Legislature(2011 - 2012)HOUSE FINANCE 519
03/23/2012 09:00 AM House FINANCE
| Audio | Topic |
|---|---|
| Start | |
| HJR16 | |
| HB9 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| += | HB 9 | TELECONFERENCED | |
| += | HB 64 | TELECONFERENCED | |
| += | HJR 16 | TELECONFERENCED | |
HOUSE BILL NO. 9
"An Act requiring the Joint In-State Gasline
Development Team to report to the legislature
recommended changes to state law that are required to
enable or facilitate the design, financing, and
construction of an in-state natural gas pipeline so
that the in- state natural gas pipeline is operational
before 2016; and providing for an effective date."
9:55:27 AM
LARRY PERSILY, FEDERAL COORDINATOR, ALASKA NATURAL GAS
PROJECTS, FEDERAL COORDINATOR'S OFFICE, WASHINGTON D.C.
(via teleconference), clarified that he did not want to
tell state government what to do on any proposed
legislation. He provided a highlight of current market
conditions in Asia and the Lower 48 related to U.S. Liquid
Natural Gas (LNG) export project financing. He would
provide an overview of the potential for LNG exports,
whether LNG prices would remain high in Asia, whether
Alaska could compete on price, and whether the U.S. market
would ever recover. Cheniere Energy (Cheniere) was
currently the only company that had the U.S. Department of
Energy (DOE) approval to export U.S. gas to non-free trade
nations including China and Japan; 8 other projects were
pending while DOE awaited a study on natural gas export
that would look at how it would affect the U.S. Gross
Domestic Product (GDP), the economy, consumer prices, and
other. He relayed that Cheniere did not currently have the
Federal Energy Regulatory Commission (FERC) certificate;
however, it was expected to be granted shortly and the
company hoped to begin construction during the present
year.
Mr. Persily discussed that Cheniere opened as an LNG import
terminal in 2008/2009 when people believed that the U.S.
would be short of natural gas. The plant had a "huge"
import terminal that had the capacity to take in and
distribute 4 billion cubic feet per day; however, the
market had changed and the U.S. was not buying natural gas.
As a result the company's debt was downgraded to junk. The
company had looked at higher prices in Asia and decided to
convert to a dual-use facility by incorporating
liquefaction and shipping into its receiving and
regasification capabilities. He stressed that customers
were needed for the success of a project.
Mr. Persily shared that Cheniere had succeeded in signing
up four customers (BP Group, Gail India, Korea Gas
Corporation, and Spain's largest gas and power utility
company Gas Natural Fenosa) for 20 years at approximately 2
billion cubic feet per day. The first two production trains
were scheduled at Cheniere's Sabine Pass terminal by 2016;
the second two were scheduled for 2017. He elaborated that
all four companies had signed the equivalent of
shipper/taker pay contracts that were more appropriately
termed use-or-pay contracts. The companies had all agreed
to pay between $2.25 and $3.00 per million British Thermal
Unit (BTU) to reserve liquefaction capacity at the plant
for 20 years even if they did not use it; the contracts
represented binding commitments in the amount of $45
billion over the 20 year period. Cheniere had until the end
of 2012 to get its FERC certificate and financing in line
or the companies could bail out on the commitment. He
elaborated that the only way the company could get
financing was through contracts where another company would
pay the debt. The contracts called for the customers to buy
gas based on U.S. Henry Hub prices plus a 15 percent
upcharge for the gas that would be consumed during
liquefaction. He detailed that the costs of the
liquefaction charge, the price of gas, and the cost of a
tanker traveling to Asia would be used to determine the
cost in Asia; a Henry Hub gas price of $3.00 would mean an
LNG price in Asia of approximately $9.00; $6.00 gas in the
U.S. would mean a price of about $12.00 in Asia.
Historically LNG prices in Asia had been tied to global oil
prices, but the Cheniere contract was tied to U.S. natural
gas prices. The cost of the liquefaction plant and
improvements would be approximately $10 billion; the
company had obtained $2 billion in private equity financing
from Blackstone and would get the rest by issuing debt.
Cheniere would accrue interest at approximately 17 percent
on its construction financing.
Mr. Persily reiterated that there were eight other pending
projects in the U.S. and a few more out of British
Columbia. He stated that the market would decide the
projects that would move forward and that would obtain
financing; the market would not support 12 export projects.
