Legislature(2011 - 2012)BARNES 124
01/25/2012 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Overview(s): Economics of Gas to Liquid and Methanol to Gasoline Conversion, Production and Shipment in Alaska | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
January 25, 2012
1:05 p.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Paul Seaton, Co-Chair
Representative Peggy Wilson, Vice Chair
Representative Alan Dick
Representative Neal Foster
Representative Bob Herron
Representative Cathy Engstrom Munoz
Representative Berta Gardner
Representative Scott Kawasaki
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
OVERVIEW(S): ECONOMICS OF GAS TO LIQUID AND METHANOL TO
GASOLINE CONVERSION, PRODUCTION AND SHIPMENT IN ALASKA
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
BRUCE TANGEMAN, Deputy Commissioner
Office of the Commissioner
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation on
Alaska's fiscal regime and incentives for gas-to-liquids (GTL).
CHERYL NIENHUIS, Acting Chief Economist, Commercial Analyst
Anchorage Office
Tax Division
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Answered questions during Mr. Tangeman's
PowerPoint presentation about Alaska's fiscal regime and
incentives for gas-to-liquids (GTL).
DAVID G. WIGHT, Principal
David G. Wight Consulting
Anchorage, Alaska
POSITION STATEMENT: Spoke about his positive work experience
with Mr. Deo van Wijk of Janus Methanol AG.
DEO VAN WIJK, Owner
Janus Methanol AG
Porter, Texas
POSITION STATEMENT: Provided a PowerPoint presentation about
gas to gasoline via methanol.
JOE DUBLER, Vice President, Chief Financial Officer
Alaska Gasline Development Corporation (AGDC)
Alaska Housing Finance Corporation
Director of Finance
Alaska Housing Finance Corporation
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation on
AGDC's gas-to-liquids economic feasibility study for the Alaska
Stand Alone Gas Pipeline (ASAP).
DARYL KLEPPIN, Commercial Manager
Alaska Gasline Development Corporation (AGDC)
Alaska Housing Finance Corporation
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: Assisted with the PowerPoint presentation
on AGDC's gas-to-liquids economic feasibility study for the
Alaska Stand Alone Gas Pipeline (ASAP).
ACTION NARRATIVE
1:05:25 PM
Co-Chair Paul Seaton called the House Resources Standing
Committee meeting to order at 1:05 p.m. Representatives Foster,
Dick, Gardner, Kawasaki, P. Wilson, Herron, Feige, and Seaton
were present at the call to order. Representative Munoz arrived
as the meeting was in progress.
^OVERVIEW(S): Economics of Gas to Liquid and Methanol to
Gasoline Conversion, Production and Shipment in Alaska
OVERVIEW(S): Economics of Gas to Liquid and Methanol to
Gasoline Conversion, Production and Shipment in Alaska
1:05:40 PM
CO-CHAIR SEATON announced that the only order of business would
be an overview on the economics of gas to liquid and methanol to
gasoline conversion, production and shipment in Alaska. He said
the reason for looking at this is the concern about declining
volumes in the Trans-Alaska Pipeline System (TAPS) and
transitioning to the pumping of heavy oil through the pipeline.
1:07:16 PM
REPRESENTATIVE P. WILSON returned to the committee's 1/23/12
overview of invasive species in which the [Alaska Department of
Fish & Game (ADF&G)] stated that the owner of the oyster farm
[in Sitka] had not taken any action. She said the farm owner
had received his contract with the state only one week before
the structure escaped in a big storm. For two years things had
gone on and he was not allowed to go onto the premises and she
did not want anyone to think that the owner was at fault. The
owner could not do anything with the oyster farm and could not
make any money with the farm, so is in the hole because of this.
CO-CHAIR SEATON pointed out that [legislators] specifically
asked that an emergency protocol be developed and he did not
want to get into the situation of blaming. He said he would
like the committee to have the Division of Agriculture and ADF&G
come forward with mechanisms for avoiding this in the future.
This immediate problem has to be resolved, and it must be
ensured that these kinds of problems for addressing an issue do
not come up in the future. He related that [the committee's]
intention is to go forward with legislation if needed or
regulations if legislation is not needed so that there are no
roadblocks for handling an emergency in the future.
CO-CHAIR FEIGE asked whether the oyster farm owner was not
allowed on the structure for the week prior to its breakup or
the two years prior to the breakup.
REPRESENTATIVE P. WILSON replied that the owner was not allowed
for two years and then a week before the breakup [the
department] decided there should be a contract with the owner so
he could go back onto the structure and do something.
1:10:20 PM
CO-CHAIR SEATON returned to the overview, saying that Department
of Revenue Deputy Commissioner Bruce Tangeman would provide the
first of four presentations.
BRUCE TANGEMAN, Deputy Commissioner, Office of the Commissioner,
Department of Revenue (DOR), noted that a positive for Alaska is
its resource on the North Slope (slide 1). Regarding DOR's role
in any gas utilization discussion, he said it is not the
department's responsibility to define what incentives the
private sector may need to move forward with a gas-to-liquids
(GTL) project or any other gas project. It is the private
sector's responsibility to analyze the state's existing tax
structure, point out the hurdles it may perceive as being
barriers, and begin the dialogue as to possible solutions for
moving forward on a potential project. While DOR's incredible
team creates and operates models like he has never seen before,
the department is by no means the expert in GTLs or any other
gas utilization concepts.
