to repay and therefore the same loss of debt
capacity: the traditional note for cash or signing an agreement
whereby the cash is given to the creditor. Debt is debt, and it
cannot be avoided by having someone else assume it on the
state's behalf. He said he does not know what the limit is on
the state's debt capacity, but if it is similar to what has been
described as why the state cannot do ownership on its own, this
would also preclude the state from taking its taxes and
royalties in-kind.
5:24:13 PM
MR. MARKS, in response to Representative Seaton, explained that
in previous testimony the administration provided three reasons
for why the state needs a partner: for expertise; for cash
because of the state's cash flow; and because, if the state
wants to own 25 percent of the pipeline under any kind of
debt/equity ratio, the state cannot afford it above a certainty
point because there is a limit on the state's debt capacity.
CO-CHAIR FEIGE inquired whether Mr. Marks is referring to
testimony before the committee by Commissioner Rodell [of the
Department of Revenue (DOR)]. He recalled Commissioner Rodell
testifying it was not necessarily a firm ceiling, but the state
is somewhat limited by a rule of thumb to keep the debt service
down to 8 percent or less of the operating budget.
MR. MARKS confirmed this is what he is referring to.
MR. MARKS, continuing his response to Representative Seaton,
related the administration made the representation that, because
of this limit on the state's debt ceiling, the state needs a
partner. He pointed out that a firm transportation commitment
to TransCanada is an equal amount of debt as owning the whole
line and, given that debt is debt, it will have the exact same
impact as a debt limit. It would also mean the state cannot
take the gas in-kind because the liability incurred would be
exactly the same as the state owning 25 percent of the pipeline.
He recalled his and former [DOR] Commissioner Wilson Condon's
conversations several years ago with Moody's Investors Service
in which Moody's said there is no question that the firm
transportation commitment is debt with the same effect on debt
capacity as any other debt.
5:27:09 PM
MR. MARKS, in response to Co-Chair Saddler, confirmed he is
saying that firm transportation commitment is the same thing as
debt and is accounted as such by credit rating agencies. To
explain further he presented a scenario where the state did not
have a partner and financed 100 percent debt for a 25 percent
ownership. He referred to the earlier testimony that this much
debt exceeded creditors comfort in terms of the state's credit
rating. He offered a second scenario with state ownership of 10
percent and TransCanada ownership of 15 percent of the same
proposed project. He relayed that a state firm transportation
commitment to TransCanada for the 15 percent would carry the
same amount of debt as ownership for the entire 25 percent.
MR. MARKS, in response to Representative Seaton, confirmed that
should the state take the royalty and tax in-kind, the long-term
shipping commitment would be considered a debt for the amount of
gas taken in-kind, as it would have to be shipped.
5:29:48 PM
MR. MARKS returned attention to slide 14, noting the possibility
for tax exempt bonds through the Alaska Railroad Corporation.
He said legislation in 1983 had given the Alaska Railroad
Corporation the ability to incur tax exempt debt for industrial
development projects, and it has been suggested that this
privilege could be used to finance the gas pipeline. Goldman
Sachs, Merrill Lynch, and U.S. Senator Ted Stevens had believed
that this was the case. He explained it requires a private
letter ruling from the IRS, and necessitates legal arguments.
Doing that could cost about $100,000 and, while no one has done
it, the benefits would include tax exempt debt which is about 25
percent lower than taxable debt.
CO-CHAIR SADDLER asked whether there is any required nexus
between the Alaska Railroad Corporation industrial bonding
capacity and the natural gas pipeline, and whether there are any
limits to this lending capacity.
MR. MARKS offered his belief that there are no limits to this
lending capacity and that there is no need for any nexus. He
suggested a possible need for railroad expansion in order to
facilitate the pipeline, which would then also allow non-
railroad expenditures. He said "you don't know if you don't
ask," and cited the Citigroup concurrence of the possibility.
5:33:02 PM
REPRESENTATIVE SEATON asked whether there was Citigroup analysis
on tax exempt for 100 percent debt of the AGDC stand-alone
pipeline.
MR. MARKS replied that Citigroup had looked at 100 percent debt
through a combination of revenue bonds and general obligation
debt. In addition to this, some or all of that debt could be
tax exempt through the Alaska Railroad Corporation, and,
although it was not specifically mentioned in the financing
plan, it was not mutually exclusive and all could be applied.
CO-CHAIR FEIGE asked whether it is possible for AGDC to issue
the bonds, as it is a public corporation.
MR. MARKS offered his belief that the authority was given to
AGDC in HB 4, although he is not well versed on it. He said
there would be no need for a cash partner because 100 percent
debt financing and tax exempt bonds would require little or no
cash before gas starts flowing. The state's credit rating and
tax exempt debt could offer a lower cost of capital with lower
tariffs. He suggested a discussion with Citigroup for further
information.