Mr. Persily moved on to address the Asian market in
general. He detailed that Australia currently had eight LNG
export projects under development, which represented
approximately $180 billion.
10:02:43 AM
Mr. Persily detailed that the Australian projects would
quadruple the country's export capacity to more than 10
billion cubic feet per day; by 2017 the country would
overtake Qatar as the world's leader. Between the two
countries the total LNG export capacity would be
approximately 21 billion cubic feet per day. He detailed
that in 2010 about 29 billion cubic feet of LNG had been
exported/imported internationally. There were currently
expansions, new projects, and developments underway in
Indonesia, Papua New Guinea, Angola, and Russia. He
furthered that in Mozambique the companies Anadarko and ENI
had announced discoveries that totaled 60 trillion cubic
feet; the companies were looking towards Asia as an export
market. He pointed out that the projects all represented
competition, but he acknowledged that the price was very
good in Asia at present. Current spot market prices for
April delivery to Asia were close to $16 per million BTU,
but the market was waiting to see whether Japan would
restart some of its nuclear plants. He stressed that the
outcome could significantly impact long-term prices.
Mr. Persily continued that the high price of energy in
Japan was beginning to effect behavior and utilities were
pushing back looking for ways to cut costs; the executive
director of Tokyo Gas Company was quoted as saying "cutting
raw material costs is one of the major goals." The company
had signed a long-term contract to purchase LNG from a
group project in Australia that would turn coal-bed methane
into LNG; the company executive had reported that costs for
coal-bed methane were significantly lower. He pointed to
pushback in China and India; the Chinese government set the
natural gas price at about $5, which had worked okay until
importers began paying two to three times the amount. The
Chinese government was currently testing the raise of the
cap to $12 per million BTU in two provinces; the hope was
that it would spur increased domestic production. He
explained that at present China produced about 80 percent
of the gas it needs. The prior year it had imported about 3
billion cubic feet of gas per day; split roughly 50/50
between LNG and pipeline gas from Turkmekistan.
10:05:52 AM
Mr. Persily relayed that in January 2012 China buyers had
paid an average of $10 per million BTU of pipeline gas and
a range of $3.50 to $18 for LNG (the low end had been gas
taken on old contracts that had been signed at good prices
and the high end was on current higher prices). India also
set its price of gas and was instituting pricing reform in
order to spur domestic production. He posed the question -
would there be more domestic production in India and China
in the long-term and how would the markets react to higher
prices.
Mr. Persily discussed that current gas prices in the U.S.
were horrendous and were at 10-year lows; the situation was
ugly and was worsening and the country could run out of
storage capacity later in the year. Most industry analysts
believed that eventually supply and demand would regain
balance. He pointed to various forecasts for long-term U.S.
gas prices: Shell projected pricing at $6; Anadarko
expected gas to reach $5 to $7 by 2016; Goldman Sachs saw a
price recovery beginning in 2013; Deloitte predicted gas at
$6.50 in upcoming years. He stressed that the numbers only
represented projections. He believed it made sense for any
producer of oil and gas in Alaska to look at all markets,
but the private money would select the project that would
get built in the U.S. In closing he shared that the risk in
Alaska was great relating to the extensive timeline it took
to build in the state, the cost, and market volatility. He
opined that the state would have to help with the risk in
some way or another if Alaska ever had a sizable gas
project.
Representative Gara asked for verification that spot market
sales tended to be higher than long-term prices. Mr.
Persily responded that it depended on demand, but typically
a premium was paid for spot market sales because the
commodity was not under contract.
Representative Gara surmised that Alaska could not run a
pipeline on spot market prices. He did not believe the
state could routinely start and stop pipeline flow. Mr.
Persily replied that the liquefaction plant was the
problem; the plants did not run well "stop-and-go." A
revenue stream was necessary in order to obtain financing;
long-term financing was needed.
