Legislature(2007 - 2008)ANCHORAGE
06/20/2008 09:00 AM House RULES
| Audio | Topic |
|---|---|
| Start | |
| HB3001|| SB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB3001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
JOINT MEETING
HOUSE RULES STANDING COMMITTEE
SENATE SPECIAL COMMITTEE ON ENERGY
June 20, 2008
9:02 a.m.
MEMBERS PRESENT
HOUSE RULES
Representative John Coghill, Chair
Representative John Harris (AGIA Subcommittee, Chair)
Representative Anna Fairclough
Representative Craig Johnson
Representative Ralph Samuels (AGIA Subcommittee)
Representative Beth Kerttula (AGIA Subcommittee)
Representative David Guttenberg
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Charlie Huggins, Chair
Senator Bert Stedman, Vice Chair
Senator Kim Elton
Senator Lyda Green
Senator Lyman Hoffman
Senator Lesil McGuire
Senator Donald Olson
Senator Gary Stevens
Senator Joe Thomas
Senator Bill Wielechowski
Senator Fred Dyson
Senator Thomas Wagoner
MEMBERS ABSENT
HOUSE RULES
All members present
SENATE SPECIAL COMMITTEE ON ENERGY
All members present
OTHER LEGISLATORS PRESENT
Representative Bob Buch
Representative Mike Chenault
Representative Mike Doogan
Representative Les Gara
Representative Carl Gatto
Representative Mike Hawker
Representative Lindsey Holmes
Representative Reggie Joule
Representative Mike Kelly
Representative Gabrielle LeDoux
Representative Jay Ramras
Representative Bob Roses
Senator Hollis French
Senator Gene Therriault
COMMITTEE CALENDAR
HOUSE BILL NO. 3001
"An Act approving issuance of a license by the commissioner
of revenue and the commissioner of natural resources to
TransCanada Alaska Company, LLC and Foothills Pipe Lines
Ltd., jointly as licensee, under the Alaska Gasline
Inducement Act; and providing for an effective date."
- HEARD AND HELD
SENATE BILL NO. 3001
"An Act approving issuance of a license by the commissioner
of revenue and the commissioner of natural resources to
TransCanada Alaska Company, LLC and Foothills Pipe Lines
Ltd., jointly as licensee, under the Alaska Gasline
Inducement Act; and providing for an effective date."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: HB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (H) READ THE FIRST TIME - REFERRALS
06/03/08 (H) RLS
06/03/08 (H) WRITTEN FINDINGS & DETERMINATION
06/04/08 (H) RLS AT 9:00 AM CAPITOL 120
06/04/08 (H) Subcommittee Assigned
06/05/08 (H) RLS AT 9:00 AM TERRY MILLER GYM
06/05/08 (H) House Special Subcommittee on AGIA
06/06/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/06/08 (H) House Special Subcommittee on AGIA
06/07/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/07/08 (H) House Special Subcommittee on AGIA
06/08/08 (H) RLS AT 1:00 PM TERRY MILLER GYM
06/08/08 (H) House Special Subcommittee on AGIA
06/09/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/09/08 (H) House Special Subcommittee on AGIA
06/10/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/10/08 (H) House Special Subcommittee on AGIA
06/12/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/12/08 (H) House Special Subcommittee on AGIA
06/13/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/13/08 (H) House Special Subcommittee on AGIA
06/14/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/14/08 (H) House Special Subcommittee on AGIA
06/16/08 (H) RLS AT 9:00 AM ANCHORAGE
06/16/08 (H) House Special Subcommittee on AGIA
06/17/08 (H) RLS AT 9:00 AM ANCHORAGE
06/17/08 (H) House Special Subcommittee on AGIA
06/18/08 (H) RLS AT 9:00 AM ANCHORAGE
06/18/08 (H) House Special Subcommittee on AGIA
06/19/08 (H) RLS AT 9:00 AM ANCHORAGE
06/19/08 (H) House Special Subcommittee on AGIA
06/20/08 (H) RLS AT 9:00 AM ANCHORAGE
BILL: SB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (S) READ THE FIRST TIME - REFERRALS
06/03/08 (S) ENR
06/03/08 (S) REPORT ON FINDINGS AND
DETERMINATION
06/04/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/04/08 (S) Heard & Held
06/04/08 (S) MINUTE(ENR)
06/05/08 (S) ENR AT 9:00 AM TERRY MILLER GYM
06/05/08 (S) Heard & Held
06/05/08 (S) MINUTE(ENR)
06/06/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/06/08 (S) Heard & Held
06/06/08 (S) MINUTE(ENR)
06/07/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/07/08 (S) Heard & Held
06/07/08 (S) MINUTE(ENR)
06/08/08 (S) ENR AT 1:00 PM TERRY MILLER GYM
06/08/08 (S) Heard & Held
06/08/08 (S) MINUTE(ENR)
06/09/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/09/08 (S) Heard & Held
06/09/08 (S) MINUTE(ENR)
06/10/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/10/08 (S) Heard & Held
06/10/08 (S) MINUTE(ENR)
06/12/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/12/08 (S) Heard & Held
06/12/08 (S) MINUTE(ENR)
06/13/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/13/08 (S) Heard & Held
06/13/08 (S) MINUTE(ENR)
06/14/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/14/08 (S) Heard & Held
06/14/08 (S) MINUTE(ENR)
06/16/08 (S) ENR AT 9:00 AM ANCHORAGE
06/16/08 (S) Heard & Held
06/16/08 (S) MINUTE(ENR)
06/17/08 (S) ENR AT 9:00 AM ANCHORAGE
06/17/08 (S) Heard & Held
06/17/08 (S) MINUTE(ENR)
06/18/08 (S) ENR AT 9:00 AM ANCHORAGE
06/18/08 (S) Heard & Held
06/18/08 (S) MINUTE(ENR)
06/19/08 (S) ENR AT 9:00 AM ANCHORAGE
06/19/08 (S) Heard & Held
06/19/08 (S) MINUTE(ENR)
06/20/08 (S) ENR AT 9:00 AM ANCHORAGE
WITNESS REGISTER
Harold C. Heinze, Chief Executive Officer, Alaska Natural
Gas Development Authority (ANGDA); Delma Bratvold, Science
Applications International Corp.; Gene Dubay, Senior V.P. &
Chief Operating Officer, Continental Energy Systems; Colleen
Starring, Regional V.P., ENSTAR Natural Gas Company; John
Lau, Director of Engineering, ENSTAR Natural Gas Company;
Richard Peterson, Managing Member, Natural Resources-to-
Liquids, LLC; Peter Tijm, Member, Natural Resources-to-
Liquids; Barry Pulliam, Senior Economist, Econ One Research,
Contractor, Legislative Budget and Audit Committee; Bill
Walker, Project Manager and General Counsel, Alaska Gasline
Port Authority; Craig Richards, Attorney, Alaska Gasline
Port Authority.
ACTION NARRATIVE
CALL TO ORDER
The joint meeting of the House Rules Standing Committee and
the Senate Special Committee on Energy was called to order
at 9:02:20 AM.
HB 3001-APPROVING AGIA LICENSE
SB 3001-APPROVING AGIA LICENSE
HAROLD C. HEINZE, CHIEF EXECUTIVE OFFICER, ALASKA NATURAL
GAS DEVELOPMENT AUTHORITY (ANGDA), gave a brief overview of
ANGDA. He noted that ANGDA has been addressing in-state gas
issues and spent six months before submitting an application
under AGIA. The project ANGDA proposed consisted of a spur
line running from Delta Junction through Glennallen to
Palmer and Beluga, in order to capture gas leaving Alaska in
a big pipeline. Without the spur line there would be no way
to get the gas to coastal areas, which are the biggest users
of natural gas. The project has moved forward over the last
several years. They have a conditional right-of-way from the
state covering the area between Glennallen and Palmer. The
other portions of the route follow existing pipeline right-
of-ways; they should be easy to permit and design. Wetland
determination teams have been in the field this summer.
Preliminary work should be done by next summer. ANGDA has
been working with utility companies, particularly the
electric companies, who are major gas users, to get them
organized so that they are prepared to participate in an
open season process. The key question is when the open
season will occur and how well they will be prepared.
9:07:34 AM
MR. HEINZE observed that the issue of North Slope gas to
market must go beyond one big pipe out of Alaska; there
should be many spur lines. Long term perspective must be
kept in mind. He observed that ANGDA has tried to emphasize
that not all Alaskans will be able to share in the energy
source of the North Slope. However, the North Slope gas is
rich in propane, which can be produced and distributed with
minimal effort and 99 percent of Alaskans could potentially
benefit.
9:09:37 AM
MR. HEINZE defined "in-state gas use" as measured in
millions of cubic feet a day (MMcf/d). In 2006, 100 MMcf/d
was used for residential heat and a little over 100 MMcf/d
for residential electricity and light. In addition in 2006,
industry used 250 MMcf/d. He estimated that growth in the
Cook Inlet area would increase the need in heat and light to
250 MMcf/d. In addition, a pipeline through the spine of
Alaska would go through Fairbanks, which would use another
50 MMcf/d. He spoke to future industry needs, which are
harder to predict.
9:12:41 AM
MR. HEINZE pointed out seasonal gas use increases, which
have implications in terms of storage, pipeline
deliverability and other issues.
MR. HEINZE spoke to the cost of service tariff for a number
of different assumed volumes and circumstances. The
benchmark is the Black and Veatch work, which illustrated
that pipeline costs from the North Slope to Alberta would be
about $3.50 [$/mmbtu], not including the treatment plant on
the North Slope, which could make the total tariff could be
higher. ANGDA's estimates are comparable. He referred to the
ENSTAR estimates related to a $3.3 billion bullet line from
the North Slope to Cook Inlet. $2.3 billion of that was
spent to get to Fairbanks. That works out to around $10 if
only 100 MMcf/d moves through. At 250 MMcf/d, the number
drops to $3.50, and then down to $2 at 500 MMcf/d. ("Gas
Pipeline Cost of Service Estimates" from handout "Connecting
Alaskans to Their Natural Gas" (Copy on File)).
9:15:34 AM
MR. HEINZE referred to the threshold needed to build the
line and reviewed the cost of a variety of options. He noted
the $10 would be paid by the consumer, which seems like a
lot, but Fairbanks currently pays over $22 for their gas. A
large pipeline would decrease cost to $1.25, a dramatic
difference. He reviewed the numbers for Cook Inlet
consumers.
MR. HEINZE concluded that the scope of the line needs to be
determined and emphasized the importance of getting to an
in-state open season as soon as possible. He felt that the
spur line offered the best opportunity for reduced cost in
the long term. Large volumes are more tariff efficient.
9:19:22 AM
MR. HEINZE maintained that Alaska should retain some value
advantage in terms of gas over the rest of the United
States. He hoped the state could preserve the opportunity to
be at least at the discounted price level.
MR. HEINZE urged the legislature to promptly approve the
AGIA license to TransCanada; ANGDA believes that would keep
the maximum amount of momentum and competition to negotiate
and make things happen. A big pipeline built sooner would be
advantageous for in-state service. Buying and shipping gas
in a big pipe and a spur line could require a commitment
from the state of over $10 billion. Alaskan utilities don't
have that kind of money, but they have the customers that
will pay for utilities over the long term. He spoke in
support of an aggressive timeline as the best chance of
striking a favorable long term deal for Alaska.
9:22:33 AM
REPRESENTATIVE RALPH SAMUELS questioned what would happen if
the state chose to build the bullet pipeline with state
capital and not fold the cost into the tariff. He asked if
it would cost $3.5 billion and how that would affect
Anchorage and Fairbanks tariffs.
MR. HEINZE agreed the volume range to meet Alaska's gas
needs would be between 100 and 250 MMcf/d. If the state put
up $3.3 billion for a bullet line, tariffs would be close to
zero. Operating costs associated with a pipeline are very
low.
REPRESENTATIVE SAMUELS concluded that if the gas was used in
state, FERC would not require the state to get the capital
back through the tariff.
MR. HEINZE responded that the gas would be intra-state gas
and would be solely the jurisdiction of the Regulatory
Commission of Alaska (RCA). If the money were put up with an
expectation of zero rate of return, the tariff could
conceivably be approved within 12 months.
9:25:43 AM
REPRESENTATIVE SAMUELS questioned how the deal would work
between ENSTAR and the producers.