5:35:17 PM
MR. MARKS addressed slide 16, "Ownership: Risk of Failure to
Sanction," explaining that this is the other concern associated
with ownership. He noted that sponsors could spend $2 billion
to get to the financial investment decision (FID) point only to
have the project not materialize. He pointed out that, under
this proposal, the state would be liable for about 25 percent,
$500-$600 million regardless of whether it exercises its
ownership option with TransCanada. Although the project could
be stopped if it did not appear to be working out, more than $2
billion could be spent trying to narrow the cost uncertainties.
He related that similar projects had cost estimates of plus or
minus 10 percent when the sanction point was reached, so it is
necessary to spend 3-5 percent of the total project cost, hence
the $2 billion cost. He reported that it is necessary to know
the costs before being able to develop the detailed gas
marketing plan. He advised that other projects in Asia could
step in front or prices could crash, so this money could be
spent for naught. He said it is an issue for whether the state
should take on this risk or whether the producers are better
equipped to handle that risk. He suggested that the producers,
through diversification, could be better equipped as they are
reviewing other international projects; whereas the state only
has this project. He said this project is competing against the
producers' other oil projects, so it is not a level playing
field. The producers can make active decisions, whereas the
state is the passive recipient of those decisions. He pointed
out that the three North Slope producers have a market cap of
almost $750 billion. He questioned whether this money would
make a material difference to the viability of the project. He
suggested that there is a tipping point, but it is difficult to
know it. The greater the interest by the producers, he opined,
the less they need the state money. He suggested a balance of
four things: how near the state is to the tipping point; the
probability of the project; the size of the prize; and how
material it would be for the state to lose $600 million. He
proposed as an alternative to offer an arrangement for the state
to buy into the project once it is sanctioned, and repay to the
producers the feasibility costs with interest, which would allow
the state more time to determine how it wants to proceed.
5:39:58 PM
MR. MARKS, in response to Co-Chair Saddler, explained material
difference defines how bad it would be for the state to walk
away from the project at FID. It is necessary to keep an eye on
the prize and decide if it is worth the risk.
REPRESENTATIVE SEATON asked whether "sanctioned" is a term
typically used in projects which are being analyzed.
MR. MARKS replied that it is not used explicitly, but often
implicitly when governments take on a share of the development
costs. He said most other places with oil first perform
feasibility studies and then develop. He allowed it is not
unusual for producers to take an ownership share and that
feasibility studies are not always shared.
5:42:18 PM
MR. MARKS addressed slide 17, "3. Role of AGIA in Proposal,"
saying public comments made by the administration when the
project was first introduced included: an aggressive time frame
to get the gas to market; a desire to avoid a potential lengthy
and costly legal fight over ending the AGIA license; and a
proposal designed to end the AGIA license amicably. He pointed
to the agreement for treble damages the state would be liable to
pay to TransCanada should the state give any preferential tax
treatment or grant of money to any competing project. He raised
the questions of how much expert partnership the state needs and
how much cash partnership the state needs. He opined that the
proposed plan has been developed to give TransCanada a material
role to avoid potential AGIA liabilities. He said the questions
should be asked as to whether better terms could be available if
the state was not so constrained by AGIA and whether these terms
could be renegotiated with TransCanada.
5:44:15 PM
MR. MARKS introduced slide 18, "Areas Where State Could Possibly
Have Better Terms If It Had No Partner or a Different Partner."
He said if the state was not compelled to have a partner for the
60-100 percent of the gas treatment plant and the pipeline, and
had the opportunity to own 100 percent of the 25 percent, and
could get good terms with tax exempt debt, with a lower cost of
capital, then the state would receive higher gas revenues and a
lower cost of gas to consumers. The 60 percent difference of
ownership with lower cost of capital would save consumers
several hundred dollars a year for the cost of gas. He said
there is also a misalignment of interests between shippers and
non-shipper partners. He pointed to cost overruns and expensive
expansions as some of the biggest costs to the program,
therefore a non-shipper partner would make money on these cost
overruns, whereas the state would lose money. He said that non-
shippers are not motivated to keep costs down and motivation is
important. A different partnership for the state, he opined, or
renegotiation of the Memorandum of Understanding (MOU) with
TransCanada, could offer more preferable terms to the proposal.
