Legislature(2013 - 2014)HOUSE FINANCE 519
04/11/2014 01:30 PM House FINANCE
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| Presentation: Discussion of Oil and Gas Issues - Roger Marks and Enalytica. | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
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HOUSE FINANCE COMMITTEE
April 11, 2014
1:34 p.m.
1:34:57 PM
CALL TO ORDER
Co-Chair Austerman called the House Finance Committee
meeting to order at 1:34 p.m.
MEMBERS PRESENT
Representative Alan Austerman, Co-Chair
Representative Bill Stoltze, Co-Chair
Representative Mark Neuman, Vice-Chair
Representative Mia Costello
Representative Bryce Edgmon
Representative Les Gara
Representative David Guttenberg
Representative Lindsey Holmes
Representative Cathy Munoz
Representative Steve Thompson
Representative Tammie Wilson
MEMBERS ABSENT
None
ALSO PRESENT
Roger Marks, Legislative Consultant, Legislative Budget and
Audit Committee; Janak Mayer, Partner, Enalytica; Nikos
Tsafos, Partner, Enalytica.
SUMMARY
^PRESENTATION: DISCUSSION OF OIL AND GAS ISSUES - ROGER
MARKS AND ENALYTICA.
1:35:08 PM
ROGER MARKS, LEGISLATIVE CONSULTANT, LEGISLATIVE BUDGET AND
AUDIT COMMITTEE, provided a PowerPoint presentation titled:
"Evaluation of SB 138 and Associated Proposed North Slope
Natural Gas Commercialization Proposals" (copy on file).
1:35:52 PM
Mr. Marks began his presentation with slide 2: "Roger Marks
- Background." He disclosed that he worked in a private
consulting practice in Anchorage specializing in petroleum
economics and taxation. From 1983 through 2008 he was a
senior petroleum economist with the State of Alaska,
Department of Revenue Tax Division. One of his
responsibilities was to assess the North Slope gas
commercialization issue which he continued to do over the
course of his 25 years of service. He pointed out that over
a fifteen-year period in the 1980s and 1990s he was likely
the only state employee looking at the gas issue. He
participated in various study groups with the producers on
liquefied natural gas (LNG), pipeline gas, and gas to
liquids. He also worked on the Alaska Stranded Gas
Development Act under Governors Tony Knowles and Frank
Murkowski. He reported that since leaving the state he
published on Alaska Gasline Inducement Act (AGIA) in a
couple of journals and through his work with various
clients he continually assessed commercialization potential
of North Slope gas.
1:36:58 PM
Mr. Marks continued with some background explaining that in
early February 2014 he was asked by Senator Kevin Meyer
through the Legislative Budget and Audit Committee to
prepare an evaluation of the gas proposal. He issued a
report in mid-February 2014 which members had in their
packets. He announced he would be addressing some of the
findings in his report and indicated he would be offering
some observations, some suggested questions, and some
options to consider. He turned to slide 3: "Outline":
1. Introduction: Market and Timing Landscape
2. Hi-level Decisions
a. In -Kind Gas
b. Regulation
c. Ownership
3. Role of AGIA in Proposal
1:38:21 PM
Mr. Marks discussed slide 4: "Introduction: Market
Challenges":
· Competition
o Twice the amount of supply as there is demand in
Asia in 2030
· Pricing
o Prices appear to be falling
ƒBuyers realize sellers were making windfalls
at prices linked to high oil prices and
increased competition among sellers
o Compete based on cost
· Size Burden
o Need to capture large incremental share of market
in short amount of time
o Higher breakeven price than much of the
competition.
Mr. Marks reported 19 countries outside the U.S. with
functioning LNG projects that were looking to serve the
Asian market. He continued that there were 5 additional
projects in the advanced stages of market assessment, also
hopeful of supplying Asia. He made the point that if the
2009 nuclear embargo was lifted, the 1,200 trillion cubic
feet of gas sitting in the shallow waters of Iran would
become an available supply as well. He furthered that the
Fukushima disaster in Japan in 2009 [2011] took all of
Japan's nuclear capability offline, which accounted for 30
percent of its energy demand. Japan replaced its resource
with gas causing the country's energy prices to rise. The
Japanese government was very interested in bringing most of
its 48 nuclear plants back online. He reported that only 4
of the 48 plants were affected by the Fukushima disaster.
The remaining plants were in good condition. He relayed
that Japan was also interested in accelerating its coal
development and moving away from the use of gas. He
informed the committee that China started to explore shale
and coal-bed methane and had access to great quantities of
pipeline gas from Russia. He surmised that despite
encouraging market growth prospects in Asia and in looking
at the consensus and most of the forecast, there would be
twice as much supply of LNG as there would be demand in
Asia by the year 2030.
Mr. Marks moved to the topic of pricing. He stated that,
until recently, LNG prices in Asia were oil-linked causing
prices to be high, especially as oil and gas prices
worldwide seemed to be coupled over the last 10 to 15
years. He continued that the link appeared to be weakening
as buyers in Asia realized producers were making a windfall
on oil-linked prices and as competition to sell gas to Asia
increased. Previously, LNG prices were around $18 per
million British thermal units (BTU) in Asia, as reflected
in old contracts. Newer contracts were being let at prices
as low as $6 to $12 per million BTU.
1:41:34 PM
Mr. Marks reported that Rice University's sophisticated
world gas marketing model showed that oil prices in Asia
would be about $5 per million BTU over Henry Hub's
prediction. The long-term forecast for Henry Hub was a
price of around $5. If Rice University's model was
accurate, Asia's price would be $10 per million BTU, much
lower than what it had been. He furthered that, going
forward, prices would continue to fall, and competition
would have to be based on cost.
Mr. Marks pointed out that Alaska was at a disadvantage
regarding cost. He mentioned the size burden of the
project. The cost estimate for the total project was $45
billion to $65 billion including the gas treatment plant,
the pipeline, and the LNG facilities. The cost estimate was
done four years earlier and did not account for inflation.
Alaska was the only LNG project in the world that would
have a pipeline of its magnitude. Alaska required the
largest and longest pipeline to bring gas to the point
where it would be liquefied. He elaborated that, since it
was such a big and expensive pipeline, Alaska would need
large quantities of gas to run through it to lower the per-
unit price. He stipulated that the gas would have to be
sold in a short amount of time, otherwise, a pipe would sit
half empty for several years hurting Alaska's economics.
The producers worked to find the ideal pipeline size large
enough to bring the per-unit cost down but not so big that
the volume of gas could not be sold. The volume of Alaska's
project would be lower, and the per-unit cost would be
higher. He mentioned that in Asia discreet sales could be
made utility-by-utility, unlike the United States. All
three producers [BP, ConocoPhillips, and ExxonMobil] would
have to sanction the project individually in order for the
project to move forward. The Asian market was only growing
at a rate of 2 billion cubic feet (BCF) per day, per year.
Alaska's project would generate 2.4 BCF per day, per year.
He suggested that if it took 4 years to get the gas into
the market Alaska would capture 30 percent of the
incremental market each year, an ambitious goal.