MR. HEINZE explained that the state would fund and build an
in-state line, which would not have a toll other than
operating expenses. The state would not own the gas; whoever
wanted gas would ship it. If a company like ENSTAR wanted
gas on the south end of the line, they would go to the north
end and buy gas, or they would buy it from a company that
has already shipped it down. This would be limited to an
Alaskan market. The price would be as high as the next
cheapest alternative.
9:27:34 AM
REPRESENTATIVE RAMRAS recalled when the legislature passed
the resolution asking for a focus on small diameter
pipelines and the governor's approach was to set aside $4
million for ANGDA. He asked what ANGDA was doing to address
that resolution, which was responsible for the governor's
response for the $4 million, to try and talk about a small
diameter pipe that can happen in a time frame that is sooner
than AGIA.
MR. HEINZE clarified that ANGDA received $4 million to study
gas related issues. The money comes due July 1, 2008. ANGDA
intends to move ahead with those things that directly
influence how big the market is in Alaska, and identify
industrial users that might be interested in coming to
Alaska and help pay the bill. There are a number of similar
issues; for example, ANGDA recently hired Tony Izzo as the
Gas Supply Coordinator. He would be working with local
electrical utilities to find a way to be of maximum
assistance to them. He noted that in relationship to AGIA,
ANGDA supports the granting on the license in the belief
that that puts the process on a competitive commercial
basis. They believe that is the best opportunity to achieve
in-state service.
MR. HEINZE reiterated that once AGIA is settled, and two big
pipelines moving forward, then the spur line becomes real.
When he talks to financial people outside of Alaska about
the spur line, the biggest problem is that they know there
is no gas in Delta Junction. Once people believe a big
pipeline will happen, then it becomes much easier to work
towards a spur line. In that mode ANGDA intends to take any
steps to accelerate the timeline. For example, ANGDA has
always advocated that the spur line be built as a pre-build
into the big pipeline, that it be built and ready for the
big pipe. They have advocated that the northern section be
built first in preference to the Canadian section, and so
on. There will not be an opportunity to make good decisions
about the spur line until the bigger project is well
underway.
MR. HEINZE stated that he did not feel that there was enough
information yet to warrant a commitment about which way to
go. The goal is to get to open season by the first of next
year.
9:32:52 AM
REPRESENTATIVE RAMRAS questioned ANGDA's interpretation of
the way to spend the $4 million for a spur line to be
attached to the AGIA line in the year 2020, which does not
help interior Alaskans now. He asked if ANGDA had any sense
of urgency.
MR. HEINZE repeated that the language was the language
chosen by the legislature, rather than the language of
instruction he would have preferred; ANGDA was restricted to
looking at market as opposed to a project. Regarding the
immediacy of the energy situation, he described being in
Fairbanks and discussing propane and getting a facility
going on the North Slope within one year. He also wanted to
use some of the money to study and advocate for a 40 mile
pipeline into Fairbanks from the Nenana Basin to expedite
getting the gas to Fairbanks.
9:35:02 AM
REPRESENTATIVE MIKE DOOGAN referred to the slide on demand
and asked if it showed current demand with some increases
for growth in population.
MR. HEINZE replied that the slide represents a reasonable
growth in demand.
REPRESENTATIVE DOOGAN asked if there were a provision for
people lowering use.
MR. HEINZE responded that homeowners don't have a lot of
good alternatives. There could be an effect, but it was not
considered in the figures.
REPRESENTATIVE DOOGAN turned to the slide with the tariffs.
He asked if the actual price would have to include producer
costs.
MR. HEINZE replied that the numbers reflected only the cost
of the pipeline and that there may be other costs associated
with preparation of the gas, shipping, distribution, and so
on.
REPRESENTATIVE DOOGAN clarified that the total delivery
charge could be in the $6.50 range.
MR. HEINZE answered that if the volume numbers are towards
the higher end of the scale, the price is less because of a
tariff break. Building the pipeline would require a 20-30
year commitment. He did not think anyone wanted to sign a
purchase agreement with a floating price for that length of
time. ANGDA wants a price decided on.
REPRESENTATIVE DOOGAN responded that people seem to use
"availability of gas" and "cheap gas" as if they were the
same thing, but they are two different things.
MR. HEINZE added that the supply has diminished in Cook
Inlet. There is no assurance of a long-term supply. There is
also the issue of deliverability. Both issues are addressed
by bringing North Slope gas in. In addition, North Slope
gas, in an open season process, may provide the opportunity
to cut a deal for purchase and shipment for the next 20-30
years that basically gives a stable energy cost environment.
He recalled a recent 30 percent price increase. The only way
to get away from those is a longer term commitment. He
referred to a company that made a long-term deal which was
controversial at the time, but resulted in price stability.
REPRESENTATIVE DOOGAN asked if the utilities would be better
off with a negotiated rate rather than depending on FERC to
set the rate.
MR. HEINZE thought that if state could act decisively in the
next year, whether choosing Denali Pipeline or TransCanada,
ANGDA could assess needs and willingness to commit. That
would not affect financing in any big way, but the utilities
are an important piece. If Alaska has to assert any of its
concerns through the FERC process, it makes it difficult for
everybody.
REPRESENTATIVE DOOGAN asked if whoever built the pipeline
would be better off going to FERC with a completely
negotiated agreement about who the gas would be provided for
and prices.
MR. HEINZE responded that when a tariff is filed, there
should have been a strong effort to bring the parties
together. He cited an example in Wyoming of competing
pipelines in a heated competition.
9:44:18 AM
SENATOR THOMAS WAGONER asked for the conversion between a
gallon of propane and one MMcf of methane.
MR. HEINZE said he would get that information.
SENATOR WAGONER asked about an off-take at the Yukon point
for propane. He wondered if it would make better sense to
have an off-take at Delta Junction with a straddle plant,
and to process there for shipment to the villages.
MR. HEINZE explained that a big pipeline would carry a lot
of molecules other than methane: ethane, propane and butane
as well. Each of those other molecules can be separated by
just taking a side stream and running them through a fairly
simple process at a straddle plant. Simply cooling the gas
causes the propane/butane drops out. ANGDA expects there
will be propane facilities all along the pipeline because at
every compressor station, step one of conditioning the fuel
to be put in the turban unit is to drop out the
propane/butane. He reiterated that there will be wholesale
propane facilities at least at every 150 miles along the
pipeline. He continued that ANGDA believes that it is
important to keep the ability to put a large straddle plant
at Delta Junction, one that might be capable of assuring
that there was up to 75,000 barrels a day of ethane
available. That is a big plant, costing billions of dollars.
ANGDA wants the state to have the possibility of making
those kinds of decisions in the future.
MR. HEINZE referred to the pay-offs to Alaska in terms of
value for our gas and in terms of jobs and plants and the
tax base.
9:46:46 AM
REPRESENTATIVE SAMUELS wanted information about the capital
cost difference between the 100 MMcf/d and 250 MMcf/d
estimates.
MR. HEINZE answered that the capital cost is the same in all
cases.
REPRESENTATIVE SAMUELS described a hypothetical of giving
ANGDA $4 billion for a bullet line right now. He asked how
long before the gas could be used in a home in Fairbanks.
MR. HEINZE observed that, presuming a 24 inch pipeline,
moving a project forward rapidly would take a couple more
years of preliminaries and three years to build. The biggest
issue would be what is at each end of the pipe, especially
the north end.
REPRESENTATIVB SAMUELS thought that it was a matter of
public policy to take care of the in-state gas needs. He
asked how expandable the 250 would be.
MR. HEINZE said that ANGDA used ENSTAR's numbers for a 20
inch pipeline. The numbers could be low, but he thought the
20 inch high pressure pipe could be capable of 750 MMcf/d. A
24 inch pipe could carry 1.25 bcf/d.
REPRESENTATIVE SAMUELS queried about expansion to Nikiski
with a zero tariff. He wondered if FERC would seize control.
9:51:57 AM
REPRESENTATIVE BOB ROSES wondered how ANGDA had enough data
to endorse AGIA if they did not have enough data to decide
how the spur line should go.
MR. HEINZE clarified that he didn't have enough data in
terms of volumes on the chart. The direction of ANGDA is
guided by what would be the best long term deal for the
Alaskan consumer. While they are interested in market forces
that affect the bigger project, the focus is on Alaskans. On
the chart it is clear that the spur line offers advantages.
He thought it would be a mistake to abandon the possibility
of a competitive, big pipe that a spur line could connect
with.
REPRESENTATIVE ROSES stated that he wanted competition as
well. He asked if there had been discussions with Denali.
MR. HEINZE reported that discussions with Denali have been
very limited, although there had been good dialogue with
ConocoPhillips during the Alaska Stranded Gas Development
Act (SGDA) considerations. ANGDA was glad that Denali has a
leader but there has been no meaningful discussion. He had
no reason to think Denali would not be open to discussion.
REPRESENTATIVE ROSES wondered if ANGDA shared the concern
that came out during public testimony about limiting options
by granting TransCanada the license.
MR. HEINZE responded that granting the license would
effectively accelerate the timeline and promote openness. He
referred to a recent report that Denali was opening a docket
with FERC. He thought this created good competition. He
related a story about well drilling and competition. He
emphasized that leverage is needed as Alaska is a small
competitor.
REPRESENTATIVE ROSES questioned whether pushing forward with
the license would prohibit the state, because of the non-
competitive clause on subsidizing other companies, from
encouraging other companies.
MR. HEINZE replied that ANGDA's considerations flagged only
the term "grant of money." The phrase would only apply to
ANGDA. No one else has said that anything in the provision
prevents them from doing what they want. The language is
fine for an in-state spur line. For greater volumes, over
500 MMcf/d, there is a successful in-state market. All
discussions with TransCanada indicate that the spur line and
that volume are good. They make money and the consumer wins.
SENATOR DYSON stated concerns about the impact of a spur
line on Cook Inlet and Nenana Basin exploration and
production, especially related to added incentives. He
worried that spending the money on the spur line would shut
off new gas exploration in those basins.
MR. HEINZE commented on the Nenana Basin. If there was
anything there he would like to see gas taken directly to
Fairbanks or making electricity and shipping the electrons
both north and south on the intertie. He did not think the
spur line had anything to do with what was happening in
Nenana Basin. He wished them well.
MR. HEINZE acknowledged the potential for development in
Cook Inlet, as long as the price structure is reasonably
supportive. He thought development would happen regardless
of a spur line. The commerciality of moving ahead makes
sense regardless of what we do about a spur line. If there
were a discovery of a large deposit of gas, the spur line
would be popular because it goes the other direction as
well. These kinds of longer term infrastructure developments
can fit with a wide variety of actualities.
9:59:38 AM
SENATOR DYSON wanted to know how much gas was in the Basin
before committing to a spur line. However, having a spur
line in place that would move Cook Inlet gas was also very
attractive. He asked if exploration in either basin would be
inhibited in any way by the spur line.
MR. HEINZE admitted that it was difficult to tell. He did
not think the prospect of a spur line would affect
exploration and development.
SENATOR DYSON asked if gas from new discoveries in Cook
Inlet would be cheaper for the consumer because there would
not be the capital cost to amortize. He questioned how much
incentive Cook Inlet lease-holders had to drill now because
the small increments in consumer demand would not make it
worth it. He thought the large industrial contracts were
important as anchor tenants for the gas sales.
MR. HEINZE commented that the current Cook Inlet market is
an isolated market, a small group of producers to a small
group of consumers. He said the advantage of considering the
North Slope gas coming into the area is that it is a huge,
multi-generational supply that gives the opportunity for a
long term deal.
SENATOR DYSON asked if the gas from the North Slope would be
significantly more expensive in Southcentral than gas from
new discoveries in Cook Inlet.
MR. HEINZE referred to the chart and said the price would be
comparable to gas prices in other parts of the United
States. If the basin remains isolated, the price might have
to rise higher. The clearing price might be set by liquid
natural gas (LNG) imports into Cook Inlet, which would mean
a price higher than the North Slope.
10:08:20 AM
SENATOR HOLLIS FRENCH said an Anchorage hearing was planned
to explore what the state can do within the confines of AGIA
related to assisting the development of in-state gas. He
asked why purchase agreements are important for a spur line.
MR. HEINZE advised that utilities need a long term supply of
gas. A company like Exxon might be interested in having a
relationship with an electric company over twenty years
because they have opportunities to make money on money that
they do not spend. The state, on the other hand, could bond
at a very low interest rate, and against the pledge of
monthly household payments for twenty years, broker a deal
that bridges between the utility's monthly cash flow and the
long-term purchase of gas in the ground.