He suggested it would have been better for the state to share
the failure to sanction risk, whereas under the MOU termination
rights, if the project does not sanction, the state must repay
TransCanada everything it has spent since January 1, 2014. This
could cost the state up to $270 million, regardless of whether
the state exercised its ownership option. He maintained that
TransCanada's placement of all the risk for a failed project
back on the state translates to a lack of partnership during
this period. He said there are instances in which pipeline
companies have assumed development costs and incurred the risk
of development expenses that did not result in a project. He
offered an example of open season with precedent conditions that
were not met, and said this is a risk of doing business as a
pipeline. He argued that this non-assumption of risk should
result in a lower cost of capital and suggested that a different
partner might assume more of the risk. He said another term
that could be improved in the current proposal is to share in
the benefit of lower interest rates. Currently, TransCanada's
proposed cost of debt is 5 percent plus whatever happens to 20-
year treasury bills between now and FID. So, for example, if
treasury bills increase 3 percent between now and FID, that will
lock into an 8 percent cost of debt; whereas, if interest rates
go down, there are often callable features on corporate bonds
that would allow TransCanada to refinance a lower interest rate,
while the state would still be paying 8 percent.
5:49:27 PM
MR. MARKS moved to slide 19, "Role of Financing Terms in
Tariffs," explaining that much of the cost in a tariff is the
financing cost, similar to interest payments on a home mortgage
that result in a total payment of three times the price of the
house. He pointed to the weighted cost of capital, which is the
percent debt times cost of debt, plus percentage equity times
cost of equity. Equity costs more than debt because it is more
risky given that creditors have access to debt before equity
gets paid. Another reason more equity creates a higher tariff
is that return on equity is taxable income that is passed off
into the tariff. These provisions effect on each other: the
more debt accrued, the riskier the other debt becomes which, in
turn, increases the cost of debt, making the equity more risky
and increasing the cost of equity. He stated that, in general,
it is optimal to have less equity, resulting in a lower cost of
debt and equity, and lower tariffs. The cost of capital terms
can have a wide effect on the tariff, similar to a mortgage.
Responding to Co-Chair Feige, he confirmed this is what is
commonly referred to as the weighted average cost of capital.
Continuing, Mr. Marks noted that these financing terms determine
the tariff, the gas revenues, and the price of gas to consumers,
because the costs of the pipeline and the interest are passed on
to the consumer. TransCanada has proposed a tariff term of 5
percent debt, 12 percent equity, 75/30 debt/equity, which, he
pointed out is probably better than what the producers could
offer and is better than what most FERC regulated lines in the
Lower 48 would offer. He reported that the TAPS tariff is 12
percent/5 percent with 50/50 debt/equity. He stated that FERC
offers much higher returns on equity than does the Canadian
National Energy Board as different formulas are used. He said
the TransCanada proposal is similar to that of many other
Canadian pipelines, and he offered some examples. However, he
continued, with the option of 100 percent tax exempt debt, it is
plausible that the capital provisions could be lower than the
TransCanada proposal.
5:53:40 PM
MR. MARKS reviewed slide 20, "Are Better Cost of Capital Terms
Possible." He said that terms on existing pipelines may not be
relevant because if the state only needs a partner for cash then
what it needs is a co-investor rather than a pipeline company.
A co-investor that is an investment bank or private equity firm
could have much lower capital requirements than a regulated
pipeline. Additionally, the other 75 percent of the pipeline is
being built be well financed, well capitalized, experienced,
major international oil corporations, which could plausibly make
the project less risky and induce a bidder for lower returns.
He said bidders could offer a trade-off and be willing to absorb
some of the failure-to-sanction risk in exchange for a higher
rate of return.
MR. MARKS offered suggestions for possible re-negotiation of
terms with TransCanada or a different partner. He discussed a
higher ownership share than the 40 percent of the 25 percent for
the gas treatment plant and pipeline currently offered to the
state by TransCanada. He said lower cost of capital terms could
also lower tariffs. He referenced some specific provisions of
the MOU, including the right to exercise the ownership option.
He cautioned that the Pre-Front-End Engineering and Design (Pre-
FEED) might not be over by the date for the ownership option, so
the state would have to make the decision with incomplete
information. He expressed his lack of understanding for the
provision in the termination clause that requires the state to
enter into a firm transportation agreement by December 31, 2015,
or TransCanada has the right to terminate, suggesting that the
administration and TransCanada should be questioned regarding
this clause.