1:13:23 PM
MR. TANGEMAN said there are several question marks on every
slide in his presentation but not many answers. This is because
he is here to point out some of the issues the committee needs
to keep in mind as it discusses GTLs or any other gas
utilization concept moving forward. It is important to know
DOR's role in the process as well as that of other state
agencies such as the Alaska Oil and Gas Conservation Commission
(AOGCC). Both DOR and AOGCC will be key players in future gas
utilization discussions.
MR. TANGEMAN reported that roughly 90 percent of Alaska's
general fund revenue comes from the four petroleum revenue
sources of royalty, production tax, corporate income tax, and
property tax, which constitute Alaska's fiscal regime for oil
and gas (slide 2). Any GTL project in Alaska would likely pay
one or more of these elements to the state, and any potential
hurdle that the industry might bring forward to discuss for
incentivizing will no doubt reside in one of these four areas.
1:14:58 PM
MR. TANGEMAN pointed out that Alaska's Clear and Equitable Share
(ACES) production tax (slide 3) is the largest element of the
fiscal regime in terms of revenue and is potentially the most
likely element of the fiscal regime with which to create
incentives. However, it is the most complicated tax structure
in North America and perhaps the world. He said there are two
important concepts when relating production tax to GTLs: 1)
Production tax is calculated on the gross value at the point of
production (GVPP) minus qualified capital and operating
expenditures. This has relevance in terms of a GTL plant's
location and what costs of a GTL plant, if any, would qualify as
deductions under ACES. 2) Production tax is levied on companies
that produce the gas and these companies may not be the ones
that build the GTL plant. One of the variables is who is going
to own the plant itself.
MR. TANGEMAN discussed two questions that need to be answered
with respect to GTL (slide 4): 1) Where will the GTL plant be
located? 2) Who will own the plant, the gas, and the GTL
products, and what will be the fiscal arrangement of any
structure that is put in place? Regarding where to locate the
GTL plant (slide 5), he noted that location of the plant makes a
big difference in how the economics will play out. Facility
siting is important because if the plant is located anywhere
other than the North Slope or Cook Inlet the gas will need to be
transported to the plant to begin the GTL process, and this will
add additional costs to the project.
1:17:07 PM
REPRESENTATIVE P. WILSON requested Mr. Tangeman to explain the
difference in economics that plant location would make to the
state and to the producer.
MR. TANGEMAN replied that it would impact both the state and the
producer, mainly depending on the capital investment that is
required. If gas must be transported to the plant over a long
distance, capital investment to pipe the gas would possibly be
affected by the tax credit system currently in place, which
would be a drag on state revenue and would offset some of the
costs that the companies would incur. In further response, he
confirmed that he is saying the difference is the upstream costs
before the gas gets into the pipe.
1:18:20 PM
CO-CHAIR SEATON theorized that if the GTL plant was on the North
Slope, what is transported would hypothetically go into TAPS, a
currently existing pipeline; but a plant located elsewhere would
require the expense of transporting gas to the plant as well as
the expense of transporting the end product. He asked whether
this is part of the relationship being looked at regarding the
economics of where the plant is located.
MR. TANGEMAN answered that that is part of it. For example, if
a plant was located in Fairbanks, a pipeline would need to be
built to Fairbanks where the gas would be processed and from
there it would presumably go to TAPS, which is where the tariff
would kick in. Because many variables and scenarios could be
created and modeled, a simple way to start thinking about plant
location is to assume it is somewhere close to TAPS and then
look at how far the gas will have to be transported to the GTL
plant itself.
CO-CHAIR SEATON noted that when transmitting gas the tariff on
the gas is subtracted from the value of the gas, and the company
must transmit the product that it will be using up in the
conversion process. If the facility was on the North Slope the
volume through TAPS would be more, so the tariff on all of the
oil and other products would be lowered. Those elements must be
considered, but the purpose for today is to just get a handle on
the issues.
1:20:59 PM
CO-CHAIR FEIGE surmised that with no pipeline to the plant there
would not be that transportation cost, so the check per million
cubic feet (MMCF) to the producers for the gas would be higher.
MR. TANGEMAN replied, "To the gas producers, yes; well, it
depends."
CO-CHAIR FEIGE further surmised the gross value at the point of
production would be higher because ...
MR. TANGEMAN interjected that it depends where the GTL plant
owner is taking ownership of the gas.
CO-CHAIR FEIGE asked where the tax would apply to the gas under
current statutes, assuming the GTL plant is a separate entity
and assuming that that entity takes possession of the gas as it
comes into the GTL plant.
MR. TANGEMAN deferred to Ms. Nienhuis.
1:22:25 PM
CHERYL NIENHUIS, Acting Chief Economist, Anchorage Office, Tax
Division, Department of Revenue (DOR), said she would guess that
it depends on the fiscal arrangement. Qualifying that she could
not say for certain, she said it seems like Alaska's point of
production statutes require that when a petroleum product is
accurately metered, that is considered the point of production.
So, if that occurs upstream of the gas pipeline then that would
be the taxation point under current statute.
CO-CHAIR SEATON noted that the point of production is determined
by statute and therefore that issue could be looked at if the
economics needed to be changed; the state legislature can set
the point of production for taxation. He presumed the state is
not stuck in one system and could change it.
MS. NIENHUIS responded she cannot comment because there could be
other elements to the point of production that fall outside of
the taxation realm, such as impacts to royalty.
CO-CHAIR SEATON said he was just clarifying that that is set by
the legislature. For a bill dealing with GTLs and incentives
the legislature would probably need to specify the point of
production for taxation.
MR. TANGEMAN agreed.
1:24:08 PM
MR. TANGEMAN returned to his presentation and the second of the
two questions that need to be answered with respect to GTL
(slide 6): "Who owns the plant, the gas, and the GTL products?"