1:44:50 PM
Mr. Marks moved to slide 5: "New LNG Projects are
Expensive." He pointed out that breakeven prices were
estimated at $8 to $13 per million BTU in Asia. His
breakeven estimate for the North Slope project, depending
on what hurdle rate the producers used and the cost of the
project, fell between $11 and $17 [per million BTU]. Alaska
was one of the higher cost LNG projects.
1:45:28 PM
Mr. Marks advanced to slide 6: "Timing Landscape":
· Terms set up today will determine
o Risks to state
o Cost of capital
ƒLong-term gas revenues
ƒWhat Alaskans pay for gas in the future
· Options: A modified deal which may take a few months
to put together could create more long-term benefits
to state
Mr. Marks communicated that the state needed the project to
begin as soon as possible, and terms set at present would
determine two important things going forward; the risks to
the state and the cost of capital. He used the example of
interest on a thirty-year home mortgage to explain that the
cost of capital determined gas revenues and rates to
consumers. Lower terms on capital costs for the pipeline
would save significant dollars over the life of the
project. He suggested the state consider a modified deal
that, if available, would ultimately lower costs for the
state and for consumers.
1:47:49 PM
Mr. Marks referred to slide 7: "High Level Decisions under
Proposal":
· State takes its production taxes and royalties as in-
kind gas
· Tariffs and expansions will not be regulated
· TransCanada (and perhaps SOA as partner) will own
share of GTP and pipeline, and SOA will own share of
LNG facilities, commensurate with state's share of gas
(about 25%)
· Designed to amicably transition out of AGIA
Mr. Marks stated that tariffs would be regulated under
Section 3 of the Natural Gas Act geared for LNG import and
export terminals and did not cover tariff and expansion
terms. As a result, in order to get reasonable tariffs and
expansion terms the state was interested in owning a
portion of the project.
1:49:12 PM
Mr. Marks detailed slide 8: "In-Value vs. In-Kind Gas":
· Helps out the economics of the project considerably
· If the state takes its royalties and taxes in value:
o The producers pay for 100% of the capital cost,
incur 100% of the capital risk, but only get 75%
of the revenues
o Producers pay to state in taxes and royalties an
amount of money equal to 25% of the gas
o They slowly recover over time the cost of the 25%
of the capital costs they laid out for the
state's share through the tariff deduction
o But at a midstream rate of return, which is lower
than the upstream
o This waters down their rate of return
· When the state takes its taxes and royalties as in-
kind gas, the state assumes the capital commitment for
its capacity either through ownership or taking on a
firm transportation commitment with a third-party
· The state does not need to own the pipeline to take
the gas in-kind
Mr. Marks explained that currently with the Trans-Alaska
Pipeline System (TAPS) the producers realized a midstream
return of 8 percent. Producers anticipated a minimum hurdle
rate of approximately 10 to 12 percent based on where they
were looking for a return on the upstream and the project's
risks. Taking the oil in-value watered down the rate of
return. He also noted that the upstream rate of return not
watered down with the midstream increased the producers'
rate of return by 1 or 2 percent. The breakeven price
dropped from $1 to $2 per million BTU, a significant amount
based on the scale of the project. He added that, in terms
of alignment, taking the gas in-kind was more important.
1:51:23 PM
Mr. Marks reviewed slide 9: "Firm Transportation
Commitments":
· When the state takes its taxes and royalties as in-
kind gas, the state will take on a long-term firm
transportation liability (debt) to TransCanada (on the
portion of the 25 percent the state does not own).
· Ship or pay regardless of cost, market, reserves
· Used by pipeline company as collateral for financing
· TransCanada will have priority claims on projects cash
flows
Mr. Marks elaborated that a firm transportation (FT)
commitment was not an operating expense but a capital
obligation. It did not vary with operations. In financial
terms, TransCanada would become the middleman; the state
would sign the FT commitment, TransCanada would take the
commitment to the bank, the bank would give TransCanada
cash to build the pipeline, and the state would owe the
money to TransCanada. He stated that whether the state
owned the pipeline itself or took the FT commitment, the
obligation and loss of debt capacity would be the same.
1:53:58 PM
Mr. Marks advanced to slide 10: "Debt Capacity and In-Kind
Gas":
· State policy is for debt service to be not more than 8
percent of general fund unrestricted revenues
· Investing in the project will put the state 2-3 times
over that amount
· It has been suggested that having TransCanada as a
partner would reduce the debt service relative to
state ownership
· The debt from taking the FT with TransCanada will have
a greater impact on the state's debt capacity than
debt used to finance ownership
Mr. Marks gave an example that if the state owned $1
billion of the project and financed at 70 percent debt and
30 percent equity, the debt would equal 70 percent of $1
billion. If the state took a FT commitment to TransCanada
for $1 billion, it would be $1 billion of debt.
1:55:21 PM
Mr. Marks turned to slide 11: "Marketing the In-Kind Gas":
· By taking gas in-value the state benefits from some of
the best marketers in the world
· Consider linking in-kind provision with agreement by
producers to market state's gas with their gas at the
same price they got
o Otherwise, risk that state may be marketing at
prices considerably lower than producers, which
could result in losing money
Mr. Marks reported that with the in-value system, where the
state received a share of what the producers received
through taxes and royalties, the state would benefit from
some of the best gas marketers in the world, the gas
producers. The producers would market the gas for no fee to
the state. Under Section 8.3.3 of the Heads of Agreement
(HOA) it stated that the producers would be willing to
negotiate an agreement to purchase and dispose of the
state's in-kind gas. He suggested the state consider
linking the gas in-kind option in an agreement with the
producers, where producers would market the state's gas
with their own (including pricing) at no cost. Without such
a provision, the state stood high risk. He explained if the
three producers sanctioned the project, the state would be
passively drawn into participating. The statute for
taxation specified that producers had the ability to pay
their taxes and royalties in-kind, they could. Once they
did so, the state would be forced into an FT commitment
with TransCanada. In reading the MOU with TransCanada, he
found that the state would have to take the FT before the
front end engineering design (FEED) started, at the end of
preliminary front end engineering design (pre-FEED), which
was not a customary arrangement. Usually, to get to pre-
FEED, a company started filing its documents with the
Federal Energy Regulatory Commission (FERC), where the open
season started. Potential shippers then took out precedent
agreements, much less binding than firm transportation
agreements. Under the Memorandum of Understanding (MOU) the
state would have to take a firm transportation services
agreement before feed started; before the final cost, debt,
and equity costs were known; and before being able to
assess the market. The construction period, if sanctioned,
would be 5 years. If the producers got to the market first,
they would likely get the highest prices and the best
markets. Even given a tight economic climate, the project
would still potentially be feasible for producers by a
small margin. However, if the state ended up marketing
behind the producers and thus procuring less for its gas,
it could mean a loss for the state. In addition if the
state was competing with the producers in the same market
it could reduce the price it obtained in Asia if the buyers
tried to play the state against the producers. Getting the
producers to sell the state's gas was exactly what happened
with the in-value system. He concluded that the state would
have more bargaining power than through negotiation.