5:56:53 PM
MR. MARKS introduced slide 21, "How Bound is State by AGIA." He
said that if the state was to proceed without TransCanada, and
modify taxes and take full ownership of the full 25 percent or
maybe get a different partner, the state would incur a risk of
legal and financial exposure through the license project
assurance clause, also known as the triple damages clause. He
read the clause from AS 43.90.440: "If ... the state extends to
another person preferential royalty or tax treatment or grant of
state money for the purpose of facilitating the construction of
a competing natural gas pipeline project in this state ... the
licensee is entitled to payment from the state of an amount
equal to three times the total amount of the expenditures
incurred and paid by the licensee ..." He explained this was
included in the AGIA agreement so the licensee had the exclusive
enjoyment of the $500 million reimbursement inducement, and
would not incur the expenses if the state offered a similar
proposal to another group. He pointed out three ambiguities in
this: the meanings of "preferential", "grant of state money",
and "total amount". Addressing "total amount", he noted
TransCanada has been reimbursed about $350 million of the $550
million it has spent. What is ambiguous is whether "total
amount" means gross or net. If it means gross, the state would
owe TransCanada three times $550 million, about $1.65 billion;
if it means net, the state would owe $600 million. The problem
is that no one knows exactly what the state's exposure is.
Addressing "preferential", he explained that when AGIA was
rolled out in 2007 or 2008, the administration and Legislative
Legal and Research Services said the intent was not to preclude
laws of general applicability. Included in CSSB 138(FIN) am, is
something that could apply to a North American pipeline, or to a
gas-to-liquids (GTL) project, or to ice-breaking LNG tankers
going out of Prudhoe, or to any LNG project; so it is plausible
that what is going on in SB 138 would not constitute
preferential tax treatment. Most ambiguous, he continued, is
the term "grant of state money" because it was not widely
addressed during the legislative hearings on AGIA. He related
that when asked what "grant of state money" means, the
administration said "the outright unfettered financial grant".
He questioned what that means and whether it could mean a
donation. Arguably, an appropriation to buy equity and pay for
an asset may not be a grant, he continued, but on the other hand
possibly any appropriation could be considered a grant for
financial support for a competing project.
6:00:44 PM
MR. MARKS directed attention to slide 22, "Options" to address
the question of where the aforementioned leaves the state for
dealing with the AGIA constraints and potentially preferable
options, He said one option is to assess what the state's legal
exposure is and consideration could be given to outsourcing
legal expertise for assessing the exposure. Another option is
to engage TransCanada and ask what it would do if Alaska
proceeded without it. A third option is to renegotiate some of
these terms to be similar to those that could be received from a
competitor. The ambiguities to the state are also ambiguous to
TransCanada. Another option is settlement, he said. To keep
TransCanada whole, the state would really only have to pay
single damages on net, which would be less than $200 million.
The least preferable option, he continued, is litigation because
it takes time with an uncertain outcome. Some things could
still proceed, and maybe the state would win, but even if it
loses it potentially could have a better long-term outcome.
6:02:16 PM
MR. MARKS turned to slide 23, "4. Taxation: Production Tax," to
discuss the state taking its taxes in-kind as proposed. He
believed this makes sense because it provides economic benefit
for the producers and creates alignment between the state and
the producers. He pointed out that for in-kind taxes, it is
sensible to assess this on gross at the point of production.
Regarding an appropriate tax rate is, he offered his belief that
fair share is what can be gotten in a competitive environment,
which is jurisdictions with a similar risk and reward structure.
MR. MARKS directed attention to slide 24, "Government Take - LNG
Projects," an assessment produced by Daniel Johnston in the
Black & Veatch report. He pointed out the wide variation in
take among the projects, and offered his belief that similar
jurisdictions are a matter of judgment. He said Alaska is a
high cost, high risk region, with a government take around 60
percent. He pointed to the U.S. outer continental shelf (OCS)
project, which has a 61 percent government take, advising that
the project with TransCanada should not have a higher take than
the U.S. OCS project. He estimated the state take should be
between 57 and 59 percent, and he believed the enalytica
estimate was between 60 and 62 percent. Using 58 percent as the
state take, he said the federal government would receive 23
percent, the state 35 percent, and the producers the remaining
42 percent. Splitting that 42 percent three ways among the
producers, each would receive a 14 percent share, so the state
would be receiving 2.5 times more economic rent than any
producer. He said he therefore agrees with the definition of
fair share that is in CSSB 138(FIN) am.
6:05:19 PM
MR. MARKS moved to slide 25, "Property Tax," offering his belief
that property tax based on value is regressive because the
higher the cost, the higher the tax, which adds to the economic
risk for a project. An increase in project cost due to cost
overruns increases the property tax as well. He pointed out
that a property tax of 20 mills on a $50 billion project results
in a property tax of $1 billion. The highest assessed property
tax for TAPS was 1/5 of this, $200 million, and was for oil,
which is a higher valued substance. He pointed to a plethora of
litigation over the valuation of tax, which has to do with
appraisal for valuation which does not usually work well for a
unique asset. He said appraisal for valuation works well for
houses in a community, but not with an asset that does not have
any similar comparisons. He allowed that social impacts to
local municipalities will occur during construction of the
pipeline, but questioned whether impacts are directly related to
value. He noted that a clause in the Heads of Agreement (HOA)
suggests the property tax be based on cents per thousand cubic
feet (MCF) plus impact payments, instead of based on value,
which he said makes sense in terms of reducing the economic risk
of the project.