Representative Gara asked whether it was accurate that
Cheniere was aiming at a price of $9 to $12. He wondered
whether it was a fair benchmark for the other potential
U.S. export facilities. Mr. Persily responded that Cheniere
was not a producer; he likened it to a toll road. The
company did not really care what the price of gas was
because it would just make money as the gas moved through
the plant. He added that given the pricing structure it
looked like $3 U.S. gas could be delivered in Japan at
about $9. He remarked that it would be interesting to see
if DOE allowed another export project and if another
project could obtain contracts. He relayed that the whole
industry was watching to determine whether people would
want gas priced to Henry Hub, which was currently lower
than oil prices.
10:10:39 AM
Representative Gara asked whether it was possible to assume
that if any of the other eight companies working to get DOE
approval for export would send gas out at a similar price.
Mr. Persily believed that new export plants would have to
compete on Cheniere's pricing structure. He speculated that
it could be different for a producer; producers moving
their own gas would sell the gas for as much as they could.
He opined that presently many producers would probably be
happy to sell the gas at almost any price due to the
current over supply in the U.S. He shared that there would
be a significant amount of uncertainty around pricing until
a second round of contracts came forward in the U.S. and
commitments were made.
Representative Gara wondered how competitive gas through a
plant in Alaska would be on the Asian market. He referred
to the ASAP report [Alaska Stand Alone Gas Pipeline] that
showed the tariff to Big Lake for a 500 mcf line would be
$7.75. He surmised that the report assumed $2 for the cost
of gas on top of the $7.75.
Mr. Persily shared the same recollection, but noted that he
had not reviewed the report recently.
Representative Gara speculated that it would be another $2
in local gas distribution costs to get from Big Lake to
Nikiski or another tidewater facility. Mr. Persily did not
believe that the cost would be that high on the Enstar
system, but he had never priced the cost out.
Representative Gara asked whether Mr. Persily had a more
accurate number. Mr. Persily replied that someone in the
room or Enstar could probably provide a more accurate
number. He added that unless there was a liquefaction plant
the gas would have to be moved by pipe to tidewater.
Representative Gara asked what the cost of conditioning the
gas at a liquefaction plant would add to the total cost.
Mr. Persily answered that it was very difficult to
estimate. The price Cheniere was charging was public and it
was a fairly cost effective plant because the facility
already had the docks and storage tanks built. The
liquefaction costs would depend on the size of the plant
and how much infrastructure needed to be built. He believed
that when Wood MacKenzie had done its study for the Alaska
Gasline Port Authority the prior year for a very large
liquefaction plant at Valdez (capable of sending out 2.7
billion cubic feet per day) liquefaction costs had been
around $4; the study had acknowledged that the number was a
very rough estimate and that the plant was very expensive.
Any company looking to get into the LNG market in Alaska
would look at the cost and the size of the project to what
the market was willing to pay; if the liquefaction costs
were too high the company would have to figure out how to
reduce them.
10:14:50 AM
Co-Chair Thomas thought it would be cheaper to get gas from
Alaska compared to other locations from around the world
including British Columbia and Mexico. He surmised that
shipping costs would be less expensive from Alaska to Asia.
Mr. Persily agreed. He relayed that tanker charges from
Alaska to Japan would be significantly less than from Texas
or Louisiana to Japan even with the expanded Panama Canal
open in 2014. He had seen estimates that the tanker charge
could be $1.50 to $2.00 less per million BTU; however,
shippers/producers on the Gulf of Mexico coast had the gas
at tidewater. There would be a cost of several dollars to
move the gas from Prudhoe Bay to tidewater in Alaska, which
would wipe out the savings from the shorter tanker run.
From Prudhoe to port in tidewater plus the tanker charge
would have to compete with gulf coast facility tanker
charges and liquefaction costs.
Co-Chair Thomas remarked that that was his point.
Representative Gara asked for a tanker cost estimate from
Alaska to Asia. Mr. Persily had seen estimates for tanker
charges from Alaska of approximately $1 or slightly less
per million BTU. He reiterated that tanker charges were
cheaper, but the transportation cost from the North Slope
needed to be added to the total cost.
Representative Gara estimated that the multiple costs
involved equaled roughly $15.75: $7.75 tariff; $2.00 gas
price; Enstar distribution cost he estimated at $1; $4.00
liquefaction; and $1 tanker costs. He referenced that the
ASAP study acknowledged that its cost estimates could be
off by 30 percent. He wondered how easy it would be for
Alaska to get long-term contracts at roughly $16 gas.