1:59:20 PM
Mr. Marks discussed slide 12: "B. Regulation":
· Proposal under Heads of Agreement (HOA) is for FERC to
regulate under Section 3 of the Natural Gas Act
o Mainly designed for licensing the siting,
construction, expansion, and operation of LNG
import or export terminals
o Terminals include facilities used to transport
and process gas
o Appears this would be the only pipeline in the
U.S where tariff for consumers' gas is not
regulated
· No regulation of tariffs or expansions
o To get reasonable tariffs and expansions, state
ownership necessary
o Unclear what happens as in-state needs expand:
Mr. Marks stated that, as specified by FERC, an LNG
terminal included a treatment plant and a pipeline. Based
on FERC's definition, the current proposal would not have
any regulations on tariffs or expansions. In the Lower 48,
where Section 3 was used and included pipelines, there were
interstate pipelines that delivered gas to consumers; FERC
regulated the pipelines under Section 7. After consulting
with research staff from the National Association of
Regulatory Utility Commissioners, the National Regulatory
Research Institute, and the Texas Railroad Commission, he
discovered that the proposed pipeline would be the only one
in the United States in which tariffs for consumer gas were
not regulated. Under the proposal, the pipeline would not
be a common carrier or a contract carrier. He continued
that the pipe would essentially be four industrial feed
lines from the North Slope to Asia. He concluded that the
way the proposal was designed, state ownership was
necessary in order to get reasonable tariffs and
expansions. He also surmised that the state's capacity
would possibly become the expansion source of last resort.
2:01:57 PM
Mr. Marks directed attention to slide 13: "Example -
Initial Gas disposition (billion cubic feet per day)":
Initial Gas Disposition (billion cubic feet per day)
Total Gas 2.4 bcf/d
State Share 25 percent
State Gas 0.6 bcf/d
To Fairbanks (0.05 bcf/d)
State Gas to Asia 0.55 bcf/d
Mr. Marks suggested that in five years if Cook Inlet
production started to decline without the prospect of
recovering and Southcentral Alaska needed 0.2 bcf/d, it
would be difficult to ensure production of available gas.
Long-term contracts with Asia would prevent any obligated
capacity from being redirected for in-state use. He
volunteered that the state could request the U.S.
Department of Energy revoke the export license based on
indigenous consumption need. He recommended the state
consult with the department for more information. He also
suggested including language in the enabling legislation
that would compel producers to produce gas if needed for
in-state consumption. Under current lease terms it was not
possible for the state to do so. He suggested that 0.2
bcf/d was a relatively small quantity of gas, and an
alignment of interests between the state and the producers
would be necessary. He recommended the state negotiate with
the producers about the possibility of expansion if
additional in-state supply was needed after the pipeline
was running.
2:04:41 PM
Mr. Marks addressed what the producers would charge the
state for their gas. He asserted that without regulation in
place a transparent netback price would not be available to
determine a reasonable purchase price. He suggested adding
a provision be added to the legislation requiring producers
to sell their gas to the state, designated for in-state
use, at a reasonable price. He furthered that similar
provisions were used in the state's tax statues.
2:06:05 PM
Mr. Marks reviewed slide 14: "Benefit of Regulation of
Monopoly":
· Precedent for Regulatory Commission of Alaska to
regulate in-state and export pipeline and gas
treatment under AS 42.08
· Regulation is the trade-off for privilege of natural
monopoly
· May enhance market efficiencies to have transparent
pipeline cost
· State may be conflicted as pipeline owner or partner
to pipeline owner for accountability
Mr. Marks explained that only one pipeline would be built.
The state would grant a right-of-way lease giving the owner
of the pipeline a monopoly on the business of transporting
gas. He remarked that Section 3 of the Natural Gas Act was
not designed to deal with a monopoly power over a gas
pipeline in a marketplace setting where consumers receive
gas directly. Currently, there was a very efficient system
in place for small producers to get their oil to market.
The only producers shipping gas on Trans-Alaska Pipeline
System (TAPS) were British Petroleum (BP), ConocoPhillips,
and ExxonMobil. It would be very inefficient for small
producers such as Anadarko, Pioneer, ENI, and others, to
get into the gas transportation business based on the
volume of gas they produce.
Mr. Marks elaborated that prior to the Exxon-Valdez spill
many of the producers shipped their oil on other producers'
tankers, an agreement called, "contract of affreightment."
After the Exxon-Valdez spill the small producers started
selling to the "big-three" producers who then transported,
shipped, and sold the gas. The small producers took a
slight reduction in their selling price, but in doing so
avoided taking on oil spill risk. Also, the netback costs
of the oil on the slope remained transparent. However, with
the new legislation, the netback value on the North Slope
would be a complete unknown except to the pipeline owners.
Mr. Marks argued that the pipeline owners would have the
opportunity to exploit their monopoly, possibly impeding
commercial activity and hampering the small gas producers
from exploring for and developing gas on the North Slope.
He also noted that if TransCanada had 25 percent capacity
of the pipeline in partnership with the state to deliver
gas for in-state consumption, one of the most significant
roles of regulation would be to make sure there was
responsible and prudent spending by the owners of the
pipeline. However, in the proposed case the owners would
have a monopoly, incurring costs and passing them through
at their discretion. The owners would be able to make
higher equity investments and earn higher investment
returns without having to be responsible and prudent in
their spending. He expressed his concerns that there would
be no neutral place for the consumer to go with a grievance
without regulation in place. In the proposed regulatory
arrangement the state would potentially be conflicted in
terms of accountability. He saw accountability problems for
prudent spending as one of the issues to be concerned with
under the proposed regulatory arrangement.
2:12:00 PM
Mr. Marks discussed slide 15: "C. Ownership and
Partnership":
· Need for ownership due to no regulation on tariffs and
expansion, and for lower tariffs
· State does not necessarily need partner for expertise
assistance
o Producer expertise
o AGDC expertise
o TransCanada's expertise in gas treatment unclear
o To the extent there is not a need for expertise,
if the state needs a cash partner, it does not
necessarily need a pipeline company partner, but
a general investment partner
Mr. Marks recounted the agreement explaining that the
state, in partnership with TransCanada, would own 25
percent of the pipeline commensurate with its share of the
gas. TransCanada would own the pipeline and the treatment
facility with an option for the state to buy into its 40
percent. He elaborated that the state would own 100 percent
of the 25 percent state share of the LNG facility. He
questioned whether the state needed ownership, and if so,
whether it needed a partner. He opined that under the
proposed regulatory structure there was a need for
ownership due to the lack of regulation on tariffs and
expansion and for lower tariffs. He reported three reasons
outlined in the regulatory structure why the state needed a
partner. First, the state's debt limit problem would be
reduced by having a partner and taking an FT commitment
with TransCanada. Second, a partner would bring expertise
to the project. Third, the state needed a bank. He did not
did not necessarily agree that the state needed a partner.