MR. MARKS concluded his presentation with slide 26, "Fiscal
Stability," noting that for the past 20 years the producers have
expressed the need continually for fiscal stability. Given the
state's history over the past 25 years, he concurred that fiscal
stability is important. He offered his belief that SB 138 is
not stable, although taking gas in-kind stabilizes things
somewhat. He said a future legislature could introduce
additional assessments, and suggested there be discussion with
the producers as to what would constitute adequate stability.
He directed attention to the HOA, Section 9.3.2, which discusses
the development of other terms to make contract terms
predictable and durable.
6:09:17 PM
CO-CHAIR SADDLER recalled the earlier statement of Mr. Marks in
support of the need for delay. Co-Chair Saddler posited that
falling gas prices and supply growing faster than demand instead
supports moving the project faster rather than slower to take
advantage of the fall of commodity prices and construction
expenses rising.
MR. MARKS replied competition is what the competition is, and
the fastest that the project could reach market is 2024, a very
ambitious goal. He said the market will continue to grow.
There is no short-term window of opportunity and, arguably,
prices could go up over time. The project will be a challenge
no matter when it is started.
CO-CHAIR SADDLER requested clarification regarding the
suggestion by Mr. Marks to wait and address more issues.
MR. MARKS offered his belief that waiting does not make the
project more or less competitive or make it more or less viable,
and working out some things could generate long-term benefits to
the state.
6:11:28 PM
REPRESENTATIVE KAWASAKI maintained that the MOU, the HOA, and
the bill put the state in the position of caboose, rather than
the driver of the train. Although intent language has been
added to the proposed bill, it does not have the full effect of
law. He requested clarification from Mr. Marks, as the
consultant for Legislative Budget and Audit Committee, regarding
whether the proposed bill should be passed or should some of the
questions be answered before moving forward.
MR. MARKS replied his role is to offer observations, questions
to ask, and options to help in the decision making, but whether
to pursue these is up to the committee. He said the HOA and the
MOU are not contracts, but are long-term policy statements by
the parties setting out guidelines for direction. There is no
commitment for action in either of these, and they are not
legally immutable. He said he has offered some options to
consider putting into statute, as anything in statute offers
more bargaining power and strength than negotiation.
6:14:11 PM
REPRESENTATIVE KAWASAKI offered his belief that the expansion
provisions discussed earlier for lining up the relationship
needed to be added to the proposed bill. He reflected on the
suggestions for failed partnership and better cost capturing
terms and asked whether these should be put in statute for a
stronger bargaining position.
MR. MARKS agreed there is that option if this is judged to be in
the state's best interest. He reiterated that anything in
statute does not have to be negotiated and would lead to better
terms. He suggested listening to the producers and TransCanada,
and engaging them for these options and any resulting problems.
CO-CHAIR FEIGE pointed out that a stipulation in the HOA and the
MOU is that any enabling legislation that is not accepted will
allow the agreements to be terminated.
CO-CHAIR SADDLER reflected that the main message from Mr. Marks
is that there are many ways this deal could have been
structured. He inquired whether Mr. Marks has a recommended
structure or whether Mr. Marks sees his role as poking and
asking questions.
MR. MARKS replied he has posed many questions which legislators
should ask and the answers to these questions will determine the
direction to proceed. For instance, can the state finance this
project with 100 percent debt? Can the state get taxes and
financing? What is the state's legal exposure from AGIA? He
said members have the option to ask those questions and then to
proceed from there. At this point, there are a lot of unknowns
that, if known, could offer direction, eliminate options, and
highlight where legislators might want to go.
6:17:40 PM
REPRESENTATIVE SEATON drew attention to slide 5, recalling the
8-12 percent hurdle rate mentioned by Mr. Marks. He asked what
the hurdle rate would be for the project as current proposed.
MR. MARKS replied that is a difficult question because [the
hurdle rate] is a closely guarded secret. He noted that 8-12
percent is based on his experience, although it is dynamic and
affects risk. He noted a discount rate, or hurdle rate,
reflects the weighted average cost of capital, which is the cost
to repay people for the use of money. A lower priced project
might be subject to a lower discount rate, as there is not as
much risk of the price going down. He allowed that the analyses
across the spectrum of prices and discount rates offer a very
complicated dynamic.