He said the owner could be the North Slope gas producers, the
Cook Inlet gas producers, or a third party. For example, the
GTL plant could be set up similar to the Alyeska Pipeline
Service Company, which is an independent third party
owner/operator. Will the gas be transferred to the GTL plant
owner or sold to the plant owner/operator? Who, if anyone, will
need incentives is what will need to be fleshed out.
CO-CHAIR SEATON related a past situation of a producer that
wanted to put an ultra-low-sulfur diesel refinery on the North
Slope. The proposal was to have it on the lease so that it
would qualify for the credits and it would be on the lease so
there would be no royalty. The legislature said that was not
the purpose of the ACES credits. If the legislature decides it
wants something like that, then the legislature would have to
make the change. The legislature determined that a refinery
placed on the North Slope was not upstream of the point of
production regarding the 20 percent tax credits.
1:26:05 PM
MR. TANGEMAN said the aforementioned leads directly to slide 7
which depicts four potential areas where incentives could be
manipulated to make a project economic. Referring to these four
areas as "knobs," he said there are many available knobs that
can be turned to incentivize a GTL plant, a gas plant, or any
infrastructure the state sees fit for commercializing North
Slope resources. Each situation calls for a different knob to
be turned and will affect all of the other knobs in a different
manner. For example, royalty relief or tax credits could be
granted to producers selling gas for feedstock to the GTL plant
owner. Corporate income tax credits could be issued for work
leading up to the construction of the GTL plant. Or credits
could be granted for research into feasibility of shipping GTL
products down TAPS.
1:27:46 PM
MR. TANGEMAN pointed out that the price of gas is a huge, huge
consideration when considering the economics of a GTL project
(slide 8). Yesterday the Henry Hub price of gas was $2.63 [per
MMBtu], he related. There is plenty of potential, but the state
needs to hear from the private sector (slide 9). It is known
from modeling done for legislator's that there are a lot of
variables that can be plugged into a model depending on what is
being looked for, and the outcomes are going to vary depending
on what is put in on the front end. So, it is important for the
department, the legislature, and the state in general, to get
more detailed feedback from the private sector as to what are
the issues and hurdles that they see and need help on to make a
project like this economic.
1:29:46 PM
MR. TANGEMAN concluded by stating that GTL is one of several
options for developing Alaska's gas resource. Incentives depend
on the state's desired outcomes - with a very strong incentive
just about anything can be done. Incentives are possible
through production tax, royalty, corporate income tax, property
tax, and other subsidies. Determining the goal is the bottom
line. For example, is the goal to create jobs, diversify the
state's economy, or to fully develop Alaska's natural gas
through one major project? Instead of "or" the word "and" could
be used, so there are a lot of things to be considered when
trying to figure out the best way to commercialize the state's
resources on the North Slope.
1:30:42 PM
CO-CHAIR SEATON opined that sometimes industry does not present
things because it figures the legislature would not consider
them. Sometimes the state's various problems are addressed in
isolation, including whether GTL is economic, so it was good to
learn that where the GTL plant is located makes a difference.
Another example is that if GTLs were produced on the North Slope
the throughput in TAPS would be increased, and a dilutent
produced on the slope could help with viscosity and
transmissibility at low flows. Another real problem is taxes
where there is [both] oil and gas. Right now gas sales
effectively are not taking place, but once they do and
investments are made there is a huge potential problem in
applying expenditures for gas, which are taxed at a low rate,
against the tax rates for oil, which is the decoupling issue the
legislature has looked at before. He asked whether Mr. Tangeman
sees any problems for GTL or other liquid if, instead of taking
royalty and production tax on gas, the outlet of the plant is
determined the point of production so that royalty and tax is
taken on the manufactured liquid at the end. This would tax the
right value stream, he continued, because it would relate to the
price of oil, which is where progressivity is, and would
eliminate the need for differentiating investment in gas or oil.
This would solve a multitude of problems at the same time
instead of one at a time. He reiterated his question by asking
whether DOR sees this as a potential, with statute change, point
of production clarification, and willing partners, to eliminate
the decoupling issue.
1:34:41 PM
MR. TANGEMAN said he thinks that will be a very, very big issue
if something like this progresses. This goes back to the
current debate on ACES and the governor's bill [HB 110]; it is
that tax on the output. So taxing it as a petroleum/oil product
falls back into the discussion of last session and the interim
about how industry is going to view that and whether that is the
main hurdle. If that is the main hurdle and industry says it
needs relief on the production tax, then that is what will make
a GTL project go or not go.
1:35:42 PM
CO-CHAIR SEATON added that the problem with taxing gas at barrel
of oil equivalents is that comparison-wise it is a product that
has very low unit value, so that problem is not escaped nor is
the problem of having to differentiate investment. He said he
does not know whether industry is hearing that [the committee]
is willing to look at those issues and not have to deal with
decoupling. He asked whether DOR sees anything that would
prohibit this from being done with the proper legislation, which
would be taking royalty and production tax on the output and not
taxing the input to a plant under the right circumstances.
MR. TANGEMAN responded he does not see that [the committee] is
prohibited from doing anything as a legislative body. It is
whether it will be economic and the bottom line is how industry
is going to view any change that is made. Whether it is on the
gas as the entry point into the plant or the petroleum product
as the exit product into TAPS is the biggest discussion.
Decoupling will be discussed in the other body so it is
certainly on everyone's radar.