As he discussed earlier having a partner and taking an FT
commitment with TransCanada would actually increase a debt
limit problem. He argued that the state would already have
the expertise it needed from the producers. He also
emphasized that the state would have the Alaska Gasline
Development Corporation's (AGDC) expertise. Under the
current proposal nearly half of the cost of the project was
for the LNG facility which would be owned by AGDC without a
partner; AGDC would be allowed to take on contractors but
would have full ownership of the facility.
2:14:40 PM
Mr. Marks stated that under the Alaska Stand Alone Pipeline
(ASAP) AGDC was appropriated more than $400 million to own,
build, operate, and finance the in-state line without a
partner. The size of the bullet line project was roughly
equivalent to the state's 25 percent share of the AKLNG
project.
Mr. Marks moved on to discuss the gas treatment plant and
the pipeline. In looking at financial reports he commented
that it was unclear how much gas treatment experience
TransCanada had. He claimed they were world-class
transporters of oil and gas, had businesses in power
generation and gas storage, but lacked much or any
experience in gas treatment. He furthered that when
TransCanada originally submitted its AGIA application it
did not want to do gas treatment. TransCanada came back
with a gas treatment contract with URS Corporation at the
request of the state.
Mr. Marks suggested that if the state needed a cash
partner, it did not necessarily need to partner with a
pipeline company. He communicated that a general investment
partner, such as a large investment bank or a private
equity firm, may be a better fit. He also alluded that
finance funding could come from the Alaska Permanent Fund
to the tune of approximately $3 billion. The state could
invest it at 11 percent, less than TransCanada, and bring
an 11 percent return which was a very equitable return.
2:17:14 PM
Mr. Marks discussed slide 16: "State Does Not Necessarily
Need Partner for Cash or Lower Tariffs: 2011 Citigroup AGDC
Financing Plan":
· Possibility of 100% debt financing
o Combination of revenue bonds and state backing
o Appears to be less risky than ASAP plan
o Possibility of deferring most cash outflows until
gas starts flowing
o May have short-term impact on credit rating that
would reverse once gas revenues start coming in
· Possibility of tax-exempt bonds through Alaska
Railroad
o Directed at industrial development projects
o Requires IRS private letter ruling
o Reduces cost of debt about 25% relative to
taxable debt
· Would require potentially no or little equity (cash)
before gas starts flowing
· To the extent the state does not need a cash partner,
its good credit rating and potential for tax-exempt
debt could result in a lower cost of capital
Mr. Marks reported that AGDC brought in Citigroup to put
together its financing plan in 2011. Citigroup discussed
the possibility of 100 percent debt financing through a
combination of revenue bonds and state backing. The 25
percent AKLNG project appeared less risky than the stand-
alone project in many regards. The stand-alone project was
projected to be approximately $8 billion, whereas the cost
of the AKLNG project would only be slightly more. The
involvement of the big-three producers would make it less
risky for investors, and there would be more gas revenue
coming to the state to underpin the debt.
Mr. Marks suggested that, with 100 percent debt financing,
cash outflows could be deferred until gas was flowing. He
continued that the state could experience some short-term
impact on its credit rating that would be reversed once gas
revenues started coming in. The impact would likely occur
within the first five years. The only time this could
become a problem was if there were gas purchase agreements
in place and creditors felt comfortable that high gas
prices would be coming in after construction.
2:19:22 PM
Mr. Marks discussed tax-exempt bonds through the Alaska
Railroad Corporation. When the state purchased the railroad
from the federal government in 1983 part of the legislation
that conveyed it to the state opened up the opportunity for
the railroad to issue tax-exempt debt. The purpose was to
add to industrial development projects. He stated that
Senator Ted Stevens authored the legislation and believedit
would open the door for the state to get tax-exempt debt
through the railroad. Citigroup also believed it was a
possibility. He furthered that in order to get tax-exempt
debt the state would need a private letter ruling from the
Internal Revenue Service (IRS). A legal argument needed to
be made to the IRS, which would be costly to assemble,
approximately $100 thousand or more. He explained that tax-
exempt debt financing ran about 25 percent less than
conventional debt. If the state could get tax-exempt debt
it would be a tremendous benefit to the project; 100
percent low-cost debt financing would require little or no
equity up front prior to gas output. The state's good
credit rating and potential for tax-exempt debt would
likely result in a lower cost of capital to the extent the
state did not need a cash partner. Higher revenues, lower
tariffs, and lower cost gas to Alaskans would also follow.
He suggested the state bring in Citigroup as a consultant.
2:21:51 PM
Mr. Marks discussed slide 17: "Ownership: Risk of Failure
to Sanction":
· Sponsors could spend over $2 billion to get to FID and
have a project not materialize, of which SOA would be
responsible for 25%, regardless of whether it
exercised ownership option with TransCanada
· Are producers better equipped to handle that risk?
o Diversification - some of their other prospects
will get sanctioned
o Finite capital competing not only for gas, but
for oil
o Where other countries do share this risk, the
takes are higher
· Will this money make a material difference to the
viability of the project?
o The more interested the producers are in the
project, the less they need state money. The less
interested they are, the more the state should
avoid this risk.
· Balance:
o How near tipping point
o Probability of Project
o Size of the prize
o How material is $600 mm
· Could pursue arrangement with producers to buy in to
project once it is sanctioned (or at least after pre-
FEED) and re-pay feasibility costs with interest
Mr. Marks stated that the project could be stopped at any
point. The purpose of the FEED process was to spend money
to narrow cost uncertainties. At the time of entering pre-
FEED, cost uncertainty would be in the area of 20 to 25
percent, too uncertain for going forward. He recommended
spending money to get to the point where there was a
confidence level of plus or minus 10 percent. He opined
that it would take about 3 to 5 percent of the total
project cost to get to the proposed level of comfort,
reflected in the $2.2 billion that was estimated to get
through pre-FEED and FEED.
Mr. Marks discussed the challenge of developing a gas
marketing plan without knowing costs. He specified that the
state needed to ensure that it could generate enough income
to cover its costs. He indicated that there were multiple
reasons why the state could spend a lot of money and still
walk away with nothing. Other projects could step into the
market, prices could crash, and exchange rates could change
unfavorably affecting gas prices. He was uncertain if the
state should take the risk of ownership and wondered if
producers were better equipped to handle the exposure. He
asserted that the producers had diversification in their
favor compared to the state. He explained that companies
had a finite amount of capital and asserted that the
current project was competing with other LNG projects as
well as higher value oil projects. The producers were the
active decision makers while the state was the passive
recipient.
2:24:44 PM
Mr. Marks referenced the Denali project that BP and
ConocoPhillips took on a few years ago. He stated that
their goal was to spend $600 million to get to open season
without an inducement act, HOA, MOU, or state
participation. He claimed that in other countries, where
they took the risk of incurring the costs of feasibility,
they were limited to national oil companies where the
government takes were much higher than Alaska's potential
project. Additionally, he stated that what the producers
spent on sanctioning costs would be paid for through state
and federal government income tax deductions. He also
claimed that the market cap of the big-three companies was
about $750 billion, dwarfing the state.