Mr. Persily replied that the specific figures in the ASAP
report were not shown in current dollars; the numbers
assumed some inflation and were a levelized tariff in
dollars of the day over 20 years in the pipeline. He
furthered that it was possible that LNG prices in Asia
could also inflate over time; in the scenario the current
$13 to $15 would be higher over the next 20 years. Company
marketing departments gambled on the issues. He surmised
that Alaska gas would always tend to be on the high cost
side because an 800-mile pipeline with a tariff put the gas
at a cost disadvantage with others.
Representative Gara asked whether there was ample time to
determine if a large pipeline could be constructed that
would produce cheaper gas, given what was known about Cook
Inlet reserves. He noted that the way the legislation was
written the legislature could not stop the project unless
state funds were required.
10:20:37 AM
Mr. Persily could not speculate on the life expectancy or
exploration success in Cook Inlet. He remarked that
everyone would like to see the biggest possible project to
move the most gas because it would provide the cheapest
energy to Alaskans, but he could not say how much gas was
available in Cook Inlet or how long it would last. He was
hopeful that exploration work in the area would be
successful.
Representative Gara believed that if the gasline proposed
in HB 9 was built that consumers would be obligated to pay
for the price and the gas for a long period, given that the
pipeline shipper would not build without a long-term
contract. He wondered what about the length of a contract
that may be required for Alaska consumers.
Mr. Persily could not provide a specific answer, but he
explained that if he wanted to borrow money on a
development the lenders would want to know that he had a
revenue stream that would cover the mortgage. For example,
it would be necessary to convince a lender that there was a
15-year revenue stream that would cover a 15-year mortgage.
He furthered that it would depend how long the debt was
for, which would dictate how long the contract would be to
use the pipe to produce the revenue to pay off the
mortgage. The mortgage could be stretched out over a number
of years with lower payments and higher interest or it
could be accelerated and paid off more quickly.
10:23:20 AM
Vice-chair Fairclough clarified that the legislation did
not specify the size of the pipeline. She remarked that
cost estimates and variables discussed during the meeting
were a speculation. She explained that the bill provided a
framework for the project; the bill required economics, a
safe construction, and other. She stressed that none of the
assertions made regarding the project numbers were included
in the bill.
REPRESENTATIVE MIKE HAWKER, CO-SPONSOR, agreed.
Co-Chair Stoltze thanked Mr. Persily for his time.
Representative Gara MOVED to ADOPT Amendment 13 27-
LS0075\K, which would amend previously adopted Amendment 3
(copy on file):
Amendment 3, Page 2, line 26, after "commission."
Insert:
"The commission may, by order, extend the 180 day
review period by the duration of any delay caused by a
public utility's failure to submit supplemental
information that is available to the public utility."
Co-Chair Stoltze OBJECTED for discussion.
Representative Gara explained Amendment 13 that would amend
previously adopted Amendment 3. He had worked with
Representative Hawker and staff to reach a compromise on
what would occur if the Regulatory Commission of Alaska
(RCA) did not make a decision in 180 days. The current bill
included a provision specifying that the lack of a decision
by the RCA within 180 days was deemed to be approval. The
amendment addressed a situation in which a utility did not
provide the necessary information to the Regulatory
Commission of Alaska, which prevented it from making the
decision within the 180-day timeframe. The amendment
reached a middle ground and allowed the RCA more time if
the utility did not provide the information to the
commission. A party could not withhold information in order
to beat the 180-day deadline.
Representative Hawker concurred and deferred the response
to his staff.
10:26:46 AM
RENA DELBRIDGE, STAFF, REPRESENTATIVE MIKE HAWKER, agreed
that a compromise had been reached; the sponsors were
comfortable with the amendment.
Co-Chair Stoltze WITHDREW his OBJECTION. There being NO
further OBJECTION, Amendment 13 was ADOPTED. He referred to
the fiscal note.
Representative Hawker remarked that the sponsors had
endeavored to provide the committee with the best possible
resources.
Vice-chair Fairclough pointed to the fiscal impact note
from the Department of Revenue. The note would provide an
allocation to the Alaska Gasline Development Corporation
(ADGC) and funded varying position counts including, 22 in
FY 13 (7 of which were included in the governor's request),
45 in FY 14, 48 in FY 15, 61 in FY 16, and 54 in FY 17 and
FY 18. The total cost included in the governor's FY 13
request was $3,629,400.