1:37:24 PM
CO-CHAIR SEATON reiterated that he is trying to figure out
whether taxing oil on the outlet side will eliminate the big
problem with decoupling, because decoupling is taxing at a very
low rate and allowing investment to be written off against the
other tax rate if oil is being produced.
MR. TANGEMAN pointed out that another big issue with decoupling
is the cost allocation - whether the cost of the plant is on the
upstream side with the gas or the downstream side with the
product or somewhere inside the plant.
CO-CHAIR SEATON agreed.
1:38:19 PM
CO-CHAIR SEATON directed attention to DOR's 1/18/11 letter in
the committee packet regarding an economic analysis of Alaska
North Slope gas-to-liquids plant. He offered his appreciation
for the caveats included in the analysis because they allow for
asking about what would happen if the royalty is not on the gas
but is on the GTL product. He urged members to look at the
internal rates of returns and the net present values in the
analysis because that is helpful information for understanding
whether the project is in the range of being economic and
whether any changes need to be made.
1:40:25 PM
CO-CHAIR SEATON then referred an attachment to the DOR letter
entitled, "Additional Information on Gas-To-Liquids." Regarding
BP and advances in GTL technology [page 2 of the attachment], he
read the following statement: "... the reaction is highly
exothermic and the reactor must be designed to remove heat
quickly." He inquired whether there has been any analysis of
the amount of heat to see whether it could be used for heating
the oil being moved through TAPS.
MR. TANGEMAN said the aforementioned falls under the category of
DOR not being an expert in GTLs.
1:42:13 PM
CO-CHAIR SEATON provided a biography of the next speaker, David
G. Wight: served as president and chief executive officer for
Alyeska Pipeline Service Company from July 2000 to January 2006,
served as president of BP Amoco Energy Company in Trinidad and
Tobago for eight years, and served as treasurer of the Alaska
Oil & Gas Association. He said Mr. Wight's Amoco career
involved him in activity in Texas, Kansas, Oklahoma, Colorado,
Utah, Alaska, and Illinois where Mr. Wight developed
engineering, operation, production, procurement, and management
experience. Further, Mr. Wight served as the president of Amoco
Trinidad, an exploration and production company, and he led the
establishment of the first greenfield liquefied natural gas
(LNG) plant in Trinidad and the second LNG plant in the Western
Hemisphere. Co-Chair Seaton explained that Mr. Wight, a person
familiar to committee members, will be relating his experience
working with Mr. Deo van Wijk of Janus Methanol, someone who
committee members are unfamiliar with although Mr. van Wijk did
make a presentation to the committee last year.
The committee took an at-ease from 1:44 p.m. to 1:50 p.m.
1:50:37 PM
DAVID G. WIGHT, Principal, David G. Wight Consulting, stated
that he was asked by the principal of Janus Methanol, or
GigaMethanol, to facilitate discussions of [Mr. van Wijk's] gas
to methanol to gasoline proposal. He said he accepted the
opportunity because he has done business in the past with [Mr.
van Wijk's] company and its innovative technology, and he feels
that it is an opportunity for Alaska to look at some ways to
monetize its gas. He said the state should look at [Mr. van
Wijk] to see if this fits some of the state's opportunities to
move its gas to market.
MR. WIGHT said his experience with Janus Methanol comes from
Trinidad where his company at that time, initially Amoco and
then BP Energy, was an energy supplier. Mr. van Wijk came to
Amoco wanting to enter into a long-term gas supply agreement for
his double-world-scale methanol proposal, which he had developed
the technology on. Amoco found it a good business opportunity
and entered into a contract. Mr. van Wijk's facility performed
as proposed - delivering on time and within cost, and during the
period of time that he [Mr. Wight] remained in Trinidad, Mr. van
Wijk met the gas purchase requirements of the agreement with
Amoco. Since that time, Mr. van Wijk sold his interest in that
facility and entered into a non-compete agreement. During that
non-compete period of time on methanol Mr. van Wijk studied the
technology and developed the proposal that he would like to
speak to Alaska about.
1:53:00 PM
MR. WIGHT said Mr. van Wijk's proposal this time is twice as big
as the one built in Trinidad, so on a world-scale basis it has
doubled again. It uses less energy than the previous time and
with an incremental capital cost it takes methanol, which is
very difficult to transport due to its corrosive nature, and
turns it into gasoline thereby affording the opportunity to put
it into TAPS, which would be very beneficial in terms of
transportation costs.
MR. WIGHT said he has had successful business relationships with
Mr. van Wijk in the past and has found him to be a very
credible, innovative technology leader and a very credible
business person.
1:54:16 PM
MR. WIGHT explained that Mr. Van Wijk's proposal would start
with a single train facility that would use about 320 million
cubic feet (MMCF) of gas per day and would produce 30,000
barrels of gasoline per day that could be put into TAPS.
Advantages to this include: no incremental pipeline costs
because existing facilities could be used; improvement of the
flow characteristics in TAPS because it is a lighter part of the
hydrocarbon stream; no corrosive natures; and the addition of
volume - all of which are significant issues currently being
considered. Because it is a capital investment on a single
train facility it clearly is more cost effective because it does
not have the pipeline cost that other facilities must look at
for moving liquids or natural gas all the way to the
marketplace. Mr. Wight said the disadvantage is it does not
provide gas for in-state use. But, he added, it does not take
away from that opportunity because the opportunity is
incremental on volumes that would be available and would not
prevent continuing to look at pipelines or other activities.