Mr. Marks posed the question whether the money the state
spent would make a material difference to the viability of
the project. He believed there was a tipping point where
state participation would make a difference. However, there
was no way of knowing where the tipping point was. He
asserted that the more interested the producers were, the
less they would need the state's money for feasibility. The
less interested they are in the project, the more the state
should stay away from the risk.
Mr. Marks commented that there was a balance between the
tipping point, the probability of the project, the size of
the prize, and how materially it would be if the state
invested $600 million and came away with nothing; AGIA did
that with $350 million. He stressed that what the producers
needed was long-term alignment.
2:27:11 PM
Mr. Marks discussed slide 18: "Role of AGIA in Proposal":
· Public comments by administration:
o Aggressive time frame to get gas to market
o Desire to avoid potential lengthy and costly
legal fight over ending AGIA license
o Proposal designed to end AGIA license amicably
· Appears plan was crafted (at least in part) around
giving TransCanada a material role to avoid potential
AGIA liabilities
· License project assurances (treble damages) clause in
AGIA
· Could there be better terms if state was not so
constrained by AGIA?
Mr. Marks claimed that if the state proceeded without
TransCanada there would be a risk of legal and financial
exposure through the license project assurances clause in
AGIA, which asserted that if the state gave preferential
tax treatment or a grant of state money for a competing
project it had to pay TransCanada three times what it
spent. In referring back to the public comments made by the
administration, he believed that the state was placed in a
poor bargaining position in crafting terms with
TransCanada. He wondered if better terms could be agreed
upon if the state was not so constrained by AGIA.
2:29:15 PM
Mr. Marks discussed slide 19: "Areas Where State Could
Possibly have Better Terms If It Had No Partner":
· Possibility of full ownership of 25 percent share of
GTP/Pipe with 100 percent debt financing and possible
tax-exempt debt
· Lower cost of capital: higher gas revenues/lower cost
gas to consumers
· There is a misalignment of interests between shippers
and non-shipper partners
Mr. Marks reported in the current project the state would
be the shipper and TransCanada would be the transporter. He
emphasized that the biggest risk of the project (other than
the market) was cost-overruns and expensive expansions.
TransCanada would make money while the state would lose
money on overruns. TransCanada made money on its return on
equity; the higher the equity invested the more money it
made. He asserted that TransCanada did not have incentive
to be efficient with spending whereas it was critical for
the state to avoid cost overruns.
2:31:09 PM
Mr. Marks moved to slide 20: "Areas Where State Could
Possibly have Better Terms If It Had a Different Partner
(or could re-negotiate MOU) ":
1. Sharing failure to sanction risk
2. Share in benefit of lower interest rates
3. Higher ownership share than 40% (of 25%)
4. Better cost of capital terms in tariff
o TransCanada's terms are about the same as other
Canadian pipelines
o 100% or tax-exempt debt may be preferable
o Given producer involvement, terms on existing
pipelines may not be relevant
Mr. Marks relayed that the state could potentially
negotiate better terms by putting the project out for
competitive bid or renegotiating the existing terms. He
reported that there were at least ten pipeline companies in
Canada and the United States that were capable of doing
Alaska's project. He identified four areas of the MOU that
could be adjusted to benefit the state. Currently, the
state assumed all of the risk of failing to sanction. He
suggested that risk could be shared. He also proposed
sharing in the benefit of lower interest rates. Under the
current MOU TransCanada proposed a 5 percent cost of debt.
If interest rates were to go down and TransCanada were to
refinance at a lower interest rate it would not be
obligated to pass the lower interest rate on to the state.
The state would have to continue paying the higher interest
rate. A different partner could offer to share in the
benefit of lower interest rates. The state could also
negotiate a higher ownership share than 40 percent.
2:34:33 PM
Mr. Marks stated that the final area in which terms could
be adjusted was better cost of capital terms. He recounted
that what TransCanada proposed was better than U.S.
pipelines under FERC, and what it received currently was
about the same as other Canadian pipelines. He suggested
that the 100 percent or tax-exempt debt was preferable to
what TransCanada offered. Also, with producer involvement,
terms on existing pipelines could be irrelevant. Private
equity firms could come in wanting lower returns. Also, the
state's portion of the pipeline was 25 percent. The
remaining 75 percent belonged to the producers who were
well-financed, well-capitalized, well-motivated, and well-
experienced. Other entities could look at the project as
less risky than terms on existing pipelines. Another bidder
might need a lower return and might be willing to share
some of the sanction risk. He reiterated the importance of
going out for bids on such a significant project.
2:37:39 PM
Mr. Marks directed attention to slide 21 titled "How Bound
is State by AGIA?":
· The easiest way out of AGIA is abandonment of the
project as uneconomic (AS 43.90.240)
· Official project plan is still the pipeline to Alberta
· Uneconomic defined as:
"predicted costs of transportation at a 100
percent load factor, when deducted from predicted
gas sales revenue using publicly available
predictions of future gas prices, would result in
a producer rate of return that is below the rate
typically accepted by a prudent oil and gas
exploration company for incremental upstream
investment that is required to produce and
deliver gas to the project."
· If parties disagree it is settled by arbitration
· If it is found uneconomic - treble damages no longer
apply
· Economically, this would not be difficult to show
Mr. Marks defined an "uneconomic" project to be one that,
given predicted costs and gas prices, had a sub-economic
rate-of-return. He commented that the standard in statute,
referred to as a preponderance of evidence, was a low
threshold. He explained that if there was a 51 percent
chance that the pipeline to Alberta project was not
economic, the state would not be bound to the project.
Under AGIA, if the parties disagreed on the economic
viability of the project, they would settle their dispute
via arbitration. He continued that if the project was found
to be economic then treble damages would no longer apply
[Note: slide reads "If it is found uneconomic - treble
damages no longer apply"]. He asserted that it would not be
difficult to show that the project to Alberta was
uneconomic. He furthered that he had informal conversations
with Don Bullock, at Legislative Legal Services, who
believed that it would not be difficult to show that the
project was uneconomic. Mr. Marks reported that the most
recent cost estimates for the project was $30 billion to
$40 billion excluding transportation costs from Alberta to
the Lower 48. He surmised that today, given the cost
estimates of the project and the forecasted prices in the
Lower 48, the project would lose money. He disclosed that
currently there was approximately 1,200 trillion cubic feet
of gas available in the Lower 48 closer to the market at a
lower cost than what Alaska could offer.
2:40:41 PM
Mr. Marks discussed slide 22: "Fiscal Stability":
· Producers have continually expressed necessity
· Some fiscal stability may be necessary
· SB 138 not stable
· Scope out producers intentions as to what constitutes
adequate stability.
Mr. Marks affirmed the necessity of fiscal stability. He
believed that it was a serious issue based on the history
of the state over the last 25 years. He opined that SB 138
in its current form was not stable. He acknowledged the in-
kind gas provision but asserted that there was nothing in
the bill that would prevent a future legislature from
coming in and imposing an additional tax. He suggested
approaching the producers to find out what they believed to
be adequate stability. He referenced Section 9.3.2 in the
HOA that addressed other terms that made the contract
predictable and durable. He did not want the state to be in
a position where it made a $600 million investment just
before sanctioning only to have producers set an additional
stipulation such as a change in the constitution.