SENATOR FRENCH asked how important the purchase agreements
were to the success of a spur line.
MR. HEINZE did not think they were important at all.
Everybody who has gas on the North Slope would like to sell
into the in-state market because they only pay 5 percent
severance tax, not 25 percent. It is a limited market;
whoever gets there first gets it. That is why Exxon might be
willing to make a twenty year deal.
10:11:36 AM
REPRESENTATIVE CARL GATTO asked if it was possible to run
non-pipeline quality gas all the way into a gas turbine to
generate electricity and not blow the turbine blades because
of the presence of carbon dioxide.
MR. HEINZE explained that the costly part of the gas
treatment plant in Prudhoe Bay is removing the carbon
dioxide, which saves moving an inert molecule, thereby
reducing the volume of the gas by 10 percent. There may be
limited opportunities downstream to remove it as other
things are done with the gas, especially interfacing with
other pipeline systems unwilling to accept the carbon
dioxide. On the other hand, pipeliners don't like carbon
dioxide because with water it creates carbonic acid, which
leads to corrosion and other problems. If the only use of
the gas is to burn it, which makes water and carbon dioxide,
the presence of the carbon dioxide doesn't matter. Turbines
and stoves work fine on Prudhoe Bay gas with the carbon
dioxide still in it.
MR. HEINZE emphasized that carbon dioxide removal is
absolutely necessary if you are making LNG. Different
pipelines tolerate different amounts of carbon dioxide.
10:14:35 AM
REPRESENTATIVE GABRIELLE LEDOUX thought the AGIA process was
spurring the competition with Denali Pipeline. She wondered
if it would be better to wait on AGIA.
MR. HEINZE replied that deciding to not vote on the issue is
a no vote. He liked the people at Denali Pipeline, but he
did not have commitments from them. If the AGIA license was
approved, he would at least have some leverage.
10:16:29 AM
SENATOR LESIL MCGUIRE commented that if AGIA were voted
down, there would still be ANGDA, the legislature, the
governor, TransCanada's interest in ownership of the right-
a-way, the producers who have publicly shown their interest.
She did not agree that a no vote would mean a forever no to
TransCanada or to a gasline. It would mean no to a
particular set of parameters that are too expensive and too
limiting on the future choices.
MR. HEINZE stated that if at this point the legislature
doesn't feel comfortable moving ahead with TransCanada as an
alternative to Denali, then he wanted clear direction.
SENATOR MCGUIRE suggested pausing in the process and
bringing in a mediator.
SENATOR MCGUIRE questioned if a yes vote for TransCanada
would mean the state could not develop Cook Inlet and Nenana
Basin for in-state use. She referred to ANGDA's concerns
with the grant of money and that they believed it would not
be considered a competitive or unlawful act subject to
treble damages. Given Alaska's tax structure, which is
supposed to incentivize gas development equally for
everyone, she wondered if the carve outs of Cook Inlet and
Nenana Basic, designed to incentivize development for in-
state use, could open the state to violating AGIA.
MR. HEINZE stated his recollection of ACES was that gas used
as fuel in Alaska is subject to a 5 percent severance tax,
regardless of which basin it is from. The idea was to
provide an incentive for North Slope gas to be dedicated
into the in-state market. He thought that was legitimate and
insightful public policy, and helpful in terms of meeting
in-state gas needs. It causes players to think about how to
gain that advantage, which is significant; the difference
between a 5 percent and 25 percent tax rate is a large
incentive to a producer. He argued that those terms are
unrelated to the non-compete aspect of being a good partner
to TransCanada.
10:22:19 AM
MR. HEINZE referred to a handout with a draft bill. The
packet is an excerpt of a public record from 2006. There
were public hearings. The conclusion was that the statute
was in need of change. The letter was written to then
Governor Murkowski for its inclusion in the SGDA proposals
that were to come before the legislature, but never did. He
was surprised it has not been addressed before. It is an
outgrowth of former Attorney General of Alaska Charlie Cole
observation to an LB & A hearing in 2004 in which he
passionately described why the existing portions of statute
dealing with in-state open season North Slope gas could
never work. ANGDA agreed and went to the Regulatory
Commission of Alaska (RCA) who also could not figure out how
it works. The solution offered here is a fairly minor change
of statute; it eliminates regulation language and puts the
jurisdiction back on the RCA to determine if a proper open
season has been held.
MR. HEINZE asked that the legislature consider passing the
proposal as part of the AGIA legislation. Without the
change, ANGDA does not believe an in-state open season can
be held.
REPRESENTATIVE SAMUELS requested that the two chairs of
Judiciary work with Mr. Heinze.
10:26:28 AM
DELMA BRATVOLD, SCIENCE APPLICATIONS INTERNATIONAL CORP.
(SAIC), explained that the study (see handout "Alaska
Natural Gas Needs and Market Assessment: 2008 Update of the
Industrial Sector," and PowerPoint presentation "Alaska
Natural Gas Needs and Market Assessment: Update
Presentation," Copies on File) was initially done for the
Department of Energy, the National Energy Technology
Laboratory. It was published in the initial form in 2006;
ANGDA requested an update of the portion of the study
regarding natural gas needs and market assessment. The
update concentrated on the industrial sector because there
has been a substantial change in the price environment. The
update concentrated on how the change in pricing structure
and forecasts might affect demand of potential industries.
MS. BRATVOLD referred to Slide 2, which includes a graph
summarizing the 2006 study findings. She explained that the
Y axis represents the net back price, or maximum price that
each industry or sector can afford to pay, given a forecast
product price and all of their associated costs and a
discount rate. The horizontal axis represents the demand for
each of the industries or sectors. She noted that most of
the industries fall below the horizontal bar representing
the forecast prices of natural gas in Southcentral Alaska as
forecasted for 2015-2035 (based on forecasts developed 2005-
2006).
MS. BRATVOLD reviewed changes from the 2006 to 2008 report,
as shown on Slide 3, which illustrates how product prices
were changed. In the current update, there is both a low and
a high case; the low case represents product prices
determined based on their relationship to forecasts of
natural gas and crude oil, and is based on Department of
Energy, Energy Information Administration (EIA) annual
forecasts, which is generally relatively conservative.
10:31:42 AM
MS. BRATVOLD reviewed the low case scenario depicted on
Slide 4. The updated data shows that the horizontal bar,
representing the market prices in Southcentral during the
timeframe, shows that all the industries have a netback
price (the maximum they could afford to pay given their
estimated costs and discount rates in taxes) that falls
within the estimated range for market prices. She explained
liquid natural gas (LNG) and gas to liquids (GTL) industries
have two lines representing their maximum price. For both
LNG and diesel fuel, the higher bar shows the price if they
were able to sell to Japan; the lower shows the California
price.
10:34:24 AM
MS. BRATVOLD discussed Slide 5. She concluded that the
maximum feed stock would exceed the expected market prices
in Southcentral.
MS. BRATVOLD referred to Slide 6 showing estimated capital
costs by industry. She concluded that total capital would be
$8 billion for all combined industries.
MS. BRATVOLD reviewed Slide 7, a snapshot of revenue and
cost estimates for year ten. She observed that on an annual
basis for combined industries, revenues would be billions of
dollars per year.
10:36:11 AM
MS. BRATVOLD pointed out that Slide 8 contained a short list
of the companies that may be interested in Alaska if gas
were available, based on current forecasts. Each industry
would conduct its own analyses.
MS. BRATVOLD concluded that recent increases in NG and
product prices have improved the feasibility of NG-intensive
industries in Alaska. All the assessed industries appear
feasible under the high price scenario. Under the low price
scenario, LNG and GTL industries may need contracts in
premium markets (e.g., Japan) for feasibility. Alaska is
well positioned for competing with other producers in
providing to a Japanese market. The greatest uncertainty is
associated with GTL due to the combination of evolving
market, costs, and technology. She added that they are least
confident in the gas to liquid industry estimate.
10:39:45 AM
MR. HEINZE added that part of the new funding is to carry
forward some of the themes, one of which is to ascertain the
interest of industries. He emphasized that given the
dramatic price changes in recent years, it is important to
look at previous work.
10:41:59 AM
COLLEEN STARRING, REGIONAL V.P., ENSTAR NATURAL GAS COMPANY,
observed that the company believes Alaska needs gas by 2014
or sooner. She described ENSTAR as the largest utility in
the state and outlined details about the company. The Alaska
Pipeline Company (APC) operates under the ENSTAR umbrella.
For over 47 years they have constructed and operated 450
miles of transmission mains and 2,700 miles of distribution
mains. Gas is under contract to 2014.
10:47:36 AM
MS. STARRING referred to the map depicting ENSTAR's
distribution system on Slide 4 of the PowerPoint
presentation (Copy on File). Slide 6 shows that there have
not been significant finds of gas in Cook Inlet in several
years. The in-state line is meant to address the decline.
Slide 7 shows the current outlook. ENSTAR has gas under
contract through 2013. Further out, the brown bars depict
uncommitted supply.
MS. STARRING reported that Anadarko approached ENSTAR and is
currently drilling in the Gubik Field, which is just west of
the Dalton Highway. The proposed ENSTAR Line would come from
the Gubik Field to the highway and then to Fairbanks and NG
distribution system in Anchorage.
The total estimated cost for a 20 diameter line would be
$3.3 billion. The time frame to build is expected to be five
to six years: two to three years of permitting, design, and
procurement analysis; and another 3 years for construction.
10:49:27 AM
MS. STARRING reviewed time lines. The first drilling was
done by Anadarko. After the second drilling season next
winter ENSTAR will make a decision whether to go forward.
Construction will begin following the third drilling season.
MS. STARRING emphasized that the advantages of the ENSTAR
line:
· First gas by 2014
· Alaska would control its own destiny
· Ensuring a long-term supply for the Railbelt
· Complements both the AGIA and Denali projects
· Could revive Agrium plant
· Could extend the life of Kenai LNG plant
· Creates opportunities for natural gas-based industrial
growth in Southcentral
· In-state markets qualify for lower tax burdens
· Achieves reasonable prices
· Ensures sufficient wellhead prices for exploration and
future development
MS. STARRING added that Alaskans currently spend about $297
million for natural gas, $848 million for fuel oil, and $1.3
billion on propane. She referred to Slide 13 which graphs
the difference in switching to alternative fuels.
10:52:12 AM
MS. STRRING reviewed the accessible in-state markets:
· ENSTAR
· Southcentral Electric Companies
· Fairbanks Natural Gas
· Military Bases
· Golden Valley Electric
· Tesoro Refinery
· Flint Hills Refinery
· Agrium
· LNG Export
MS. STRRING briefly reviewed Slide 15, "ENSTAR Pipeline
Study, Throughput and Load Estimates."
MS. STRRING described some of the assumptions that the
project is based on:
· Project based on utility grade gas
· 20" diameter high grade steel pipeline
· Operating pressure ~2500 psi [pounds per square inch]
· Operation pressure and design allow for additional
hydrocarbon spiking
MS. STRRING noted ENSTAR's current pipeline status as
depicted on Slide 17:
· Contracted engineering, environmental, and construction
companies to assist with the project
· Update meetings scheduled with Anadarko in Alaska July
th
15
· Aerial photography of both the southern and northern
routes
· LiDAR [Light Detection and Ranging] Data
· Field work
· Agency and stakeholder communications
· Data gathering
· Document management system
MS. STARRING concluded the PowerPoint presentation with
ENSTAR's development plan priorities on Slide 19:
· Continue regulatory and permit acquisition
· Prepare economic and financial models
· Address environmental work
· Public outreach and involvement
· State ROW [right-of-way] application preparation
10:54:56 AM
GENE DUBAY, SENIOR V.P. & CHIEF OPERATING OFFICER,
CONTINENTAL ENERGY SYSTEMS [OWNER OF ENSTAR], concluded that
ENSTAR has the solution to Alaska's gas needs. The state has
a lot of options, but the timing is important. Given the
choice between a 50 cent increase in tariff and obtaining
gas in a timely fashion, they would take the gas. He thought
the tariff savings would evaporate if they have to go to
other alternatives.
10:57:02 AM
REPRESENTATIVE SAMUELS asked for a description of events
that would lead to the purchase of gas without the state
sitting on an empty pipeline. He questioned if the purchase
price paid by ENSTAR is footed by the public.