1:56:47 PM
MR. WIGHT allowed that some science and economics need to be
worked on, but said the scoping economics look good. Another
advantage if this works properly, he continued, is the
opportunity to incrementally add both to the use of gas and the
volume that could be put into TAPS in steps, which could be key
to the availability of gas from the North Slope as producers
need less gas for enhanced oil recovery and have some marketable
gas. Additional trains could be scheduled incrementally to up
the volume of gas utilization and monetization, with each train
adding another 30,000 barrels of incremental liquids to the
pipeline.
MR. WIGHT concluded by saying he thinks this has huge potential
for early and incremental monetization of gas and that it merits
serious further discussions and development opportunities with
this company. He related that as an Alaskan and someone
involved in the energy business a long time, he has continued to
look at how to meet some of the challenges of highly expensive
gas pipelines that require high volumes and seem to be the
significant impediment to Alaska's ability to monetize its gas.
He urged that this opportunity be looked at very, very carefully
because it would move the state beyond those impediments.
1:59:29 PM
CO-CHAIR FEIGE inquired about the effects that gasoline would
have on the refineries located along TAPS which utilize the
throughput to produce refined products.
MR. WIGHT understood Co-Chair Feige to be asking about the
downstream impact on in-state and out-of-state refiners that buy
Alaska's product. He said that based on the science known today
it would be a "quality bank" upgrade to the refining value of
the TAPS crude and would therefore have a positive impact on the
economic value and the value and use to refiners in Alaska and
other places.
2:01:06 PM
REPRESENTATIVE MUNOZ asked how gas and oil are shipped at the
same time and what the impact of heavy oil would be on that mix.
MR. WIGHT replied that this is an excellent question because in
the Lower 48 some pipelines operate on a batch system, changing
the product that they ship from time to time. He related that
in his asking of some preliminary questions, it seems to be the
most attractive way to mix it, which means it cannot be taken
out by itself at some later point and would have to be re-
refined by the refineries. However, it would reduce the
viscosity and help the flow characteristics. It would not be at
all incremental damaging to the wax issues - and might help
some, although that answer is not known right now - so it would
be just part of the mixed product. Regarding heavy oil,
incrementally it would have a positive impact on both the volume
and the viscosity, whether it is today's conventional crude or
the challenging heavier oil, because it is lighter and would
reduce the viscosity.
2:02:52 PM
CO-CHAIR SEATON pointed out that the Alaska Gasline Inducement
Act (AGIA) was done to enhance exploration on the North Slope so
there would be a market for gas going into a common carrier
pipeline with rolled-in rates. The problem being looked at with
a smaller pipeline is that the existing players with natural gas
could fully commit that line and therefore oil exploration would
not be enhanced because any gas found in that exploration would
be a non-sellable product. The nice thing about GTL is that if
a small diameter pipeline is filled with gas for the state,
there would still be an incentive to explore for gas because of
the incremental GTL market. He said [the committee] is not
necessarily saying that this is one or the other, but that more
than one way might be needed to monetize gas to get the benefits
of enhanced exploration, discovery, and production into TAPS.
For example, a field that is mostly gas with some liquids is
uneconomic if the gas cannot be sold.
2:05:30 PM
DEO VAN WIJK, Owner, Janus Methanol AG, first pointed out that
his company does not want to build gas pipelines, it wants to
build plants on top of where the natural gas is (slide 1).
Regarding the idea of building a pipeline to transport 4.5
billion cubic feet (BCF) of natural gas to the Lower 48, he said
that at today's economics the natural gas at the North Slope
would have a negative value. His company is trying to solve
Alaska's problem on TAPS as well as create value for the natural
gas at the North Slope. He explained that 4.5 BCF of gas a day
is the equivalent of 14 trains or 430,000 barrels a day, which
is huge and a project that would probably take 15 years to
build. Also being created, however, is increased value of the
crude oil because its viscosity and quality would be improved.
He reiterated that a pipeline is not built for moving the gas to
somewhere, instead a plant is built on top of where the gas is.
2:07:16 PM
MR. VAN WIJK said the purpose of his presentation is to explain
the idea of methanol to gasoline, which may sound like a new
idea but is a 30-year-old technology developed by Mobil in 1982
(slide 2). However, it became uneconomic in the 1990s when the
price of oil dropped to $10 or $12 a barrel. On top of that,
Exxon purchased Mobil and the technology disappeared except for
the Chinese who are checking out every technology worldwide and
have the money to build and do it. Today there are two methanol
to gasoline (MTG) plants which have proven to work. Alaska's
problem is that as oil production reduces in volume its
viscosity increases. Janus Methanol is saying the state should
convert its natural gas to gasoline, rather than his original
idea of methanol. Unlike methanol, gasoline does not have
corrosive issues and can be put into the pipeline and sent with
the oil to refineries in California or elsewhere.
2:09:17 PM
MR. VAN WIJK stated Janus Methanol believes it has a potential
solution for the TAPs problem as well as the sale of large
volumes of natural gas at relatively high prices (slide 3). No
other alternatives come even close to the gas prices that his
company could afford to pay to turn natural gas into gasoline.
The gas-to-liquids (GTL) Fischer-Tropsch process has by-products
like waxes, and what can be done with waxes in Alaska? Janus
Methanol makes only three products - high grade quality
gasoline, a little bit of liquefied petroleum gas (LPG) for
which there is a local market in Alaska, and water.
2:10:31 PM
MR. VAN WIJK noted that Janus Methanol is a Swiss-based company
with about 30 people with a total of about 500 years of methanol
experience (slides 4-5). Some persons have 30 years or more in
the methanol business; for example, he has been in methanol
since 1977 and has done nothing else but methanol. Ten people
have more than 30 years' experience each, the rest have less.