6:20:20 PM
REPRESENTATIVE SEATON understood that the hurdle rate is also
the weighted cost of capital. He inquired whether this would be
added to the cost and would reflect the project break-even point
of $16-$17.
MR. MARKS agreed the cost and the hurdle rate determine the
break-even price.
REPRESENTATIVE SEATON requested clarification that the hurdle
rate is not for estimated internal rates of return by the oil
and gas companies, but only for the project capital cost.
MR. MARKS responded the hurdle rate is the necessary rate of
return for the project to be viable and generating enough money
to repay the shareholders and creditors. A weighted average
cost of capital of 10 percent necessitates a rate of return
greater than 10 percent, and that is the hurdle rate.
6:22:48 PM
CO-CHAIR FEIGE, reflecting on the AGIA process, asked why
TransCanada is "the only real solid company that bid under that
AGIA process."
MR. MARKS replied there are two questions: why no one else bid
and why did TransCanada bid. He offered his belief that AGIA
had some commercial problems, as it was really designed for a
third party pipeline ownership with its provisions for rolled-in
rates, which created big problems for the producers. He related
that the Palin Administration preferred a third-party owned
pipeline over a producer-owned pipeline, whereas the producers
were clear that this did not work for them, and it was obvious
to many observers throughout the world that the producers would
not offer a serious bid during the open season. It did not make
sense for companies to offer an AGIA bid, as the project would
not work without the producers that wanted to build the
pipeline. Some of AGIA's terms did not make commercial sense;
it was still necessary for a FERC certificate even with a failed
open season, and this had never been done prior. There was no
big incentive to spend to get to open season, so what was put
out was not developed. Everyone knew this, he said. Besides
TransCanada, there were four other bids, two from companies with
virtually no assets, and two non-conforming bids. He opined
there were three reasons for the TransCanada bid: TransCanada
had purchased Foothills Pipe Lines Ltd. and since the pipeline
would proceed through Canada, TransCanada was familiar with the
territory; the TransCanada pipes were running empty and would
benefit from Alaska gas; and TransCanada had strategically
figured its benefit from the treble damages clause.
6:27:39 PM
CO-CHAIR SADDLER asked whether the provision in the HOA for the
producers to market Alaska gas alongside their own gas is
sufficient to overcome concerns.
MR. MARKS replied the HOA states that the producers are willing
to negotiate an agreement to purchase and dispose of oil. Under
the current in-value system, the producers sell oil and the
state gets a cut of that, and he suggested "this could possibly
be beefed up, possibly in the statute."
CO-CHAIR SADDLER asked whether Mr. Marks recommends that the
state should negotiate for a better deal.
MR. MARKS expressed his agreement.
REPRESENTATIVE KAWASAKI requested a comparison of this project
to the Stranded Gas Development Act (SGDA).
MR. MARKS responded the proposed SGDA was not a perfect deal; it
"was the governor's call and he was elected to make those
calls." Reflecting on which is the better deal, he said the
proposed economic return of 25 percent for this project is
better, which trumps any other possible downside issues for
having a partner.
REPRESENTATIVE KAWASAKI requested a comparison to the risks
under this proposal versus SGDA.
MR. MARKS offered his recollection that the 20 percent ownership
of SGDA would also incur 20 percent of the development costs.
The SGDA was a much lower cost project so there was a lower
percentage of a lower cost.
REPRESENTATIVE KAWASAKI referenced the off-ramps [in the MOU]
and the ability to re-view some of the issues. He questioned
the domino effect of changes to the proposed bill. He requested
a reiteration of earlier comments on the termination clause.
MR. MARKS answered the termination clause allows TransCanada to
terminate if the point of FID is reached and there is not a
project. The state would owe TransCanada for all expenses since
January 1, 2014, regardless of whether the state had exercised
its ownership option. He pointed out that this option could be
exercised prior to Pre-FEED.
REPRESENTATIVE KAWASAKI asked whether these are adequate off-
ramps.
MR. MARKS replied that, in terms of the commercial relationship
with TransCanada, if the project moves forward as written in the
MOU from Pre-FEED to FEED the state would owe TransCanada about
$270 million if the project does not happen.
6:34:23 PM
CO-CHAIR SADDLER, referencing slide 13, asked about the state's
need for a cash partner instead of an expert partner. Recalling
Mr. Marks's statement that the state could, instead of a
partnership, use debt equity or Alaska Railroad Corporation
bonds, he asked for a better definition of a general investment
partner, what return should be expected, and what debt/equity
ratios a partner would accept.
MR. MARKS responded that if the state needs a partnership for
cash and not expertise, then the partner does not need to be a
pipeline company. The need for a co-investor for cash would
allow a competitive bid to find out the return necessary to an
investor. He speculated that a cash investor may ask for less
than a regulated pipeline company, although it is unknown until
asked.