10:58:44 AM
MR. DUBAY observed that they do not make a profit on the
purchase of the commodity. The company's purchase agreements
are filed as a matter of public record and submitted to the
RCA for approval. The company anticipated responding quickly
if the state made the commitment to build the line.
11:00:01 AM
REPRESENTATIVE HARRY CRAWFORD queried regarding tax breaks
for in-state fuel use. He also wanted to know about debt to
equity ratio on the ENSTAR line.
MR. DUBAY answered that the debt equity on the ENSTAR line
would be approximately 70/30. Regarding the in-state tax, he
thought gas dedicated to any kind of in-state use, such as
the Agrium plant, would come under the lower tax rate.
SENATOR CRAWFORD asked about the LNG facility.
MR. DUBAY thought the same would apply to the LNG facility.
11:02:09 AM
REPRESENTATIVE MIKE DOOGAN asked if there was a date for the
preparation of economic and financial models.
MR. DUBAY stated that goals this year were to establish
costs and review throughput on the line to come up with new
tariffs. January is the projected deadline for costs. The
throughput for analysis would be approximately in April,
2009.
REPRESENTATIVE DOOGAN asked if ENSTAR's economic analysis
took into account potential competition from other resources
such as the Susitna dam.
MR. DUBAY maintained that natural gas is the best resource
at approximately one-fourth the cost of electricity. He did
not think that hydro-electric would compete with natural gas
for home heating. He asserted that they have been
conservative on their demand estimates.
11:06:22 AM
REPRESENTATIVE LES GARA questioned what would occur if a
bullet line was begun and then cheaper gas was found in Cook
Inlet. He noted that half the state's gas goes to Asia and
observed that the federal license only lasts another year or
two.
MR. DUBAY explained that proposals for Cook Inlet gas were
for 2013. ENSTAR did not get proposals from producers for
the full requirements. He stressed that they must deal with
what is before them. There is nothing that suggests another
source.
11:10:03 AM
REPRESENTATIVE GARA asked what made ENSTAR's project viable.
MR. DUBAY responded that they have commitments from Agrium
for the gas. Today there is not enough gas produced in Cook
Inlet to keep all the industries that need gas on line.
REPRESENTATIVE GARA commented that given in-state needs he
did not want Alaska gas exported from Cook Inlet. He asked
how long the gas would supply Alaskan needs if the export
contract were able to be cancelled or scaled back.
MR. DUBAY noted that they supported the export license
extension because ENSTAR views the LNG plant as back-up for
deliverability. The producers have diverted gas from the LNG
plant for their needs. ENSTAR believes the community needs
the LNG plant today and over the long term.
11:12:58 AM
REPRESENTATIVE RAMRAS noted that Fairbanks would have no gas
for the first quarter of 2009. Most customers will not have
the ability to do a fuel switch. He asked why an alternative
route to Glennallen is not being reviewed.
JOHN LAU, DIRECTOR OF ENGINEERING, ENSTAR NATURAL GAS
COMPANY, explained that ENSTAR has looked at a variety of
lines and is in favor of a spur line coming off of a
pipeline, especially the pipeline tied into Wasilla.
Anadarko approached ENSTAR with an aggressive drilling
program in the foothills that addressed problems in building
a pipeline to Southcentral and Fairbanks. Anadarko needs a
market and industrial base. Foothills gas is the current
focus. Anadarko does not want to wait till 2020. ENSTAR
currently plans to work with Anadarko to bring foothills gas
down to Cook Inlet. Other projects are not being reviewed
currently. The work that is being done would apply to any
line. He maintained that ENSTAR has the most experience and
supports a route that would connect into Cook Inlet.
11:18:28 AM
REPRESENTATIVE RAMRAS referred to the discussion regarding
potential for a transportation subsidy from the state. He
questioned delivering gas through Delta Junction to Greely
to Valdez if the corridor remains as it is. He wondered what
would be required from the state to alter the corridor and
reach stranded people.
MR. DUBAY stated ENSTAR wanted the lowest tariff gas to go
to customers. A route to Valdez means an export plant that
they have no control over.
REPRESENTATIVE RAMRAS clarified that he wanted to shift the
route to Glennallen which would give Valdez the option to
build infrastructure to meet a pipe in Glennallen rather
than in Fairbanks.
11:22:03 AM
MR. LAU explained that ENSTAR would like to take a line to
Seward, but it would not work out economically. It could
cost $70-80 million. If the state wants to pay for that
line, it could happen.
REPRESENTATIVE RAMRAS asked how many extra miles of pipe it
would mean to build towards Glennallen.
MR. LAU estimated it would be around 90 additional miles.
Construction difficulties would also add to costs.
REPRESENTATIVE RAMRAS concluded that ENSTAR would prefer the
corridor down the Parks Highway to the engineering hurdles
presented by a Trans-Alaska Pipeline (TAPS) corridor.
11:24:11 AM
SENATOR WAGONER asked if there had been any communication
with Agrium regarding their willingness to buy and ship gas
on a pipeline built by ENSTAR.
MR. DUBAY noted that there is a memorandum of understanding.
MS. STRRING added that the memorandum would be shared and
clarified that Agrium supports the ENSTAR project.
RECESSED: 11:25:52 AM
RECONVENED: 12:43:25 PM
REPRESENTATIVE SAMUELS asked that questions be delayed
unless necessary.
RICHARD PETERSON, MANAGING MEMBER, ALASKA NATURAL RESOURCES-
TO-LIQUIDS, LLC (ANRTL), proposed an alternative to gas
pipelines. He began the ANRTL PowerPoint presentation "A
Legacy Decision for Alaska" (Copy on File). ANRTL believes
the option of gas-to-liquids (GTL) provides more
opportunities for natural resource development, provides a
higher net back, and sets up a legacy program that will be
available for the next several hundred years. Gas-to-liquids
is a promising technology that is in operation in the world.
MR. PETERSON addressed AGIA concerns about GTL. The AGIA
process was designed for commercial vehicles to get gas from
the North Slope. The inference is that GTL is not
commercial. He asserted that GTL may result in a higher
wellhead value than a gas pipeline, more long term jobs for
Alaska, and a larger tax base.
12:49:33 PM
MR. PETERSON covered Slides 5-7:
· The plant would require a substantial construction
workforce. Although not as large as that needed for a
gas pipeline, the construction workforce would be
employed in Alaska for many more years.
· The GTL plant operations workforce would be much more
substantial than that for a gas pipeline.
· All of the liquids remain in Alaska for marketing.
· Natural gas liquids can be transported through the
TAPS pipeline along with GTL products.
· While a GTL project could use 2, 3, 4, 5, 6 billion
cubic feet of gas/day or more if desired, the plant
can be sized to use less gas, leaving gas production
that could be transported south through a smaller
"bullet" pipeline.
· If you are going to tax the Producers natural gas at
a quasi crude oil price equivalent, the Producers
might as well convert their natural gas to a liquid
product and actually receive a premium price above
crude oil.
· We believe the GTL option gives Alaska high value
transportation fuels badly needed in the U.S. along
with economic benefits and flexibility not offered
with a just gas pipeline.
12:51:37 PM
MR. PETERSON spoke to converting Fischer-Tropsch (F-T)
products into natural gas equivalents.
12:53:00 PM
PETER TIJM, MEMBER, NATURAL RESOURCES-TO-LIQUIDS, LLC
RESOURCES, explained the technical, chemical aspects of F-T
synthesis depicted on Slide 13. This technology was
developed in 1923 and has been in operation ever since.
MR. TIJM reviewed the three steps in gas to liquids/coal to
liquids/biomass to liquids (GTL/CTL/GTL) refining to make F-
T fuels outlined on Slide 14:
· GTL/CTL/BTL processes use three distinct steps, all
commercially proven to convert a gas, liquid or solid
into synthetic transport fuels:
o Step 1 - Syn=gas generation (hydrogen and carbon
monoxide)
o Step 2 - F-T reaction (long paraffin chains to
wax)
o Step 3 - Product upgrading (hydrocracking of the
long chain F-T paraffin to produce the desired
end product, similar to a crude oil refinery:
Kerosene - diesel - gasoline - jet fuel -
naphtha)
MR. TIJM reviewed Slide 15, which shows in more detail the
three main processing steps of the F-T process. Slide 16
lists the plants and proposed plants worldwide. One of the
big complexes in South Africa produces 150,000 barrels per
day (BPD) if liquids, using coal as feedstock. This plant
has been on line since the 1950s. Another plant in South
Africa uses off-shore natural gas as feedstock and produces
nearly 50,000 BPD. All over the world cars are being fueled
by these liquids.
MR. TJIM explained that the synthetic diesel made in these
plants is high quality. The molecules used are only carbon
and hydrogen. There is no sulfur, no aromatics. There are
almost no emissions when the fuel is burned. The fuel is
approved as the EPA as non-toxic. It even has Food and Drug
Administration (FDA) approval as food quality. He drank some
of the synthetic diesel to demonstrate its purity.
12:59:46 PM
MR. TIJM provided additional information on F-T diesel facts
and fiction:
· Myth: Majors are not pursuing F-T technology.
o In December 2003 ConocoPhillips and in July 2004
Exxon Mobil both signed agreements to build
160,000 bbl/day and 150,000 bbl/day GTL plants
in Qatar. They would not have made these
commitments if they did not believe in GTLs and
possess the skills to build world-scale GTL
plants.
o Shell Oil, a new player in Alaska, has a 15,000
bbl/d GTL plant in Malaysia, is building a
140,000 bbl/d GTL plant in Qatar as well as
designing a 70,000 bbl/d GTL plant in China.
o Chevron, Sasol's world wide GTL partner, is
building a 34,000 bbl/d GTL plant in Nigeria and
had proposed a 130,000 bbl/d GTL expansion with
Sasol and a new 120,000 bbl/d GTL plant, both in
Qatar.
o Marathon completed a pre-FEED study for a
120,000 bbl/d GTL plant in Qatar in 2003.
o BP and Statoil are working on barge mounted GTL
plants.
· Clearly, the North Slope majors possess all the
skills necessary to build GTL (F-T) plants worldwide,
including in Alaska.
1:01:59 PM
MR. TIJM spoke to the efficiency of GTL plants, delineated
on Slide 27:
Some say the GTL process is not efficient with
only 65% of the energy contained in the natural
gas reaching the end market in the form of
transportation fuels.
Like any manufacturing process that "adds value"
to its products, the transportation fuels
resulting from a GTL plant have a higher value.
Also of importance is that the "lost" 35% really
isn't lost.
It is captured as waste heat and is used to
generate electricity, heat buildings and run other
processes that need heat, saving valuable natural
gas for other purposes.
1:03:15 PM
MR. PETERSON discussed Slide 28, which compared GTL vs. LNG
for efficiency and value, and concluded that the net back of
GTL is of higher value.
1:04:31 PM
MR. TIJM returned to GTL facts and fiction with Slide 30:
· 2003 estimate $25,000/installed barrel.
· 2007 actual cost $32,000/installed barrel.
· 2008 Shell Pearl GTL plant $60,000/installed barrel
(under construction today).
· ANRTL completed a $1.5 million Pre-Feasibility study
for an 80,000 bbl/d CTL project for the Cook Inlet in
February 2008. Cost estimates have risen from $4.6 to
$12 billion from 2005-08.
· The CTL project still pencils out because product
prices have risen even more.
· Some of the estimated costs of this Cook Inlet CTL
project were derived from the $250 million Sasol/China
engineering study completed in late 2007.
· North Slope GTL plant ~300% higher than the recently
completed Sasol GTL plant in Qatar - we use a $92,000/
installed barrel cost.
· If anything, we believe the projected costs of a North
Slope GIL plant program are high.
MR. TIJM noted that 4.5 bcf/d translates to 400,000 barrels
a day in response to a question by Representative Samuels.
MR. TIJM explained that their study was generous in terms of
costs. Slide 32 depicts how front-end design studies
function, in engineering terms. The feasibility study is
still in the early stages.
1:09:07 PM
MR. PETERSON explained that batching is one of the
principles used to reduce costs and maintained that TAPS
batching/pigging can be done. Slide 36:
· There is no question that the TAPS line can be operated
as a dual/multi products/crude pipeline.
· Explorer Pipeline, owned by several major oil
companies, has successfully operated a 1,400-mile large
diameter pipeline carrying a full slate of refined
products and crude oil. In fact the Explorer Pipeline
model is used in many pipelines in operation today.