The company's engineers are German doctors, called PhDs in the
U.S., from a variety of companies, such as BP, Lurgi,
Ferrostaal, and [KTI/Mannesmann and Metallgesellschaft]. Moving
to slide 6, he said a virtual depiction of the slide shows
several plants in 1989 and those same plants in 2009, with the
growth of the plants being an investment of about $15 billion;
he personally built three of the plants in the picture. In
response to Co-Chair Seaton he said it is a remarkable
difference in 20 years.
2:12:35 PM
MR. VAN WIJK advised that Janus Methanol is suggesting for the
North Slope a two-train project of 7 million tons of methanol;
the two plants being built with a difference of about two years
(slide 7). The second train would be substantially cheaper than
the first because of utilities, site preparation, and so forth.
The plant would produce about 2.66 million tons of methanol,
about 350,000 tons of LPG, and about 4 million tons of water.
He explained that 56 percent of methanol is water and when the
water is taken out the remainder is gasoline, methanol, and LPG.
MR. VAN WIJK discussed the first phase of investment, explaining
that Janus Methanol has studied building a facility like this
one in the U.S. Gulf (slide 8). A plant of the size being
talked about would, in the U.S. Gulf, cost about $3.5 billion.
From talking with the industry, he used a multiplier of 2.2 to
get to a price of $7.7 billion for the investment on the North
Slope, and a study would be required to confirm those numbers.
Revenues would be around $3 billion per year and the plant
should pay in 5 to 6 years after starting production.
2:15:00 PM
MR. VAN WIJK said he has done nine methanol plants in his life,
seven or eight utilizing Lurgi technology (slide 9). He would
again use Lurgi methanol technology and the ExxonMobil MTG
technology that has been proven in both New Zealand and China.
At 20,000 pounds a day - two trains of 10,000 pounds each - this
methanol plant would be by far the largest methanol complex ever
built in the world. He pointed out that 7 million tons of
methanol would flood the methanol market, but its conversion to
2.66 million tons of gasoline would be a drop in the bucket in
the world market of gasoline and thus the original chemical
market would not be destroyed.
MR. VAN WIJK explained the differences between Janus Methanol's
previous plants and what it is designing today. Today's plant
would be smaller and simpler than the one in Trinidad and at
10,000 tons [methanol] per day the cost would be substantially
reduced. The seven-stage compressor has now been changed to a
booster, and even with a spare booster $17 million Euros would
be saved.
2:18:12 PM
MR. VAN WIJK drew attention to a photograph of Janus Methanol's
ATLAS and Titan methanol plants in Trinidad (slide 11) and
explained that the steam reform and compression equipment shown
in the picture would be eliminated in the next plant design,
which would reduce the cost by about 30 percent. He said that
in 2008 the ATLAS methanol plant ran at 108 percent of design
capacity - 5,000 tons per day - for 360 days, which is quite
remarkable. Reviewing the major sections of the ATLAS plant
(slide 12), he said that the air cooling seawater unit shown on
the left is substantial and difficult to deal with and the
distillation section [at the top of photograph] will always be
needed. In looking at where money could be saved, Janus
Methanol determined that it would be the syngas compression and
the syngas generation. He moved to the layout of two 10,000 ton
methanol per day plants (slide 13) and noted that the MTG plants
would come behind them and that those plants would be smaller
than the ATLAS methanol plant in Trinidad.
2:20:40 PM
MR. VAN WIJK explained that with gas-to-liquids/Fischer-Tropsch
process the gas must be taken to another place and by-products
will be produced that the state may or may not know what to with
(slide 14). However, for methanol to gasoline the products are
LPG, water, and gasoline, and the gasoline is ready to go into
the pipeline. In response to Co-Chair Seaton, Mr. van Wijk
confirmed that LPG is propane.
MR. VAN WIJK said many companies have spent a lot of money on
Fischer-Tropsch (slides 15-17). Only Mobil, now taken over by
Exxon, and the Chinese have researched a way to go from methanol
to gasoline. The [MTG] technology can be licensed from
ExxonMobil, he advised, and the methanol technology that Alaska
would need can be licensed from Lurgi and Janus Methanol has
certain rights to that. The key on [MTG] technology is the
catalyst. ExxonMobil has licensed its catalyst [to Janus
Methanol] and [Janus Methanol] will soon have a contract with
another company for a catalyst as well. Additionally, Janus
Methanol is working on making a jet fuel catalyst. He explained
that two plants in China are gigantic because they are coal-
based methanol to gasoline plants (slides 18-19). He related
that 80-90 percent of the cost is in the coal gasification and
the rest is in the MTG part.
2:22:39 PM
MR. VAN WIJK reviewed the specifications of the [MTG] gasoline
(slide 20), saying it is very low in benzene and that it has no
sulfur, which substantially increases the quality of the oil.
Comparing GTL with MTG (slides 21-22), he reiterated that MTG
only makes LPG and gasoline, whereas GTL has a whole range of
products and another refinery would have to be built to get [to
conventional fuels]. Thus, the process being proposed by Janus
Methanol is much simpler and more direct.
MR. VAN WIJK related that ExxonMobil compared the costs of GTL
to MTG (slide 23). However, because of its developments, Janus
Methanol can come substantially below the numbers depicted on
the slide because ExxonMobil used a much smaller investment and
Janus Methanol would be looking at 10,000 tons per day.
MR. VAN WIJK, moving to slide 24, stated that the only thing MTG
does not produce is diesel which, he allowed, is an advantage
[of Fischer-Tropsch] and something that can be talked about. He
again reiterated that MTG has no by-products and is a much
simpler and cheaper process.