2:42:15 PM
Co-Chair Stoltze asked if the legislature had time to
explore everything Mr. Marks suggested.
Mr. Marks stated that he had laid out some questions that
needed to be asked and some options that needed to be
explored. He posed the question whether it would make sense
for the state to go forward before answering the questions
and exploring its options.
Co-Chair Stoltze asked if enough tweaks could be made to
provide a higher level of comfort and certainty for
Alaskans based on Mr. Marks' recommendations.
2:43:37 PM
Mr. Marks responded with caution by stating that he
understood the legislature did not want to be told what to
do. He reiterated that there were some big questions to ask
such as whether the state should enter into the project
prior to the sanction point. He suggested putting a
mechanism in place where once the project was sanctioned
the state would enter into a commitment with the producers.
The state would then have the time to arrange it's
financing and give the producers the long-term alignment
they needed. The largest alignment between the state and
the producers would be for the state to commit to taking
its gas in-kind. He suggested that the state consult with
Citigroup about financing options.
Mr. Marks recommended declaring the AGIA project
uneconomic. The state would then be free to move forward
without TransCanada. He warned that if the state was
bringing TransCanada in because of AGIA, the state was
really limiting its options. He continued that if the
project was put out for bid it was possible that the state
would find out that TransCanada was an ideal partner. He
contended that in the case of large projects most
businesses go out to bid in order to consider all
possibilities.
2:46:39 PM
Co-Chair Stoltze mentioned that the state would have
another chance to approve a contract and that a special
session might be on the horizon for next year. He asked Mr.
Marks to elaborate on how much the state would be
obligating itself in taking the next step.
Mr. Marks replied that his understanding of the enabling
legislation was that it eliminated the option of going
forward without TransCanada. He avowed his concerns.
Representative Gara asked about Mr. Marks' availability to
help with amendments if necessary. Mr. Marks confirmed his
availability.
Representative Gara asked for clarification regarding Mr.
Marks' statement about statute rather than negotiation.
Mr. Marks replied that, in terms of the state getting what
it wanted, it had much greater bargaining strength putting
something into statute than sitting down to negotiate.
However, he interjected that all parties should be
considered.
Representative Gara expressed his concerns that if he did
not vote for the legislation the state would be saddled
with the Alaska Stand Alone Pipeline (ASAP) project. He
asked for further clarification. He also asked why Mr.
Marks thought the project had a lower risk than ASAP.
2:50:22 PM
Mr. Marks remarked that if he were a creditor looking at
the two projects he would be inclined to loan money to the
state for the AKLNG project because it appeared less risky
than the ASAP project. Citigroup said that under ASAP the
state could get $8 billion and possibly 100 percent debt
financing at good interest rates. There would be no
producer involvement, and a much lower revenue stream with
ASAP. The state would have a 25 percent buy-in,
approximately $11 billion, with producer involvement, and a
higher revenue stream with the AKLNG project.
Representative Gara asked if the state should leave its
options open when considering the risks and benefits of
revenue in-kind versus revenue in-value.
2:52:01 PM
Mr. Marks recommended taking the gas in-kind and opined
that it was a powerful economic incentive for the producers
to continue with the project. In considering a project of
its magnitude being able to move the rate of return by one
or 2 percentage points was significant. He also advised
including the stipulation that the producers sell the
state's gas with their gas at the same price, which he
believed would remove significant risk.
Representative Edgmon referred to slide 20. He asked Mr.
Marks if his recommendation would be to explore the four
items listed prior to passing SB 138.
Mr. Marks responded strongly in the affirmative. The
legislation would wed the state to TransCanada, thus
removing the option for a lower cost of capital on
TransCanada's portion. He thought the exploration was
prudent in securing the best deal for the state.
Representative Edgmon brought up the difference between Mr.
Mark's analysis of the project and that of Black and
Veatch. He noted Black and Veatch's evaluation favored
TransCanada as a worthy partner for a number of reasons. He
cited a reduction in up-front costs to the state of $4
billion to $7 billion, and the expertise accompanying
TransCanada. He questioned why Mr. Marks' assessment of the
project differed so much.
2:54:34 PM
Mr. Marks concurred that he disagreed on the points offered
by Black and Veatch. He specified that if the state could
not get 100 percent debt and did not have the cash, there
were other possible investors who would conceivably be
willing to invest at lower rates of return. He mentioned
that he had looked through the company's financial reports
and did not find evidence to support TransCanada's
expertise in the business of gas treatment. He encouraged
the state to have a candid conversation with TransCanada on
the subject. He spoke of access to studies done during the
AGIA process of the pipeline between Prudhoe Bay,
Fairbanks, and Nikiski. He believed that the state already
had the expertise of the producers available.
Representative Edgmon asked about the state's current
financial obligation to TransCanada. Mr. Marks replied that
pursuant to the MOU no spending had occurred.
2:56:58 PM
Representative Guttenberg asked why the project remained
viable when there were cheaper, closer, and larger volumes
of supply available on the market.
Mr. Marks replied that all of the proposed LNG projects had
problems. The advantage of the AKLNG project was that the
gas would be produced and ready to go. Other projects would
require development along with production. However, the
advantage was offset by the cost of the pipeline. The
majority of other projects did not have to incur pipeline
costs. Another big challenge of the AKLNG project was
bearing the cost of the treatment plant, 25 percent of the
total cost. It was necessary for Alaska's gas to be treated
for carbon dioxide (CO2) removal. Both Prudhoe Bay and
North Slope gas contained about 12 percent CO2, higher than
average. In liquefying gas all CO2 must be removed, driving
up costs.
Representative Guttenberg asked about tax-free debt.
Mr. Marks explained that if the state owned 25 percent of
the project and could acquire tax-exempt debt, it could
issue tax exempt bonds for 25 percent of the project,
unlike TransCanada. Since the bond holders did not pay tax
on their earnings, they would accept lower return rates on
tax-exempt bonds. He reported that generally tax exempt
bonds were about 25 percent lower than a taxable one, a big
savings in the cost of capital on the pipeline.
Representative Guttenberg asked for clarification on
TransCanada's role to the state. He asked if the entity
would operate as a bank to the state.
3:01:29 PM
Mr. Marks replied that TransCanada was a bank for the state
as well as a resource for its expertise on the pipeline.
Regarding the tax-exempt debt, any piece that TransCanada
owned was a piece the state could not borrow against.
Co-Chair Austerman reiterated Mr. Marks' comment that the
liability of the project was enhanced by Alaska taking its
gas in-kind and selling it alongside the producers. He
furthered that, from Mr. Marks' comments, it was beneficial
to the producers. He wanted to know what the most optimal
plan was for the state and what that meant for Alaska.
Mr. Marks replied that Alaska taking its gas in-kind would
likely determine whether the project moved forward. Moving
the rate of return one or two percentage points and
lowering the breakeven price $1 to $2 could make or break
the project.
3:03:32 PM
Co-Chair Austerman addressed the possibility of producers
selling the gas for the state. He asked Mr. Marks to
comment about concerns producers had about competition.