Representative Neuman thought that Amendment 13 was worded
incorrectly. Co-Chair Stoltze would come back to the issue
after the fiscal note discussion.
Representative Gara asked whether the ADGC cost estimate
associated with the legislation was approximately $400
million to get to project sanction.
JOE DUBLER, VICE PRESIDENT AND CHIEF FINANCIAL OFFICER,
ALASKA GASLINE DEVELOPMENT CORPORATION AND DIRECTOR OF
FINANCE, ALASKA HOUSING FINANCE CORPORATION, DEPARTMENT OF
REVENUE, replied that the total estimated cost for the pre-
sanction activity would be $400 million. Approximately $30
million in costs had been incurred to date; therefore,
about $370 million in additional funds would be necessary.
Representative Gara wondered why the cost was not in the
fiscal note.
Mr. Dubler replied that the fiscal note included $286
million in capital costs to get through FEL 2 (i.e. stage
2) and an open season. Subsequently ADGC would need an
additional appropriation to continue the project into its
third and final phase (pending a successful open season).
Representative Gara asked for verification that the second
appropriation would bring the total up to the $400 million
figure. Mr. Dubler replied in the affirmative.
Representative Guttenberg pointed to a graph on page 2 of
the fiscal note and wondered whether the first column
should read "FY12" instead of "FY13." Mr. Dubler responded
that the numbers were for FY 13 and were intended to
conform to page 1; the $3.6 million in the second column
was included in the governor's request and the first column
showed the appropriation requested for the FY 13 capital
budget.
Representative Gara wondered whether he could ask Mr.
Dubler the questions that Mr. Persily had not been able to
answer earlier in the meeting related to the ASAP project
cost estimates.
Co-Chair Stoltze asked whether the questions were related
to the fiscal note.
Representative Gara replied that the questions were related
to the cost of the project.
10:31:55 AM
AT EASE
10:33:44 AM
RECONVENED
Co-Chair Stoltze brought attention back to the fiscal note.
Vice-chair Fairclough clarified the record related to the
Amendment 13. She explained that the amendment was specific
to Amendment 3 that had been previously adopted.
Vice-chair Fairclough MOVED to report CSHB 9(FIN) out of
committee with individual recommendations and the
accompanying fiscal note.
Representative Gara OBJECTED for discussion. He pointed to
page 310 of the ASAP project plan. He understood that the
more preferable scenario was the 500 mcf line. Figure 3-3
assumed the export of 250 mcf possibly from Nikiski. He
referenced a tariff to Big Lake at $7.75.
Mr. Dubler explained that the 3-3 used inflated dollars for
the 500 mcf base case estimated tariff. Figure 3-4 included
current dollars at $5.63. He communicated that it was not
appropriate to compare the number with current dollars.
Representative Gara surmised that the inflated figure
represented what the tariff would cost in the future when
the gas was potentially delivered. Mr. Dubler answered in
the affirmative; the number reflected a 3 percent per year
inflation rate.
Representative Gara asked for verification that ADGC
estimated a $2 cost for gas. Mr. Dubler responded in the
affirmative.
Representative Gara asked for the ADGC cost estimate for
distribution from Big Lake to tidewater. Mr. Dubler replied
that the only thing that ADGC assumed was the gas to Big
Lake. The liquefaction producer would bring the gas from
Big Lake to its facility; the figure was included in the
ADGC liquefaction process cost estimates.
Representative Gara asked what the additional increment
would be for liquefaction and transportation between Big
Lake and tidewater.
Co-Chair Stoltze asked Mr. Dubler to continue the
conversation with Representative Gara outside of committee.
Mr. Dubler replied in the affirmative.
Representative Doogan pointed to FY 13 estimated capital
costs included in the fiscal note and wondered whether the
$286 million figure plus $200 million that had already been
appropriated represented the total cost. Mr. Dubler
responded in the negative. He explained that the $286
million would be the expenditure of the $200 million plus
some additional expenditures submitted by different
departments related to work on the project (Department of
Environmental Conservation, Department of Natural
Resources, Department of Transportation and Public
Facilities, and other).