MR. VAN WIJK concluded by saying that Alaska has a problem with
TAPS and Janus Methanol could add every two years 30,000 barrels
a day to the pipeline and thereby the pipeline could be kept for
a long time to come. He offered to come to Alaska to discuss
this in more detail if legislators wish.
2:24:55 PM
CO-CHAIR SEATON understood that Mr. van Wijk will be coming to
Alaska to talk to gas producers. He expressed his hope that
there are commercial agreements that can be met. He added that
the legislature, or at least the House Resources Standing
Committee, is willing to look at what can be done to enhance the
opportunities for commercializing gas on the North Slope.
MR. VAN WIJK responded that it is the legislator who plays a
very important role in this and if legislators decide to
investigate this further, things will happen. He related MTG to
the saying, "What a farmer doesn't know he doesn't eat," and
said the oil companies are very familiar with GTL, but [MTG] is
news to them.
CO-CHAIR SEATON replied that legislators will be asking the oil
companies specific questions on MTG.
2:26:21 PM
REPRESENTATIVE HERRON noted that Mr. van Wijk is pursuing a
market opportunity and asked whether a five-year horizon is the
criteria.
MR. VAN WIJK replied that it would be more like six to seven
years, including MTG and financing. This has potential geo-
political, geo-social, and geo-economic consequences, he
continued. Lots of countries, including China, have found shale
gas, which can be converted into gasoline, and this makes them
less dependent on the Middle East and countries like Venezuela
because gasoline is the largest outlet for oil. Shale gas and
natural gas are so readily available and becoming so cheap that
making gasoline out of them is dirt cheap compared to oil. It
is the equivalent of maybe $40 a barrel and in 10-15 years this
will have a huge impact worldwide.
2:28:36 PM
JOE DUBLER, Vice President, Chief Financial Officer, Alaska
Gasline Development Corporation (AGDC), Alaska Housing Finance
Corporation, Director of Finance, Alaska Housing Finance
Corporation, Department of Revenue (DOR), introduced himself,
his colleague Mr. Daryl Kleppin, and Dr. William Davey from
Hatch Associates who produced the [gas-to-liquids] report being
discussed today.
REPRESENTATIVE P. WILSON inquired whether gas to gasoline fits
into the category of gas-to-liquids (GTL).
MR. DUBLER replied that gas to gasoline is a different process
and he and Mr. Kleppin will be discussing the Fischer-Tropsch
process, which has been around since World War II and converts
[gas] either to jet fuel or diesel fuel rather than gasoline or
methanol.
2:30:05 PM
MR. DUBLER first discussed why this GTL study was done,
explaining that AGDC was tasked with preparing a report for the
legislature about an [Alaska Stand Alone Gas Pipeline (ASAP)]
from the North Slope to Southcentral and Fairbanks (slide 2).
Going into the study it was known that the upper limit was half
a billion cubic feet per day, the Alaska Gasline Inducement Act
(AGIA) restriction, and the lower limit was zero since a
negative number cannot be shipped. However, AGDC did not know
where to target throughput for the gas pipeline, so it
identified likely customers for the natural gas product that
would be shipped and tailored the report to the most likely
scenario of customers for that gas. Not knowing whether any of
the commercial anchor tenants would be viable, AGDC commissioned
three different studies: liquefied natural gas (LNG), which is
similar to what ConocoPhillips Alaska, Inc. did for years in
Nikiski; natural gas liquids (NGLs), and gas-to-liquids (GTLs),
which is the study being discussed today.
MR. DUBLER stressed that the three studies were commissioned not
as a way of ruling out any one, but for giving AGDC a confidence
level in preparing its report that the throughput projected for
ASAP was reasonable. Based on the study results, AGDC found
that at least one of the three provided a sufficient netback,
which is the price that the North Slope producers get for their
gas after the tariff is taken out of the cost of the gas at the
end of the pipeline. For example, Mr. Dubler continued,
Southcentral and Fairbanks combined use about 240 million cubic
feet (MMCF) per day. If all three studies had come back that
any of these would be unlikely to produce a profit for a
company, then AGDC would have stuck with 240 MCF as the
throughput on the pipeline. However, it was found that the
throughput could go up to the maximum of half a billion cubic
feet per day because AGDC thinks there is a very high likelihood
that one of them will work.
2:32:38 PM
DARYL KLEPPIN, Commercial Manager, Alaska Gasline Development
Corporation (AGDC), Alaska Housing Finance Corporation,
Department of Revenue (DOR), directed attention to a diagram of
the gas-to-liquids (GTL) process (slide 3). He said that
Fischer-Tropsch technology is a proven process that has been
around since World War II. The guidelines to [Hatch Associates]
were to use proven Fischer-Tropsch technology. As with methanol
to gas, Fischer Tropsch is not an incredibly efficient process.
The Hatch study assumed a 57 percent efficiency in terms of
converting input British Thermal Units (BTUs) to output BTUs in
the liquids, and also assumed that some of the steam would be
used to generate electricity for sale.
MR. KLEPPIN explained that the Fischer-Tropsch process tends to
be high temperatures, 1,500 - 2,000 degrees Fahrenheit, and high
pressure, with some of the vessels running between 300 and 1,500
pounds per square inch (PSI). The model looked at three
different scenarios - one train, two trains, and four trains -
at two different locations. A typical Fischer-Tropsch train
produces about 16,000 - 17,000 barrels a day. The base case for
the study assumed two trains. The two locations were a Cook
Inlet site [Port MacKenzie] and a Fairbanks site.