· Explorer Pipeline has offered to bring their expertise
to Alaska to assist with the design and conversion of
TAPS.
1:11:16 PM
MR. PETERSON explained that cleaning pigs must be used for
physical separation of the crude oil and the product. Slide
37:
· Batching F-T products and NGLs (Products) without a
physical separation between the Products and the ANS
crude oil will not work. Further batching of the
Products without a physical separation between
individual products is not recommended.
· "THE PIG TRAIN" - Physical Pigging will allow batch
shipping of Products from the North Slope to Valdez.
· The outstanding question is how far can you batch/pig
down the TAPS before you need to replace the pig due to
wear?
· TAPS line can remain viable for moving crude oil
produced on the North Slope to Valdez for 50 to 100 or
more years.
MR. TIJM gave an example of a project in Europe where pipes
were shared; his company's crude batches were effectively
separated in spite of distance and other challenges.
MR. PETERSON continued with Slide 39-40:
· Once TAPS is modified to carry both crude oil and
products, the currently recycled gas stream can be
processed to extract additional NGLs for batching to
Valdez.
· This allows for the receipt of this NGL revenue stream
within a few years, certainly long before a GTL plant
could be on line or a gas line to the lower 48 could be
built.
· It is our opinion that the market for North Slope NGLs
will be considerably higher at Valdez than at AECO
[Alberta Energy Company] in central Alberta if for no
other reason than the tariff on TAPS is at least 1/3 of
the cost to ship on the proposed AGIA gas line.
o TAPS tariff $5/bbl (83.3cents/million btu)
o AGIA tariff $3/million btu ($18/bbl)
o AGIA tariff $4/million btu ($24/bbl)
· The interior of Alaska operates on a liquid energy
economy.
· Batching products down TAPS will provide Interior
Alaska with the opportunity to receive lower cost fuels
at new delivery points along the pipeline without
having to replace their existing energy infrastructure.
1:16:46 PM
MR. PETERSON continued with Slide 42:
· Batched products will be contaminated: One of the
biggest advantages with a TAPS batching /pigging
program is that butanes have been extracted from the
gas stream and spiked into the crude oil stream since
first flows.
· This same volume of butane will be placed in the front
end of the pig train and used to clean the pipe walls
of contaminants.
· The "dirty" butanes will be blended with the ANS crude
oil at Valdez.
· If any batched products behind the "cleaning" butanes
are also contaminated, the batching program will
provide for additional processing at Valdez to remove
sulfurs and color.
· NGLs with a high vapor pressure can't be transported in
TAPS: The lightest products we would recommend for
shipping on the TAPS would be propane CH Propane has a
38
vapor pressure of 207 psig [pounds per square inch
gauge] at 110°F. This is far below the operating
pressure of TAPS.
· Keep ethane in the natural gas as there is no
petrochemical industry on the US West Coast. Ethane
will be converted into F-T products.
MR. PETERSON pointed out that if Alaska does not want to do
a GTL program, but still wants a gas pipeline (Slide 45):
· Batching/Pigging in TAPS could benefit the AGIA gas
line if a gas line is the best option
· Modifying the TAPS line to batch crude oil and products
will eliminate the need to transport liquids in the gas
line.
· This will reduce the cost of the gas pipeline and make
its operation easier, plus make delivery of in-state
gas less complicated as you are not dealing with a
dense phase gas.
1:20:04 PM
MR. PETERSON observed that America needs natural gas (Slide
47):
· The need for imported (additional) natural gas pales
in comparison to the need for reducing imported crude
oil and adding refining capacity.
· Natural gas has historically sold at a discount to
the value of crude oil. Today that disparity is
wider.
· Diesel has historically sold at a price at or below
regular gasoline. Today diesel sells at a premium to
gasoline.
· F-T diesel has, in addition to the higher value of
crude oil, the value of the refining margin plus a
lower tax rate resulting in a market price premium of
between $33 to $55/bbl over the value of crude oil
($6.2 to $10.3/mcf).
MR. PETERSON observed that (Slide 48):
· Virtually everyone has a different opinion on the
volumes of natural gas, crude oil and refined
transportation products produced, consumed or imported
in the U.S. For the purposes of this report, we use
information gathered from independent two sources:
· U.S. Energy Information Administration
(www.eia.doe.qov/) and
· The BP Statistical Review of World Energy June 2007
(www.bp.com/rroductlanding.do). This latter document is
an excellent summary of world energy and BP should be
commended for pro v/ding this public service update
each year.
MR. PETERSON continued with Slide 49:
· If we look at the six month period from August 2007
through January 2008 (the latest EIA numbers) the U.S.
on average produced slightly more than 5 million
barrels per day of oil. (note: the EIA data does not
include NGLs in the crude oil).
· During the same time period the U.S imported over 10
million barrels per day of crude oil and another 3
million barrels per day of refined products.
· The significance of the latter number is that the
nation lacks over 3 million barrels per day of refining
capacity to meet current U.S. transportation fuel
demands.
MR. PETERSON emphasized that even if the Arctic National
Wildlife Refuge (ANWR) was opened up immediately, there is
not enough refining capacity to meet current demand. The
U.S. imports three million barrels a day of gasoline,
diesel, and jet fuel because of that.
1:25:46 PM
MR. PETERSON turned to Slide 50:
· While U.S. refiners have been adding capacity to
existing refineries with process efficiency upgrades,
no new refinery has been built in the U.S. since the
1970's.
· This could possibly be one of the reasons why refinery
margins have crept up from the $5 to $6/bbl range in
1970 - 2000 era to over $30/bbl in 2007.
· A North Slope GTL plant represents new refining
capacity for the U.S. and a potential threat to these
higher margins, especially on the U.S. West Coast.
· This is one potential reason GIL's are not be in the
forefront of North Slope majors' gas development plans.
Slide 51:
· The U.S. currently (2008) imports roughly 70% of its
crude oil/transportation needs. With approximately 13
million bbl/d of transportation fuel demand almost 29%
of this demand (approximately 3 million barrels per
day) is imported in the form of finished products.
· On an energy content equivalent scale this represents
approximately 18 bcf/d of natural gas being imported
just to meet the U.S. refinery shortfall.
· This is four times the volume of gas to be delivered
through a natural gas pipeline.
· ~78 bcf/d for total transportation needs - 20 times.
1:29:12 PM
MR. PETERSON explained a graph on Slide 52 depicting U.S.
oil companies have no control over the price of crude oil in
the world. The largest independent oil company in the world
cannot compare as far as crude oil production. He went on to
Slide 53:
· During this same time period the U.S. was producing
approximately 64 billion to 65 billion cubic feet per
day (bcf/d) of natural gas and importing approximately
9 to 10 bcf/d of natural gas, primarily from Canada.
· Of this, approximately 1.6 to 1.8 bcf/d of the total
U.S. natural gas is being imported as LNG.
· Thus 14.7% of U.S. natural gas consumption is imported,
with LNG representing approximately 2.4% of total U.S.
natural gas needs.
1:29:57 PM
MR. PETERSON reviewed Slide 54:
· Historically natural gas HAS sold at equivalent price
compared to crude oil.
· From 2002 to 2007, natural gas averaged 68% of the WTI
[West Texas Intermediate] price of crude oil (i.e. 32%
below crude oil).
· In April 2008, the NYMEX closing price for May 2008
deliveries of natural gas was $10.60/mcf or, a crude
oil equivalent price of $63.60, some 45% below the then
crude price of $115/bbl.
· We believe that there was a fundamental severing in the
price of natural gas compared to crude oil once oil hit
the $60 to $70/bbl range.
MR. PETERSON thought the reason was that there is a maximum
number natural gas will sell for in the Lower 48 and we are
close to that number now.
1:31:50 PM
MR. PETERSON continued with Slide 55:
· All of the energy consumers who could have switched off
crude-based products have done so but the gas industry
is still able to meet demand.
· In fact, little LNG is currently being imported into
the U.S. because markets elsewhere in the world,
especially those linked to the price of crude oil, are
paying much higher prices and few want U.S. dollars.
· If one compares a California ultra-low sulfur diesel
price with an equivalent natural gas price one quickly
sees a potentially greater return for Alaska in selling
F-T products than selling natural gas.
MR. PETERSON emphasized the de-valuing of the U.S. dollar as
the primary reason LNG is going to other markets. The
Japanese market, which drives the high price of LNG, is
going to re-negotiate to bring down this tracking of crude
oil prices so that LNG worldwide may come down.
MR. PETERSON explained Slide 56:
· April 2008 [California Air Resources Board] CARB diesel
wholesale price of $3.30/gallon ($138.60/bbl) plus the
tax advantage of selling a natural gas based fuel in
the transportation market of $13.02/bbl, one has a
market gas equivalent price of $28.6/mcf.
· Compare this to the April NYMEX [New York Mercantile
Exchange] number and one can see that the gas price
would have to increase by 270% to equal that of diesel.
· On May 19th, the wholesale price of California diesel
hit $3.91/gal or a mcf equivalent price of $33.4/mcf.
1:34:46 PM
MR. PETERSON presented the graph on Slide 57, "CARB Diesel
Fuel Average Rack Prices (As of 5/19/08)." The average 2005
through 2007 price for finished diesel was around $2/gal.
The average 2007 came up to $2.37/gal. The May 2008 price
was $3.91, or $33.4/mcf. Slide 58:
· We point these facts out to show that the greatest
energy need in the U.S. is not natural gas; it is
replacing crude oil imports and more importantly
adding domestic refining capacity.
· U.S. natural gas is not priced on a world crude oil
equivalent as it is in many other parts of the world.
U.S. transportation fuels are, however, priced based
upon the world price of oil.
· Plus in some areas, such as the U.S. West Coast,
transportation fuels are priced at a premium due to
higher quality requirements.
1:36:47 PM
MR. PETERSON turned to Slide 60, "Netback from California to
Prudhoe Bay." He offered three cases:
· CASE A - Average California 2007 refinery wholesale
rack price $2.37/gallon
· CASE B - May 19, 2008, California refinery wholesale
rack price $3.91/gallon
· CASE C - Projected 2014 crude oil price of $200/bbl
and $40/bbl refinery margin resulting in $5.71/gallon
MR. PETERSON also assumed:
· $2/bbl shipping cost, Valdez to market, and a $5/bbl
TAPS tariff, for a total $7/bbl Prudhoe Bay to
California
· 5.3 billion btu/bbl of F-T and 1 million btu/mcf of
natural gas
· A debt service/equity recovery cost of $31.75/bbl
(75/25, 20 years to recover the debt, 7.5% cost of
financing, 20% return for equity for the producer)
· A GTL plant operating cost of $18/bbl
1:39:44 PM
MR. PETERSON reviewed slides 61 to 64, which detail the math
for the three cases. He pointed out that the F-T process
converts carbon contained in the natural gas into finished
transportation fuels and heat. Approximately 65 percent of
the BTUs contained in the natural gas will end up in the
transportation fuels. Much of the BTUs contained in the
natural gas will be captured either in the F-T fuels or
waste heat to produce power. The end result is that product
in:
· Case A would cost $2.37/gallon in California would
cost $6.01/mcf natural gas at a Prudhoe Bay GTL
plant;
· Case B would cost $3.91 in California and 12.98/mcf
natural gas at Prudhoe Bay GTL plant; and
· Case C would cost $5.71 in California and $21.16/mcf
natural gas at Prudhoe Bay GTL plant.
1:41:05 PM
MR. PETERSON emphasized the projected high costs of AGIA gas
on Slide 65:
· A Prudhoe Bay price approaching $18 to $27 per mmbtu
over 25 years.
· 2017 to 2042. WOW.
· What do Alaskans think they will be paying for natural
gas?
· These AGIA projected gas prices are 300% to 400% higher
than the 2007 prices in the Cook Inlet. This isn't
"cheap" gas!
MR. PETERSON wondered how the people of Alaska would afford
heat and energy at these prices.
1:44:08 PM
MR. PETERSON asked who receives the most value from gas
sales, and directed attention to Slides 66-67:
· Tax the Producers natural gas at a crude oil price
equivalent and the Producer may only receive a fraction
of the value of the natural gas.