REPRESENTATIVE SEATON, regarding return on investment for a
regulated pipeline company, inquired whether this is a return on
equity or a combination of debt and equity. He suggested that
none of these could compete with the Alaska Railroad Corporation
tax-exempt bond structure, if that is a possibility.
MR. MARKS offered his belief that this is correct, citing the
aforementioned Citigroup opinion for tax-exempt debt.
6:37:46 PM
CO-CHAIR FEIGE directed attention to slide 11, and asked about
the enhanced market efficiencies with a transparent pipeline
cost. He opined there would be transparency as an owner, no
matter what the option.
MR. MARKS replied he was referencing the market efficiencies for
small gas producers that may want to sell gas, but do not want
to ship or liquefy gas. He said he envisions this process under
Section 3, noting that the use of "confidential" is everywhere.
He questioned whether the public would ever know the cost of the
pipeline, and therefore, a third party will not know what a
reasonable discount is for selling its gas.
CO-CHAIR FEIGE requested clarification to that scenario.
MR. MARKS explained that this hypothetical situation envisions a
decline in gas production, allowing space in the pipeline. When
the oil companies buy gas from the small producers, the small
producers make a profit because they have no oil spill risks;
for example, many small producers have stopped shipping oil
after the incident with the Exxon Valdez. Instead, they sell on
the North Slope, and this efficiency makes money for everyone.
He said there would be a similar hypothetical situation with
gas. Transparency in these costs facilitates efficient markets.
CO-CHAIR FEIGE requested clarification in regard to the
expansion capabilities negotiated into the MOU and the HOA being
insufficient. He suggested there would be a cost associated
with expansion in capacity of the pipeline and it seems fair
that those costs be borne by someone. Per the agreement, this
cost would not be borne by one of the original partners. He
expressed his understanding that the design allows for a
significant expansion of throughput, however someone should pay
for this addition.
MR. MARKS expressed his agreement, but said he was assessing a
situation whereby expansion was not necessary as there was a bit
of excess capacity available in the pipeline. In this
situation, a small producer would sell to a large producer.
6:45:14 PM
CO-CHAIR FEIGE reflected on discussions regarding AGIA and SGDA,
and noted that neither had succeeded in a pipeline to monetize
North Slope gas. He asked whether the proposed bill has
addressed the flaws in these prior pieces of legislation.
MR. MARKS replied it was not the previous legislations that
stopped the proposed projects; it was the market because the
market drives everything for a project. Hopefully there is now
a market.
CO-CHAIR SADDLER requested Mr. Marks' opinion on the pro-
expansion alignment and whether it would benefit the state.
MR. MARKS replied that with an absence of regulation no one is
compelled to expand. Under a FERC or RCA regulated pipeline, if
the expansion is large enough to make economic sense, then it is
mandated by the regulators. He directed attention to Section 3
of the Natural Gas Act, which states that no one is compelled to
expand. He offered his belief that ownership of the pipeline by
the state would ensure reasonable expansion provisions, if
necessary, as the state could be the expansion source of last
resort. He maintained this will work if the state pursues
reasonable terms and not high rates of return.
CO-CHAIR SADDLER stated there are advantages for the consumers
to have a regulated pipeline, and asked whether the contractual
arrangements are intrinsically worse.
MR. MARKS said he envisions consumers receiving gas based on the
state's capacity, as the state will be well motivated to put
reasonable terms on what it charges its citizens.
6:48:57 PM
REPRESENTATIVE SEATON, regarding expansion and non-transparency,
surmised the problem is that no one would be able to figure out
the wellhead value, so no one would know what a reasonable price
of gas is at the wellhead.
MR. MARKS confirmed that is the problem.
REPRESENTATIVE SEATON noted the terms state that any party can
expand but no one has to expand. A party choosing not to expand
has no liability for cost. However, he noted, if the increased
volume lowers the cost, even those who chose not to expand will
benefit from the lower cost. Each party's costs are different
and not known. He asked whether it makes sense for the non-
participants in the expansion to share in the benefits but not
the liabilities.
MR. MARKS replied pipelines live and die by economies of scale;
the bigger the pipeline, the lower the per-unit cost. Expansion
usually lowers the per-unit cost. He explained that expansion
benefits from the base capacity, so it makes sense for the base
capacity to benefit if the expansion lowers the cost for
everyone.
REPRESENTATIVE SEATON noted that AGIA has the same arrangement,
but if the expansion costs more there is a liability up to 15
percent above the current rate; if it costs less, then all share
in the benefits. He pointed out that there was not any sharing
of the upside cost. He inquired how to figure the benefit for
increased flow in [the Alaska LNG Project] pipeline when there
is no unified tariff.