Mr. Marks responded that he believed the producers were
able to find the best buyers and command the best price for
gas ahead of the state. Given how much gas would need to be
sold if the state was fourth in line to sell its gas it
could potentially lose a few dollars per million BTU, an
excessive dollar amount; it could mean the difference
between making and losing money on the project. The state
could opt for hiring a gas marketer; however, the producers
had experience and contacts in the Asian market. Once the
producers sanctioned the project the state would be
passively "all in". He furthered that the producers could
pay their taxes in-kind forcing the state to take the FT
commitment and to sell its own gas. He reemphasized that if
the state fell to fourth place in the marketplace then it
could end up with several dollars less per unit than the
well-connected producers.
Co-Chair Austerman wanted to know if there would be an
anti-competition issue. Mr. Marks responded that the state
would have separate and succinctly different deals with
each of the producers.
3:07:12 PM
Representative Gara asked about firm transportation. He
also asked how the state could limit its risk of paying for
capacity in the pipeline that went unused. Mr. Marks
responded that the risk was low. He furthered that the
investment made by the producers would serve as an
incentive to keep gas in the pipeline unless there was some
unintentional damage to the reservoir preventing gas from
being produced.
Co-Chair Austerman reminded members that any requests for
services from any of the state-hired consultants had to be
written and processed through Senator Anna Fairclough's
office.
3:09:24 PM
JANAK MAYER, PARTNER, ENALYTICA, encapsulated the
discussions, issues, and questions from previous weeks
regarding the project into one fundamental theme; making
choices and commitments. He focused on the state's approach
related to how much it should commit to at present and how
much it should negotiate over time. He understood the
difficulty, from a legislative perspective, in making
decisions with only tools of statute, rather than tools of
direct negotiation. He referred to the Stranded Gas
Development Act (SGDA), which he indicated set the
fundamental terms of the agreement prior to any money being
spent on feasibility or further stages. The approach to the
AKLNG project was about setting initial framework, having
all of the partners together committing money and resources
to finding out more about the project, and making a series
of stage commitments as the process unfolded. He wanted to
further discuss the fundamental question of making
decisions at present versus making decisions in the future
(i.e. A project now versus a different project later, the
state trying to be carried through the process of
feasibility without having to currently devote funds, and
the role of TransCanada).
Representative Edgmon clarified that Mr. Mayer's main point
to the committee was not to get too overwhelmed with all of
the information, as the project was only in the pre-FEED
stage. Mr. Mayer agreed.
3:13:58 PM
NIKOS TSAFOS, PARTNER, ENALYTICA, believed the biggest
question that needed to be answered was whether the
legislation in front of the committee should be passed or
if the state should choose another path. He surmised that
the most difficult part of LNG projects was that everything
had to happen in parallel, rather than in a sequential
process. Gas could not be sold if people did not have
confidence in supply availability. Marketing would be an
impossible task without pricing, and financing would be
difficult to obtain without cost. He contended that the
overarching challenge of the project was to determine the
approach. He suggested there were two approaches; first was
to make all of the decisions up front then carry them out.
He favored the second approach which was to recognize that
there were multiple parallel paths that were dependent and
built upon each other. He noted that the fiscal notes
included the state committing to less than $100 million in
the pre-FEED stage. He also suggested that projects changed
over time. New partners could come in and possibly reduce
the state's exposure. He emphasized things would change as
the project progressed.
3:16:40 PM
Mr. Mayer discussed the state's exposure over the next
couple of years. He relayed that the HOA outlined the
state's role as an equity partner contributing 25 percent
of the costs through the pre-FEED and FEED process. He
furthered that the state would ultimately be liable for its
equity portion no matter TransCanada's participation. There
were some concerns raised whether the state was in a
position to assume the proposed risk. Risk for producers
was spread among a number of LNG projects, whereas, the
state had a compelling interest in only one project. The
current framework included in the HOA, a non-binding
agreement of the parties that outlined the vision of the
project. He asserted that the agreement was appealing
because the parties agreed to encounter the feasibility
process without having all of the details defined. The
alternative was to start from scratch with the state
assuming less exposure and negotiating a comprehensive
contract. The agreement would encompass the entire fiscal
framework and the exact nature in which the state would
participate prior to moving forward.
3:20:03 PM
Mr. Mayer emphasized understanding the nature of the
project and investing incrementally over time as opposed to
committing upfront without much information just to save
money in the first year of the feasibility stage. He
claimed that when he looked at both options it was more
appealing for the state to enter into slowly escalating
commitments in tandem with details of the project, thus
minimizing risk. He reiterated the question came down to
making choices now or later.
Mr. Tsafos added an additional point about marketing to his
discussion from the previous day. He cautioned the
committee about committing to have the producers sell the
state's gas on their same terms. Although intuitively
appealing, gas was very contract dependent, unlike oil. One
of the particular features of contracts were measures that
allowed the state to limit its volatility such as having a
floor or ceiling in a contract. He suggested that as a
sovereign the state might want a different exposure level
than that of the producers. The producers had assets all
over the world and viewed risk management and commodity
exposure in a fundamentally different way than the State of
Alaska. He wanted to caution and challenge the assumption
that if the producers sold the state's gas on its behalf
that the terms would automatically be the best terms for
the state. It was highly possible that the producers' risk
tolerance differedfrom the state's. It was also highly
possible that the contract that producers signed would have
a risk exposure quite different from what the state would
like.
Mr. Tsafos addressed the broad idea of making a decision
today versus in the future. He alleged that if the state
set certain marketing terms at present it would also take
on certain risk exposures that it would not have control
over. Whereas if the state waited one, two, or three years
out it might have more say in managing its risk. The state
could clearly ask for its gas to have a guaranteed floor of
$10 and a ceiling of $15, for example, with certain terms
attached. The producers might not want to market their gas
in such a way. However, if the state agreed to receive
whatever the producers collected, it would also have to be
willing to adopt their risk tolerance appetite, something
the state needed to know more about.
3:25:07 PM
Mr. Mayer discussed some of the specifics of the MOU and
the role of TransCanada. He indicated that he had some
concerns about certain terms of the MOU. He prefaced
himself by saying there were many things he liked about the
relationship with TransCanada. He opined that TransCanada
was a highly capable partner with a strong interest in
expansion. However, he had substantial concerns about the
sharing of risk and reward in the contract. He also pointed
out there were concerns about what to do if the state
sought to finance its portion entirely on its own. He
wanted to know the state's true financial capacity, true
cost of capital, and how the two things compared. If the
legislature was asked to firmly commit to the project in
partnership with TransCanada before other decisions were
made he would be very concerned. As the legislation and
agreements traveled through both legislative bodies he had
been asked a multitude of questions about the specific
timing of things. He had a higher degree of comfort with
what was proposed because of what he had learned in the
process about the timing involved. He relayed that the MOU
was a term sheet that identified the terms that would be a
part of subsequent agreements that the state would
negotiate in more detail at a later date. He mentioned
three fundamental agreements including a pre-set agreement
setting out basic terms, an equity option, and most
importantly a firm transportation services agreement. The
signing of the transportation services agreement was the
point at which the state would make a firm and binding
commitment with TransCanada to build and be bound for
several decades to pay for the capacity built. The terms of
the agreement would be negotiated over the next year or
more and brought before the legislature for approval. Until
then, the initial preceding agreements would be implemented
including the termination of AGIA. One of the things that
gave him additional confidence in the project was the
requirement found in the enabling legislation that mandated
the state to conduct a study of its financing options
without TransCanada's involvement. He would feel capable of
understanding the state's choices being able to look at the
study and assess costs and benefits associated with each
option.