· At today's $120/bbl crude oil price the PPT on natural
gas would be:
· 25 + ((97.5-3O)x .OO4)+(12O-97.5 )x.OO1= .543 or 54%
· With a 1/8 Royalty (12.5%) + 54% = 66.5% of the
value goes to the State - the Producer receives 33%
(+ pays other taxes to the state and federal
government)
· At $200 crude the % of value to the State would
exceed 75%
· You can easily see why the Producer of the pipeline
risk isn't who is expected to take all excited about
AGIA
· Ask yourself, "Why isn't the market guaranteeing the
gas line payout instead of the Producers?"
MR. PETERSON asked who should be buying firm capacity supply
or market. Slide 68:
If Natural Gas truly was in short supply and
projected short supply were real, then people who
need natural gas, have no choice but to use
natural gas (market) would be coming to Alaska to
buy this "proven" resource. THEY would be
contracting with whoever is building the pipeline
for firm capacity to their market. Do you see this
happening?
1:47:45 PM
MR. PETERSON addressed the topic of energy conservation and
its impact on a gas line. He recalled when the price of gas
was projected to go up to $9 in about five or six years, he
wondered if he could afford to live in his house any more.
He began winterizing. He reviewed Slide 70:
· 300 million people in America
· Take 1/3 or 100 million people
· Turn off two 100 Watt light bulbs or don't run a PC for
half a day
· Save 480 billion watts per day or 20,000 MW-HR
· Assume a modern heat rate of 8,500 Btu/kw-hr
· Save 4.08 billion cubic feet per day of natural gas
· THAT'S THE ALASKA GAS LINE CAPACITY IN A FLICK OF THE
SWITCH
MR. PETERSON turned to the subject of the nuclear threat to
Alaska's gas, depicted on Slide 71:
· We are told that Toshiba is looking at installing up to
five of their small nuclear power plants in Alberta to
supply the tar sands projects with heat and electricity
that would be COfree energy.
2
· Helps Canada meet its Kyoto obligations. There goes 1
to 2 bcf/d of gas market.
· Canadian supplied gas will have to flow into the U.S.
market competing with Alaska AGIA gas.
MR. PETERSON cautioned against thinking the price would just
go up and up. The reduction in energy demand caused by
conservation has to be figured in. He pointed out that
gasoline usage comprises 70 percent of our import needs. If
that is dropped 20 to 40 percent, we still need everything
we can produce from GTLs.
1:52:04 PM
MR. TIJM described some of the benefits of GTLs at Prudhoe
Bay, including the many by-products. Carbon dioxide has to
be taken out of the gas. It can be used for secondary oil
recovery. The process generates heat that can be used to
generate local electricity. It can provide the electricity
for the whole complex and make it self supporting. Pure
water is also generated that can be used for drinking or
secondary oil recovery. If the NGLs are batched, the TAPS
tariff can be lowered. The liquids can also be diverted to
other towns that need them, like Fairbanks and Valdez.
1:54:55 PM
MR. PETERSON described the uses of the waste heat produced
by the process.
MR. PETERSON addressed Slide 75 and described Alaska's coal
resources and reserves. The Northern Alaska Basin could
potentially have more coal than the total proven reserves in
the world today.
1:57:26 PM
REPRESENTATIVE SAMUELS asked about the large capital cost to
build a GTL plant.
MR. PETERSON recommended building in a modular form. The
cost for module is around $92,000/installed barrel, or $8-10
billion initial cost. Modules added over 14-18 years would
bring the total to around $40 billion.
REPRESENTATIVE SAMUELS asked if producers did not build GTL
plants because of the transportation plus up front capital.
MR. PETERSON responded that the transportation is in place.
He speculated about the choices the major companies might
make.
REPRESENTATIVE RAMRAS mentioned that Senator Stevens would
be at a mid-July meeting with the governor on synthetic gas,
coal to gas. In the 2004 National Energy Bill, the U.S. Air
Force is mandated to get 20 percent of their energy from an
alternative source; coal gasification falls in that
category. He asked who requested ANRTL to present on the
subject.
REPRESENTATIVE SAMUELS responded that Legislative Budget and
Audit was requested by a member to have more information on
GTLs. Mr. Peterson was contracted. He speculated that there
would be more interest from the industry on GTLs and that
there must be trade-offs the industry is not willing to
make.
REPRESENTATIVE GATTO referred to Slide 14 and the fact that
the carbon chains produced "wax." He asked if, given the
North Slope winter environment, it was possible to batch wax
down the pipeline.
MR. TIJM answered by saying that the wax is the ultimate
form of the long paraffin chains that is cut in pieces
before it has a chance to liquefy. It won't be exposed to
the atmosphere. He emphasized the many uses of the wax as a
very high value-added product.
REPRESENTATIVE GATTO pointed out that number 2 diesel has
wax while number 1 diesel does not. Alaskans are forced to
burn number 1 diesel in the winter to prevent waxing. He
thought it would be very difficult to use anywhere,
especially in a pipeline.
MR. TIJM said that the molecules delivered are clear cut.
MR. PETERSON added that the GTL plant on the North Slope
would be indoors. The cold flow properties of F-T GTLs are
superior to Alaska North Slope (ANS) crude oil. Crude oil
creates wax in a pipeline at the lower temperatures, but
none of the GTLs would have that problem.
MR. PETERSON closed by saying that coal to liquids (CTL) and
biomass to liquids (BTL) F-T programs in the U.S. are
economic today because Senator Stevens put the language in
the 2005 transportation bill that gives the incentive to
compete with these fuels at the same price as petroleum
based diesels.
REPRESENTATIVE SAMUELS commented that Mayor Whitaker in
Fairbanks was also looking at coal gasification.
RECESS: 2:07:33 PM
RECONVENE:2:11:38 PM
BARRY PULLIAM, SENIOR ECONOMIST, ECON ONE RESEARCH,
CONTRACTOR, LEGISLATIVE BUDGET AND AUDIT COMMITTEE,
explained that Econ One had been asked to look at relative
netbacks of potential LNG projects and how those might
compare to pipeline projects. He referred to his handout,
"Comparison of Netbacks from Potential LNG Project with
ALCAN Pipeline Project" (Copy on File). The review looks at
the economic assumptions and analyzes the netback values
associated with both LNG and pipeline projects. It looks at
the Port Authority's proposal in particular, at proposals
that would have larger volumes (up to 4.5 bcf/d), and at
TransCanada's proposal for purposes of the pipeline netbacks
from an overland route. Econ One has also reviewed the
administration's analysis of LNG and netbacks, and
information from other LNG specialists and governmental
agencies.
MR. PULLIAM said that the goal is to assess the netback
value that will be available to the resource owners at the
inlet of the gas treatment plant (GTP) and which project
would maximize the total netback of the gas resource.
2:16:22 PM
MR. PULLIAM offered an overview of LNG and pipeline
logistics to help understand how the netback works. He
pointed to Slide 6 detailing pipeline deliveries. The gas
will go into a GTP, be conditioned, go into a pipeline and
go to a hub where it will be sold. Along the way, there is a
loss of around 9 percent of the fuel volume, as the fuel is
used for various processes. LNG deliveries involve more
steps and a loss of around 16.5 percent of the volume. The
fuel used along the way is a cost of moving the gas.
2:18:55 PM
REPRESENTATIVE MIKE DOOGAN asked about the losses.
MR. PULLIAM replied that more gas is lost in the regas
scenario; however, in the case of Asian sales, the buyer is
responsible for the losses.
MR. PULLIAM addressed supply and demand factors. When
calculating the netback, the cost of producing the product
is subtracted from the price that the product can be sold
for. Supply and demand for gas is a factor. Slides 8 and 9
illustrate world wide preserves. Russia, Iran and Qatar are
the three largest proven gas reserves in the world, and
control over half of the world's gas.
2:21:38 PM
MR. PULLIAM turned to Slide 10, depicting consumers of LNG;
Asia, especially Japan, is the largest, taking up 65 percent
of LNG demand. Europe is at 24 percent and the United States
at 10 percent.
2:22:38 PM
MR. PULLIAM stated that Slide 11 projects LNG demand by
region. In 2005, worldwide LNG demand was about 18 bcf/d.
This demand is projected to triple through 2020. A large
part of that growth will be here in the U.S. He continued by
saying the projected demand in Asia would be about 24
percent in 2020. It is important to keep that in mind
regarding pricing.
2:24:32 PM
MR. PULLIAM addressed regional liquefaction plant capacities
for serving Asian markets, as depicted on Slide 12. The
Pacific Basin, which includes Indonesia, Malaysia, Russia,
and Australia, has about 10 bcf/d currently and is
developing or considering another 10 bcf/d. The Middle East
has 6 bcf/d currently operating and another 12 under
construction or consideration. That totals around 37 bcf/d
that would be available to deliver gas into Asia.
MR. PULLIAM said that the U.S. mostly relies on domestic gas
production at this time. Slide 13 shows U.S. gas production
by source, both historically and projected. The projections
are that conventional gas is going to be declining in
volume. It will be replaced by unconventional, more
expensive gas. The EIA projects that Alaska will fill some
of that gap at the rate of 4.5 bcf/d starting around 2021,
which would comprise 6 percent of U.S. gas needs.
REPRESENTATIVE DOOGAN pointed out that Mr. Robinson from
FERC had said the sale of gas in Pennsylvania and West
Virginia was almost unheard of three years ago but now will
be almost pushing LNG out. There is much it has become
economic. He asked the relationship of that information to
the data on Econ One's report.
2:28:47 PM
MR. PULLIAM acknowledged that his data was from 2007. He
said more recent forecasts would have more of the
unconventional gas and less LNG coming into the U.S.
MR. PULLIAM turned to Slide 15 which shows usage in the U.S.
going up. This is the 2007 data; more recent data would show
a lower line. He noted that Canadian gas would affect the
picture. It is projected to go down.
MR. PULLIAM discussed pricing, using Slide 16 on historical
gas prices. The red line is the LNG price in Japan, which is
higher over time. When oil prices started to go up in 2003,
U.S. prices increased faster than Japanese prices, because
of capping in Asia. Slides 17 and 18 compare U.S. natural
gas and crude oil prices. More recently, oil has risen more
quickly than gas. The longer term average has been 8:1, oil
to gas.
2:32:02 PM
MR. PULLIAM turned to Slide 19, which compares Japanese
crude oil and gas prices. Oil and gas tracked each other
very closely because gas pricing in Japan and in Asia has
been historically tied to oil prices. Many of the contracts
in Asia have a cap on them. That is changing, which is
reflected in the graph on Slide 20.
2:33:35 PM
MR. PULLIAM emphasized that contracts are done on a long
term basis and market conditions determine price at the time
of sale. Market conditions recently have been tight. Gas
demand has gone up, LNG has been slow to respond, and so
those who have supply have been able to get good prices
recently. The question is how that will change.
MR. PULLIAM explained that the first step in the netback
process is figuring out what the sale price will be. Econ
One has started with different oil price scenarios. The
administration has used the Wood Mackenzie oil price
estimates, as well as the EIA estimates, depicted as red and
black lines on the graph on Slide 22. The blue line shows
what oil would be if it was priced at $60 per barrel in real
terms. The other lines forecast higher, but lower than the
green line at $90 per barrel. The data is from the end of
2007 and may be considered conservative today. Econ One has
used the Wood Mackenzie and EIA prices as the base.
2:37:34 PM
MR. PULLIAM turned to the prospects for Asian LNG prices
(Slide 23):
· There is a wide range of prices depending on contract
vintage.
· Recent contracts have reflected stronger links to oil.
· Many contracts are on a provisional basis as previously
(low-priced) formulas have expired or are not
applicable at current oil price levels.
· Relatively high priced opportunities in Asia will
attract gas supplies to that region:
o Increasingly competitive among suppliers;
o Opportunities for buyers; and
o Price will be dependent on the supply situation at
the time of contracts.
MR. PULLIAM said high prices will attract sellers. If there
was gas to contract now, prices would be good. When Alaska's
gas gets to market, the question will be what the supply
picture will be. Potential pricing scenarios are highlighted
on Slide 24. The four lines represent different forecasts
for prices in Asia. They are all tied into the Wood
Mackenzie forecast; the EIA forecast would yield similar
results.
MR. PULLIAM put emphasis on the middle two lines. The top
one is the base case scenario from the Gas Strategies
consulting firm. Depending on how much gas would be sent
from Alaska to Asia, Mr. Pulliam thought the estimate was
reasonable. The Port Authority developed an estimate based
on projections by the Japanese equivalent of the EIA. That
projection was for gas to sell for 80 percent of the value
of oil. Other projections are both higher and lower.