MR. MARKS answered there are four pipes within [the Alaska LNG
Project] pipeline. If someone wants expansion capacity, the
state would be the expansion source. There would be a per-unit
cost, but he said it unclear regarding the transparency of the
negotiations.
REPRESENTATIVE SEATON commented "it sounds about as foggy as I
thought it was."
6:54:25 PM
CO-CHAIR SADDLER asked whether, from Mr. Marks' perspective with
other worldwide LNG projects, there are any special concerns or
challenges for marketing this volume of gas.
MR. MARKS replied there are huge challenges due to the size of
the project and having to amortize the pipeline. It is
necessary "to put a lot of gas through to get the per-unit cost
down, which makes a marketing challenge." In Asia, gas is
marketed contract by contract, utility by utility, which is
different than in the Lower 48. The Asian market is growing
about 2 billion cubic feet per day per year. At an expenditure
of $65 billion, the state does not want the pipeline to be empty
for very long; the gas must be sold quickly because a slow ramp-
up has a negative effect on the rate of return. He pointed out
the necessity to market a lot of gas in a short period of time.
This proposed project will produce 2.4 billion cubic feet (BCF)
per day, so it could take four years to market this much gas,
meaning the pipeline would be empty for three years. If it
takes four years to get 2.4 BCF a day, and the market is growing
only 2.0 BCF a day, this project must capture 30 percent of the
incremental market in Asia every year, which is quite ambitious.
MR. MARKS, responding further to Co-Chair Saddler, explained
that with a market growth of 2 BCF per day, it is not possible
to get 2.4 BCF a day into the market in the first year because
the market is growing slow and lots of other people are
competing to sell gas to this market, and the gas must be sold
utility by utility by utility. The size of this project makes a
challenge because of needing to get a lot of gas into the market
in a short amount of time while the market is only growing
incrementally so fast. To capture 30 percent of the incremental
market in Asia for four years in a row is an ambitious task.
Even in this good case the pipeline will be partially empty for
three years, so if it takes five years to market the pipeline
will be empty even longer. This is one of the unique commercial
challenges of this project because of it being an 800-mile-long,
high-cost pipeline.
CO-CHAIR SADDLER offered his understanding that LNG projects do
not typically start at that low level of utilization and then
take years to catch up.
MR. MARKS replied the other LNG projects are smaller projects
that do not have to sell as much gas, so it is easier to market.
6:58:29 PM
CO-CHAIR FEIGE pointed out that Alaska has the advantage of not
having to drill the wells to produce the gas, so as soon as the
gas is contracted for, there is the certainty that the gas is
there and is available immediately upon pipeline completion. He
asked whether that counteracts any of the aforementioned
disadvantages.
MR. MARKS responded it would counteract "a little bit." He drew
attention to slide 5, which depicts the upstream costs, but not
the project pipeline costs for various new LNG projects. He
allowed Alaska may have a low upstream cost because the gas is
already being produced. He said the break even cost that he
calculated more than offset the upstream cost for these other
projects. Most of the depicted projects are not developed and
not being produced, but they are proven. While producing the
gas will not be cheap, it is not the biggest challenge for those
projects; their biggest challenge is getting into the market
with the cost of the LNG part, not the producing gas part.
7:00:09 PM
REPRESENTATIVE P. WILSON recounted that people have mentioned a
bigger size pipeline. She asked whether there is an optimal
size for a pipeline relative to cost.
MR. MARKS answered that when the state was previously talking
about a pipeline to North America, the size contemplated was 4.5
BCF per day. If that gas can be gotten into the market, it is
easy to sell -- just put it into the pipeline grid and it goes.
But Asia is a challenge. A larger pipeline would bring down the
per-unit cost, but necessitates the sale of more gas. Asia is
the exact opposite problem that the state had in North America,
so the producers have tried to find the sweet spot to make the
pipeline as large as possible but not so big that the gas cannot
be gotten into the market. He pointed out that although the
market is growing, and given how much of the incremental market
Alaska would have to capture each year, it is still ambitious to
get even a smaller amount of gas into the market, which is one
of the big problems with this project.
REPRESENTATIVE SEATON requested the committee receive in writing
the questions that Mr. Marks has suggested asking.
MR. MARKS suggested the request be made to the Legislative
Budget and Audit Committee and he will be happy to provide them.
[CSSB 138(FIN) am was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES - Roger Marks 3.27.14.pdf |
HRES 3/27/2014 4:30:00 PM |
SB 138 |
| LB&A Roger Marks Report 2.18.14.pdf |
HRES 3/27/2014 4:30:00 PM |
SB 138 |