Representative Doogan thought he heard a $400 million
figure referenced.
Mr. Dubler replied that $400 million was the total capital
expenditure estimate that would be required up to the
sanction process; the $286 million represented a portion of
the $400 million figure.
Representative Doogan surmised that the total cost would be
the $286 million plus the balance that would reach $400
million. Mr. Dubler clarified that the balance would be
less the amount that had already been expended.
10:39:20 AM
Representative Wilson asked for verification that the costs
and tariffs would be divided by users throughout the state.
From Dunbar to Fairbanks (including a straddle plant if
needed) would be paid by the Fairbanks users. From Dunbar
to the end location in Anchorage (plus a straddle plant if
needed) would be paid by Anchorage. She surmised that
Anchorage would pay a tariff of $9.63 and Fairbanks would
pay $10.45, which represented an $0.82 difference per
million BTU. Currently Fairbanks was paying $23.35;
therefore, it would see a 55 percent decrease in gas price.
She believed there would be a 66 percent decrease the more
the community "got off of heating oil."
Mr. Dubler responded in the affirmative. He added that
Anchorage would have a less than 10 percent increase in the
cost of gas. He stated that the project would supply gas to
Fairbanks and Anchorage for an indefinite amount of time.
Representative Wilson recognized that the legislation was
not perfect, but she believed the momentum needed to
continue on the framework and figures; therefore, she
supported the bill. She communicated that Fairbanks would
watch closely to ensure that the figures did bring
affordable gas to the community.
Representative Doogan commented that he had not been
present for the prior night's meeting due to health reasons
and he expressed intent to offer at least one amendment on
the House floor.
A roll call vote was taken on the motion to report the bill
out of committee.
IN FAVOR: Fairclough, Joule, Neuman, Wilson, Costello,
Doogan, Edgmon, Stoltze, Thomas
OPPOSED: Gara, Guttenberg
The MOTION to report the bill from committee PASSED (9-2).
There being NO further OBJECTION, it was so ordered.
CSHB 9(FIN) was REPORTED out of committee with a "do pass"
recommendation and with one new fiscal impact note from the
Department of Revenue.
Co-Chair Thomas highlighted that the opportunity to truck
gas to Tok, Delta, Haines, or other had not ever been
mentioned in the discussion. He would vote for the bill,
but wanted people to understand that there was more to
Alaska than Anchorage, Fairbanks, and Mat-Su.
Representative Guttenberg remarked that he had brought the
issue up.
Representative Hawker assured Co-Chair Thomas that the
sponsors had been prepared to respond to the questions. He
relayed that a significant focus of the bill was about
establishing a backbone that would provide a way to get the
majority of the gas from the North Slope reserves to
tidewater in Southcentral. The bill specifically empowered
ADGC to bring gas to any communities that could be reached
in an economically feasible way, which included the propane
project on the Yukon River that the Alaska Natural Gasline
Development Authority had worked on. He communicated that
it would then be up to the legislature to develop a vision
for future development. He referenced a Norwegian model
that used a fleet of compressed natural gas tankers that
could work off of tidewater to provide coastal deliveries
around the state. He stated that the legislature's own
vision was the only limitation on what could be served in
Alaska.
Representative Edgmon agreed with the comments made by Co-
Chair Thomas. He thanked the sponsor for adding intent
language that further clarified that the application could
be statewide in nature. He believed that natural gas would
be the great equalizer in terms of bringing affordable
energy to all areas of the state.
Co-Chair Stoltze thanked the staff and committee for the
hours spent on the legislation.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB009CS(RES)-NEW_DOR-AHFC-03-22-12 Attachment #2.pdf |
HFIN 3/23/2012 9:00:00 AM |
HB 9 |
| HB009CS(RES)-NEW FN DOR-AHFC-03-22-12.pdf |
HFIN 3/23/2012 9:00:00 AM |
HB 9 |
| HB009CS(RES)-DOR-AHFC-03-12-12 Attachment #1.pdf |
HFIN 3/23/2012 9:00:00 AM |
HB 9 |
| HB9 Amendment #13.pdf |
HFIN 3/23/2012 9:00:00 AM |
HB 9 |
| HJR16 Sponsor Handout.pdf |
HFIN 3/23/2012 9:00:00 AM |
HJR 16 |