2:42:35 PM
MR. PULLIAM discussed volatility in U.S. prices (Slide 25):
· Historically, gas has been priced between 1/6 and
1/10 the value of oil, with the long run average near
1/8.
· The recent run-up in oil prices and relatively
abundant domestic production of natural gas has kept
that relationship above historical levels.
· Many see the oil/gas relationship returning to more
historical levels (i.e. convergence) as:
o Domestic supplies decline and become more costly
to produce;
o LNG imports are drawn to higher priced regions
(e.g. Asia); and
o Greenhouse/carbon emission concerns put coal out
of favor and natural gas in favor as the fuel of
choice for electricity generation.
2:44:48 PM
MR. PULLIAM concluded that the 8 to 1 ratio of oil to gas is
the right perspective to use in thinking about pricing.
Slide 26 compares the Wood Mackenzie forecast with the EIA
forecast. The EIA sees more coal being used in the U.S.;
some are skeptical about that forecast.
2:45:51 PM
MR. PULLIAM explained that Slide 27 adds the Henry Hub
prices to an earlier graph about Asian prices. The black
line shows the 8 to 1 ratio. If there were a weak oil/gas
relationship in the U.S. and a strong relationship in Asia,
there would be significant differences in the selling
prices. He thought that was an extreme forecast.
2:46:46 PM
MR. PULLIAM listed the assumptions used in comparative
netback analysis (Slide 28):
· First Gas: 2020
· Capitalization:
o 70% debt/30% equity (pre-operation)
o 75% debt/25% equity (post-operation)
· Debt costs:
o 5.5% guaranteed; 7.0% non-guaranteed
· Equity returns: 14%
· Capex/Opex:
o Administration (Westney): GTP and pipeline
segments
o Port Authority (Bechtel): LNG plant
o Sensitivity at higher costs
· Fuel use:
o Administration (Westney) for GTP/pipeline segments
o Port Authority (Bechtel) for LNG plant
· Shipping costs:
o Port Authority: Approximately $0.75/Mmbtu + Fuel
· Gas composition and NGL Extraction:
o 1.118 Mmbtu/mcf
o Full extraction at Alberta
o Partial extraction at Valdez (LNG case)
MR. PULLIAM referred to discussion about whether or not
Alaska gas would be too lean if NGLs were taken out before
delivery to Asia. Econ One thought it would be fine to take
some of the NGLs out, not the full amount.
2:49:57 PM
MR. PULLIAM discussed capital costs (Slide 30). He
summarized that the Port Authority and administration
estimates are similar. Differences occur in the LNG plant
cost estimates that would lead to a difference in tolls of
about $1/Mmbtu. The two roughly agree on the pipeline
construction costs.
MR. PULLIAM described different scenarios run regarding
capital costs for an LNG project and pipeline project,
detailed on Slide 31. The administration's cost shows about
a 20 percent higher capital cost than the Port Authority.
Slide 33 shows the costs for the pipeline projects, using
the administration's capital cost calculations developed by
Westney.
2:52:02 PM
MR. PULLIAM, in response to a question by Representative
Kerttula regarding the difference between plant costs on
Slide 31, explained that one set of numbers corresponds to
the different sizes of the plants.
REPRESENTATIVE SAMUELS observed a discrepancy.
MR. PULLIAM explained that there are different ways of
estimating the costs. He referred to a graph put up by the
administration (Slide 33). He explained the data points that
were used to calculate probability. The points were based on
Westney's analysis of other LNG projects throughout the
world.
2:54:07 PM
MR. PULLIAM explained that the Port Authority, who are at
$470/ton instead of $750/ton, had a cost estimate done by
Bechtel. The discrepancy is explained by different
methodology. There are specific differences for the Valdez
plant, which would receive gas at a high pressure and would
not need as much compression as other plants. It would be
more efficient.
2:56:16 PM
REPRESENTATIVE FAIRCLOUGH referred to a previous question on
the plant cost discrepancy and asked if the administration's
analysis had included higher costs for the cooling
mechanisms for transport of the LNG.
MR. PULLIAM thought the administration tried to make
adjustments across time. They looked at plants developed in
the last five years. During that time plant development cost
has gone up considerably. He was unclear about the specific
methodology used. He did not know if they adjusted for
different plants in different regions. The specifics of the
adjustments were not available. The plant in Valdez is more
efficient to operate than in the tropics, where many of the
other plants are, and should be cheaper. In addition, gas is
being delivered in a high compression pipeline; some of the
compression needed in another plant will not be needed.
REPRESENTATIVE FAIRCLOUGH stated that the question she was
referring to had been asked June 10 when Bill Sparger was
speaking. The question was asked on a disparity on Slide 6.
She asked for a follow up calculation regarding the
compression.
3:01:16 PM
MR. PULLIAM reviewed comparative plant costs as depicted on
Slide 34. The Port Authority estimated $470/ton. The
administration's numbers are $755/ton. Costs for plants are
difficult to come by. Jensen estimates between $600 and
$650, but that would not be specific to Valdez. Tariff costs
would be approximately $2.09 to $3.16. He felt that the Port
Authority analyses would be reliable.
MR. PULLIAM discussed the different elements of the tariffs
on Slide 36. He compared LNG and pipeline projects. Fuel
costs are rising over time. Average transportation costs,
including the fuel, are a little over $9/Mmbtu for the
smaller LNG project. The 3.5 bcf/d pipeline comes out at
$5.64/Mmbtu. One of the big differences is that less fuel is
required to operate the pipeline. Overall, there is a $3.50
difference between the two scenarios.
3:05:34 PM
MR. PULLIAM moved to a chart on Slide 38 showing the
netbacks for LNG delivery to Asia. The netback would be
higher for the larger, more efficient plant. The pipeline
and the LNG on a per unit basis would give similar netbacks
under certain pricing assumptions.
3:07:29 PM
MR. PULLIAM compared projected netbacks (Slide 41). He
started with projects that were comparably sized, the 2.7
bcf/d LNG project and the 3.5 bcf/d pipeline project. The
different pricing scenarios are ranked 1-6. The netback that
would be highest would be for an LNG project at high gas
prices in Asia. That is the most likely scenario; he thought
the middle two pricing scenarios, suggested by Gas
Strategies and Port Authority, were more reasonable. The
netback would still be slightly higher than a small sized
pipeline. When that is changed into present value, and the
higher volume of the pipe is taken into account, the overall
value is higher with the pipeline.
MR. PULLIAM then compared the smaller LNG project with the
bigger, 4.5 bcf/d pipe, using Slide 43. He concluded that
the pipeline would have the higher overall value. Comparing
the larger (4.5 bcf/d) LNG plant with the larger pipeline
meant competing with other world markets. He did not think
there was value for the higher volume LNG plant.
MR. PULLIAM observed that the Port of Authority is not
speaking to a 4.5 bcf/d LNG plant.
3:12:26 PM
MR. PULLIAM spoke to sensitivities: High sustained oil
prices and the impact of project delay. There is a scenario
(Slide 47) in which the LNG project could give Alaska a
higher value than a pipeline project: very high oil prices
($120 real). A small LNG project, assuming very high
correlation to oil, could have a netback of $25/Mmbtu. At
the same time, comparing that to a small pipeline project
with a weak gas/oil relationship, the netback would be
closer to $17/Mmbtu. Bringing those numbers over to net
present value, it is clear that LNG is higher, but not by a
lot.
3:13:56 PM
MR. PULLIAM spoke to the impact of potential delays on
projects (Slide 48). The top panel of the chart shows the
net present value assuming both projects come on in 2020.
The project with the highest value is the 4.5 pipe under the
8 t 1 oil/gas relationship. In the case where both projects
come on, the pipe scenarios have higher value. Shifting the
start date of the LNG back by two years, as the
administration assumes, the value would fall. A delay in the
pipe until 2022 would translate to the pipe still having a
higher net value.
3:16:13 PM
REPRESENTATIVE SAMUELS observed that it would take a six
year delay in a smaller pipe line.
MR. PULLIAM agreed.
3:16:56 PM
MR. PULLIAM pointed out that all of the numbers assumed that
the LNG would be exported. Some of the earlier proposals
talked about sending LNG to the west coast. He had not run
the numbers, but it was clear that there were no reasonable
price scenarios that would make that attractive relative to
a pipeline project.
MR. PULLIAM asserted that he wanted to talk about export
issues because export of the LNG is central to the notion of
getting potentially higher netbacks. He reviewed Slide 50:
· Yukon Pacific permit for export
o Issued in 1989
o For a volume of 14 Mmta (about 1.9 bcf/d) to
Japan, South Korea, Taiwan
o 25 years from first gas
· Project will require DOE review
o Different project
o Time elapsed
o Different circumstances (e.g., U.S. is net
importer of gas)
o Political
· Is recent Kenai plant decision comparable?
o Smaller/shorter window
o No perceived issues outside Alaska
o Lengthy multi-year process for renewal
· Experience with oil
o Initial ban on exports
o 1996 lifting of export ban, but too late to
benefit Alaska
o Still significant perception issue at federal
political level
3:21:13 PM
MR. PULLIAM continued reviewing LNG export issues (Slide
51):
· Exports must be "in public interest"
· Pros
o Free trade
o Efficiency (higher netbacks)
o Balance of payments
o More production for Lower 48
· Cons
o Will lead to more LNG imports
o Will lead to more high cost Lower 48 production
o Will lead to higher gas prices for U.S. consumers
3:21:47 PM
REPRESENTATIVE CRAWFORD questioned if it could be viable to
export to Trinidad in order to equalize costs. He estimated
that the U.S. would not be the prime market, but India and
China. He wondered if that was taken into account in the
analysis.
MR. PULLIAM explained that the forecast does consider
demographic changes. They anticipate an increased demand in
Asia as the population grows. While China is a factor, they
also have a lot of coal and may not use as much LNG. U.S.
demand will also continue to grow and would still constitute
a huge market for gas. He thought prices should equalize due
to increased interconnection between regions in the LNG
trade and prices. The U.S currently pays the premium on oil
for the large demand in Asia; not all of that will be
escaped with gas.
3:26:32 PM
MR. PULLIAM agreed that there is some potential for a swap
including other countries. He added that the perception that
the gas is leaving the country would remain an issue.
REPRESENTATIVE CRAWFORD observed that a case was made in
Salt Lake City that the future for energy was LNG. He
suggested that the leveling of world markets would come
sooner rather than later due to the growth of the Chinese
and Indian economies. He wanted to consider offsets to
balance this.
MR. PULLIAM pointed out that the U.S. was an exporter of oil
up to the 1950s but has become increasingly dependent on
imported oil. The U.S. has been unwilling to export our oil
because of being at a deficit.
MR. PULLIAM wondered what would motivate the public to
support export. There is consensus that Alaska gas will
decrease U.S. gas by $7.5 billion a year to consumers. He
felt that it would be difficult to convince the public that
it would be in the public interest to export.
3:31:12 PM
MR. PULLIAM continued with LNG export issues (Slide 53):
· Chance of federal intervention
o Federal government assistance with permitting and
loan guarantees in 2004 likely to lead to tension
re: potential of exports
o National security concerns
o Arguments that consumers in Lower 48 would be hurt
o Probably little federal support for exports if
federal gas is involved
· Pipeline project must also apply for export permit
o But 2004 legislation specifically addresses export
to Canada
3:32:17 PM
REPRESENTATIVE GARDNER referred to a presentation by
Governor Hickel and observed that there are other parties
who believe they have valid export permits. She asked if
those permits could be used or if the federal government
could cancel them.
MR. PULLIAM explained that the permits, held by Yukon
Pacific, will need to be reviewed by the DOE. Even if the
permits are valid and can apply to this project, the process
of review will take time and engender contentious debate.
Congress could also step in if relatively high gas prices
continue.
3:34:10 PM
REPRESENTATIVE GARA wondered if there was a flip side to the
argument that would make it more likely that export would be
allowed. He thought some of the exports could go to Canada
or Mexico.
MR. PULLIAM noted that there is a faster track for exports
to other countries on the continent. Particularly Canada and
the U.S. are connected by a pipeline grid and viewed as
being part of the same market. The federal government has
already addressed the issue of oil coming through or to
Canada.
3:35:21 PM
REPRESENTATIVE GARA asked if other countries have received
export licenses for U.S. gas.