3:29:56 PM
Mr. Mayer reiterated the focus on current decisions versus
decisions later. He proposed that the state wait for the
negotiation process to take place before making decisions.
He believed making a decision and getting locked in at
present, would not be in the state's best interest.
Co-Chair Austerman indicated he would allow some questions.
However, he cautioned members to study the bill. Co-Chair
Stoltze added that SB 138 was officially transmitted to the
committee.
Representative Holmes asked about having the administration
come back to the committee to review the sectional
analysis. Co-Chair Stoltze confirmed that the
administration would come before the committee again. Co-
Chair Austerman indicated the importance of reviewing the
bill in order to know what questions to ask.
Representative Gara asserted that fundamental policy calls
should be made at present rather than later. He
communicated that the current contract required the state
to reimburse TransCanada hundreds of millions of dollars if
the project did not move forward. The state would have
invested millions without knowing whether the project would
be successful. He mentioned market changes and producer
decisions that could influence or stop forward progress of
the project, items out of the state's control. He recalled
Mr. Marks specifying that with the risk of paying so much
money up front, other sovereigns received higher state
shares than was anticipated for Alaska. He asked Mr. Mayer
to comment.
3:33:16 PM
Mr. Mayer did not agree that all sovereigns had a higher
state share. He agreed with Mr. Marks' characterization
that by-and-large sovereigns that took the most risks did
so through national oil companies.
Representative Gara reiterated that by-and-large,
sovereigns that took the most risk received the greatest
return, larger than Alaska's share.
Mr. Tsafos responded that he was not sure if the causation
was correct. He commented that states that had bigger
shares and had a 70 or 80 percent share of an LNG project
naturally assumed the costs of studying an LNG project. He
was not sure the causation was that the less the state paid
up front the more the state received later.
3:34:33 PM
Representative Gara asked about the maximum state liability
for the state's share and TransCanada reimbursement costs
if the project was halted at decision time.
Mr. Tsafos referred to slide 30 [SOA'S Cash Calls and Off
Ramps] of the presentation from March 28, 2014. He
estimated the total cost to the State of Alaska to be
approximately $600 million through the pre-feasibility and
feasibility stages with the exclusion of TransCanada. The
costs could increase with additional studies. The state's
liability to TransCanada was whatever portion of the 25
percent ownership TransCanada financed plus 7 percent
interest. If the state was to abandon the project at the
time the work was done, it would be liable to TransCanada
for $150 million to $400 million. However, he conveyed that
spending would increase as confidence in sanctioning the
project increased based on the results of the studies. If
the studies provided doubts on the viability of the project
the state would be less likely to spend its money. The
range of what the state would owe depended upon whether the
state exercised the equity option.
Representative Gara restated his question about the maximum
dollar amount the state would be liable for at the time a
decision was made whether to abandon the project. Mr.
Tsafos responded with $700 million including the 7 percent
interest paid to TransCanada.
3:38:13 PM
Representative Wilson wondered if partnering with
TransCanada was the best way out of AGIA or the best
partner for the State of Alaska. She inquired whether Mr.
Tsafos would seek TransCanada as a partner for the AKLNG
project. She expressed her concern about the concessions
the state would make with TransCanada based on its previous
agreement under AGIA.
Mr. Tsafos responded that rather than advocating in favor
or against a partnership with TransCanada his job was to
assist lawmakers in examining potential trade-offs and
options for the state. He opined that the state would not
be on the path that it was currently on if the AGIA license
and obligation were not at play. If the state was starting
from scratch there would be several options for it to
consider. He suggested that one of the questions the state
needed to ask itself was whether it wanted a pipeline
partner. A partner such as Citibank did not have the
technical expertise that another partner would be able to
offer. The state needed technical knowledge and could
either hire it or find it in a partner. He furthered that a
partner with a stake in the results of the decisions being
made would have more of a buy-in than a consultant. He was
unclear whether or not it would be worth hiring a
consultant versus paying TransCanada 7 percent of
approximately $50 million over the next 18 months for a
pre-feasibility study.
3:41:56 PM
Mr. Tsafos discussed alternatives to TransCanada. He
referenced a benchmark study that he reviewed with the
committee previously regarding tariff terms. He mentioned
that, in particular, the 75/25 capitalization ratio, which
yielded a low tariff return, was attractive. PFC Energy put
out a document called the "PFC Energy 50" that provided a
list of the 50 largest market capital companies. He looked
at the segment analysis of the different companies
including the midstream infrastructure segment. The ranking
of market capitalization companies as of December 31, 2013
included Enterprise with a market cap of $62 billion,
Kinder Morgan with a market cap of $37 billion, Enbridge
with an market cap of $36 billion, TransCanada with a
market cap of $32 billion, Energy Transfer Partners with a
market cap of $24 billion, Williams with a market cap of
$22 billion etc. Although "market cap" was not the only
measure to look at, it indicated which companies would be
willing and able to take on a $6 billion commitment. He
indicated TransCanada, the only company that qualified
under AGIA, emerged out of a process. He recommended asking
why there were more parties interested in the AKLNG project
than the AGIA project, understanding that the projects were
fundamentally different. He remarked that it was possible
for the state to negotiate a better deal, but he could not
guarantee it. He reemphasized the importance of the firm
transportation agreement and knowing when it would become
final.
3:44:38 PM
Representative Wilson suggested that all of the consultants
come back to the table at the same time in order for
committee members to address their questions and concerns.
Co-Chair Austerman indicated that he shared the concerns of
other committee members. He was unsure if TransCanada was
the right choice or if the state should find its own
funding and join together with the producers out to bid. He
hoped some answers to his questions would become clear
looking at the bill. He stated that he had more concerns
with the MOU than with the HOA. He intended to focus on
better understanding the MOU.
Co-Chair Stoltze commented that although the consultants
could not give the state its answers, they could provide
tools and the best information possible. He relayed that
the committee would do its best with the limited time and
information it had.
Co-Chair Austerman discussed the schedule. Co-Chair Stoltze
announced that public testimony would be taken in the
morning at 8:00 am and discussed additional housekeeping.
ADJOURNMENT
3:48:08 PM
The meeting was adjourned at 3:47 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| AKLNG Roger Marks Evaluation Report 4-11 HFIN.doc |
HFIN 4/11/2014 1:30:00 PM |
AKLNG SB138 |
| Marks SB 138 HFIN AKLNG 4-11-14.pdf |
HFIN 4/11/2014 1:30:00 PM |
SB 138 |