MR. PULLIAM stated that the Kenai plan had been approved and
reiterated the assumption is that the [Point Thomson] gas is
destined for the lower 48, while the gas in Kenai is not.
There had not been potential for receiving LNG gas on the
west coast so the assumption is that it would be used either
for Alaska or exported to Asia. The debate has been focused
on Alaskan consumers.
REPRESENTATIVE SAMUELS observed that Shell has stopped
drilling in the Beaufort Sea.
3:37:08 PM
MR. PULLIAM concluded with Slides 55-58:
· Gas prices in Asia are likely to maintain a premium
over U.S. gas prices, though not at current levels
· U.S. prices will likely strengthen relative to Asian
and European gas prices as U.S. domestic production
becomes more expensive and LNG flows away from the
U.S.
· LNG project would likely be viable under reasonable
price scenarios, assuming gas can be exported
o Economics of LNG delivery to U.S. West Coast
would be worse than pipeline delivery under any
reasonable set of assumptions
· Under the reasonable price scenarios, 2.7 bcf/d LNG
project offers $/MMBtu netbacks that are similar to
pipeline netbacks
o Difference in some cases is not large relative to
potential estimation error
· However, larger volumes for pipeline deliveries
produce higher overall values (NPV) for resource
owners under more likely price scenarios
· 3.5 bcf/d pipeline > 2.7 bcf/d LNG by $11Bn to
$16Bn
· 4.5 bcf/d pipeline > 2.7 bcf/d LNG by $25Bn to
$30Bn
· LNG project could produce somewhat higher NPVs if in
the long run:
· Oil prices stay high
· Gas/Oil price ratio in U.S. remains weak
· Gas/Oil price ratio in Asia stays strong
· LNG can be exported and project advances at some
time earlier than the pipeline
· Gaining Federal permission to export LNG to Asia will
likely be very difficult
· DOE permission
· Potential Federal legislation
· Export via Y-line will face similar challenges
· Federal acceptance of exporting may be more favorable
if majority of gas is already flowing to U.S. markets
· But don't count on it
· Oil experience along those lines was not
particularly favorable
· Impact of potential delays
o Delay in pipeline relative to LNG does not change
results under more likely price scenarios
· Does the State have to choose between the two
projects?
· Market-based outcome is more favorable
· Shippers can nominate to LNG project if they see
it is more economic
· Potential buyers of LNG can go "upstream" and
negotiate to buy gas
· Economics of LNG relative to pipeline not
compelling enough to suggest that the State needs
to "intervene" to make LNG happen at expense of
pipeline
RECESSED: 3:42:48 PM
RECONVENED: 3:50:18 PM
BILL WALKER, PROJECT MANAGER AND GENERAL COUNSEL, ALASKA
GASLINE PORT AUTHORITY (AGPA), thanked the legislature for
the last presentation and the opportunity to meet and
present their case with assistance from Econ One.
MR. WALKER discussed AGPA's relationship with Mitsubishi Oil
Corporation. Mitsubishi had approached AGPA the previous
year regarding Alaska LNG. During that year, Mitsubishi
looked at the financial info of the Port Authority and all
pieces of the potential project. Mitsubishi has remained
committed to the project even after AGIA and some doubts
about LNG. Both parties were hopeful that they could work
with AGIA.
MR. WALKER related that 50 percent of the LNG into Japan is
by Mitsubishi. Many of the issues about whether the gas is
too lean or too hot have been resolved. Mitsubishi is
pleased about the security of supply.
3:58:43 PM
MR. WALKER asserted that their base case is for the 2.7
bcf/d project. Less gas is required at start up. The timing
is very important as well. The work done to date gives a
significant start. AGPA is not looking at a single number to
a wellhead as a litmus test of success, although on several
scenarios, they did have the highest wellhead number.
MR. WALKER said the Port Authority was created to get gas to
Alaska and to get it there quicker. He agreed with Mr.
Pulliam's description of the issues, although he disagreed
with his conclusions.
MR. WALKER pointed out that most of the issues they had
disagreement with had been presented in Fairbanks. They have
more agreement with Econ One's economics. They would like to
get the model the administration used in order to compare
those economics. They think expansion potential is equal for
the LNG and pipeline options.
MR. WALKER stated the BTU content is not an issue; hence
Mitsubishi involvement.
MR. WALKER said that the value added was important in Alaska
and worth a significant amount in terms of jobs. Having the
facility as a fractionation unit in Valdez where the liquids
would be split off is also significant.
MR. WALKER stated the Jones Act is not a stumbling block.
REPRESENTATIVE GARA asked for clarification about first gas
to Alaskans.
MR. WALKER replied positively and said he would talk more
about the simultaneous open season.
MR. WALKER said the heart of the issue is the export license
out of Valdez. The currently existing license was obtained
by Yukon Pacific Corporation 19 years ago. There will need
to be an additional review of the license. It is not clear
if the license will be taken from Alaska. He agreed with Mr.
Pulliam that the recent export license for Kenai was for
much smaller volume.
4:06:20 PM
MR. WALKER recounted the history of the Alaska pipeline
which originally limited shipping Alaska oil to the U.S.
That remained in place until Governor Hickel's
administration. Currently there is no limitation on Alaska
to ship its resources anywhere in world.
MR. WALKER referred to predictions regarding fractured
shale. Many presenters have said that when the price of gas
is high, Alaska would be in trouble because other technology
would come forth. The Port Authority does not want to stop
the project because of concerns about what has been granted
to Alaska. He referred to a letter from DOE regarding the
export license, saying: first, that they had not heard from
the Yukon Pacific in 19 years; second, that there is a
requirement on the license about 48-hour notification to the
federal government on the first shipment of LNG out of
Valdez; and third, that there are conditions that require
notification to DOE before the export takes place. There is
a process. He urged continuing to build the all-Alaska line.
SENATOR FRENCH referred to the stance that the export
license is the number one issue for this project. He asked
what steps needed to be taken to make the license bigger and
get to a final decision.
MR. WALKER replied that not enough is being done. He said
that he needs the support of the administration and the DOE
to decide once and for all how this will benefit Alaska. He
referred to testimony in Fairbanks about the price of energy
in rural Alaska. He emphasized that this is an Alaska issue,
not a Port Authority issue. He strongly urged that all
Alaskans take control of the process. He thought the project
through Canada has some significant issues that have not
been addressed, especially land claim issues. There has been
no one from First Nations.
4:16:11 PM
SENATOR FRENCH asked when the debate about the Valdez export
license took place.
MR. WALKER answered that the debate took place in the mid-
1980s. He said that TransCanada was the only opposing party
to the license.
CRAIG RICHARDS, ATTORNEY, AGPA, did not think each source of
delay needed to be talked about. He made the point that both
projects have problems and the outcomes are unpredictable.
He urged developing both options as far as possible, so that
if one of them does not come through, the other is
available.
4:19:08 PM
MR. RICHARDS said there were two issues. There was a group
put together on the U.S. side of the project in the 1970s
and 1980s to advance the Alaska portion of the route. One of
the issues was whether the now $9 or $10 billion liability
could be put into the rate base. Credible opinion is that it
probably will not be allowed. There is still an issue as to
whether the liability holders are going to expect
TransCanada to make recompense. TransCanada has gotten
around this by saying they would not use the original
permits or data. That may or may not work. It does create a
delay. He thought that until the issues were resolved, the
project could not move forward.
REPRESENTATIVE DOOGAN stated that the export license is a
deal killer. If there is no export license, LNG cannot be
shipped. He assumed that the Port Authority has known this.
He asked why they hadn't tried to solve the issue.
MR. WALKER replied that the Port Authority has not had the
administration's support to go through the process. AGPA has
been concerned about the timing.
REPRESENTATIVE DOOGAN asked if now three governors had not
responded to AGPA's request regarding an export license.
MR. WALKER answered in the affirmative.
MR. RICHARDS added that they wouldn't go with TransCanada
either.
REPRESENTATIVE DOOGAN said he was not speaking about getting
support but getting a useful export license.
MR. WALKER stated that he believed the current
administration would support the effort. The issue was
getting through AGIA and then asking the question.
REPRESENTATIVE DOOGAN wanted a timeline regarding the LNG
export license.
MR. WALKER guessed six months on the outside.
4:25:02 PM
REPRESENTATIVE GATO asked about "Mackenzie goes first" on
the slide presentation.
MR. WALKER said Tony Palmer had answered the question in
Fairbanks by saying there is a preference in Canada for the
Mackenzie Valley project to go through first.
REPRESENTATIVE GATO asked if there would not be a preference
in Alaska that Alaska goes first. He thought that had a lot
to do with availability of materials and workforce. He
thought an opinion like that should not affect decisions
about policy.
MR. WALKER replied that two different companies have said
that it makes sense for the Mackenzie project to go first.
REPRESENTATIVE GARA pointed out that there were risks for
all projects. Until something moves forward, the outcome
will not be clear. He wondered if the AGIA process was
creating some of the problems. He referred to statements by
Mr. Palmer that the way the pipeline is going to be built is
based on the producers providing a commitment to the end
buyer. If the producers provide a 2.7 bcf/d commitment to a
buyer who takes from Valdez, then the pipe to Valdez is
built first. If there is no proposal to sell gas in Valdez,
that pipe does not go first. He asked why the project could
not move ahead.
4:29:40 PM
MR. WALKER stated that they liked the concept of the
simultaneous open season, but they have concerns. Under the
application, TransCanada has said that they would have an
open season for off-take points at Delta or Valdez in the
initial open season. If that initial open season is not
successful, then they are obligated under AGIA to continue
on with the FERC process, but only on the Canadian leg. They
are required to continue on for a second open season prior
to FERC certification, and a third open season post-
certification, but not on the LNG side. That would stop
after the initial open season.
MR. WALKER stated that TransCanada has said that if later in
the process someone was re-designated for off-take in
Valdez, they would circle back and begin the process again.
The concern is that there would be only one open season for
an LNG. The second issue would be that if there were enough
gas at the initial open season for both, the timeline would
be on the Canadian leg and not on the Alaskan leg.
TransCanada has been very clear that if at the first open
season there was enough gas for a Valdez line and not enough
for a Canadian line, they would build the line to Valdez.
There are a couple scenarios that we need to get clarified
as far as what happens post-first open season. The consensus
is that the first open season will not be successful.
Knowing that going in makes it difficult without further
clarification. He stated concerns about what was offered
later in the process.
4:34:08 PM
REPRESENTATIVE GARA requested clarification about what could
be done in the different open seasons.
MR. WALKER explained that the problem between the first and
second open seasons is that it is two or three years. If
there was no work done on the Delta Junction to Valdez
portion, he was not sure how a second nomination would work.
REPRESENTATIVE LADOUX referred to Senator French's questions
and asked why AGPA didn't get the federal permits before
now. She asked what criteria the federal government would
use in granting and denying the permits and what the state's
role would be in the process.
MR. WALKER responded that they wanted the state to testify
regarding the advantages of getting the gas to Alaska as
soon as possible. He thought the process was about getting
gas moving on a route that could be controlled.
REPRESENTATIVE LADOUX queried other criteria the federal
government would use.
MR. WALKER replied that they would look at the availability
of gas to other regions, and into the U.S. They would look
the presumption of export to say why the gas should not be
exported. They would look at the balance of payments, and at
shortages of gas into the U.S. They would also consider
price.
4:38:56 PM
REPRESENTATIVE LADOUX asked if there were anything in the
criteria that specifically addressed how the gas is
developed by the state.
MR. WALKER responded that the state is usually allowed to do
what the state feels is in its best interest. He thought the
state's interests would be considered. He said the
commitment of companies such as Mitsubishi demonstrated the
seriousness of the situation.
MR. WALKER expressed concerns that AGIA as presented has the
potential for closing out LNG options. After AGIA is
awarded, companies would have to be convinced that there is
reason for them to continue with the project. He reiterated
concerns about a disadvantage after the first open season.
These kinds of issues caused Mitsubishi to reconsider their
commitment. He wanted written clarification to be assured
that AGIA would not be a hindrance to the process. He
stressed the enormity of the issue. The Port Authority does
not want to be a hindrance to the process. They were created
to get a gas pipeline as quickly as possible and they are
concerned about impediments.
HB 3001 and SB 3001 were held in committee.
ADJOURNMENT
The meeting was adjourned at 4:43 PM. 4:45:16 PM.
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