2:34:48 PM
MR. KLEPPIN, moving to slide 4, noted that of the three cases
depicted, Case B, the base case, produces roughly 33,000 barrels
of liquids per day. He said the Fischer-Tropsch process can
produce several products, the primary ones being diesel,
naphtha, and jet fuel. The study looked at the combination that
would create the largest value and in the base case it was
assumed that roughly 74 percent of the product was diesel and
the other 26 percent was naphtha. A market analysis of where
that mixture of products would receive the highest price was
also done, with Alaska being one market and Hawaii, the West
Coast, and the Far East the other markets.
MR. KLEPPIN said the schematic on slide 4 provides a simplified
view of what a facility would like and slide 5 shows what the
GTL facility would look like. He explained that the acronym for
auto thermal reactor is ATR. Continuing, he said the first step
in the GTL process is to create a syngas, which is a mixture of
carbon monoxide and hydrogen. The next step is the Fischer-
Tropsch synthesis, followed by upgrading where the material is
broken into the components of diesel and naphtha.
2:36:45 PM
MR. KLEPPIN related that there are a number of considerations
when looking at a site, with transportation showing up as a key
consideration under construction and under operation. Regarding
the transportation issue, he directed attention to the
photograph of a Fischer-Tropsch reactor on slide 6 and noted
that a comparison of the people standing next to the reactor
shows how big the reactor is. What that means for construction
costs is that modular construction can be done at a Cook Inlet
location, but at a Fairbanks location the reactor would have to
be stick built, which means a higher capital cost.
CO-CHAIR SEATON inquired whether modules would be available for
shipment to the North Slope and further asked whether the North
Slope was specifically excluded or just not analyzed.
MR. KLEPPIN responded that a North Slope location was excluded
because AGDC was looking at utilizing a gas pipeline and what an
anchor tenant might be or where an anchor tenant might be in a
gas pipeline, and if the GTL facility was located on the North
Slope there would be no need for a gas pipeline to the GTL
facility.
2:38:28 PM
MR. KLEPPIN, returning to his presentation, said that climate
considerations for stick building the modules in Fairbanks would
lower the productivity and that is the basis for the capital
difference between Anchorage and Fairbanks; however, on the
operational side it switches. He added that a facility of this
size would have roughly 200 to 300 full-time employees and this
is incorporated into the operating costs.
MR. KLEPPIN reviewed the study's capital expenditure (CAPEX)
estimate basis (slide 7). Assumptions included that it would be
a greenfield and a new build GTL facility, that the two trains
would produce roughly 33,000 barrels a day, and that the base
case location would be at Port MacKenzie. Because the ASAP
project report was issued in July [2010], this Hatch report
assumed that all the costs are in 2010 dollars, but later
reports apply a 3 percent escalator to get to 2011 dollars. The
cost estimate is a Class 4 estimate, which means the accuracy is
on the order of plus 40 percent or minus 30 percent. This wide
range of uncertainty is because limited engineering has been
done. The Hatch study used existing facilities and tried to
scale them, accounted for climate variations and transportation
costs, and used specific quotes for different pieces of
equipment.
2:40:40 PM
MR. DUBLER acknowledged that the cost estimate is very broad,
but said the only way to narrow that down was to spend a lot of
money on engineering and actually design the facility, which was
not in the scope of the project.
MR. KLEPPIN continued, advising that the engineering is less
than 1 percent complete, so it is very much a screening study to
give an indication of whether GTLs is a possibility for an
anchor tenant either in Fairbanks or Cook Inlet. He said the
location factor of 1.25 is based on historical analysis and is
the adjustment for a facility in, say, Nigeria or Qatar, versus
Alaska.
MR. KLEPPIN discussed the cost estimates for the three different
scenarios A, B, and C, with B being the base case (slide 8). He
reported that [for case B] the cost to build a 33,000 barrel GTL
facility in the Cook Inlet is roughly $3 billion, which is a
unit cost of $88,000 per barrel day of production. [The unit
cost] for actual constructed GTL facilities ranges from $30,000
per barrel day to $175,000, so Case B would be in the middle of
this very big range.
2:42:34 PM
CO-CHAIR SEATON asked whether that range is based on economies
of scale; for example, are the big plants cheaper or is it a
function of where the plant was built and the problems that were
faced.
MR. KLEPPIN answered that it is a combination of both. The
largest facility currently in operation is the Pearl facility
built by Shell in Qatar and that facility produces 140,000
barrels a day. Other costs were included, such as drilling for
gas wells, but Shell's total cost started at $5 billion and the
final project ended up being around $24 billion. Another plant
that may be of relevance is one that Chevron built in Nigeria,
which produces a volume similar to Case B of around 34,000
barrels a day. He said he thinks the original cost for the
Chevron facility started at around $1 billion and went to $6
billion. Apparently, an issue for that plant was that it was
built in wetlands so construction costs were quite a bit higher.
CO-CHAIR SEATON surmised that the 40 percent was very
conservative.
MR. KLEPPIN said not necessarily - there is also a 30 percent
contingency. Even allowing for that it could be plus 40 percent
and there are some components that are not included in the
study. He allowed that much more work needs to be done to get
to a firm cost estimate.
2:44:08 PM
MR. KLEPPIN, returning to his presentation, pointed out that the
operating cost for the base case facility is $83,000 per barrel
and the significant portion of that is the cost of the natural
gas. The cost of the gas is a key assumption, a point also made
by the previous speaker, as well as the cost of the sales
products.
CO-CHAIR SEATON inquired about the cost used to arrive at
$83,000 per barrel.
MR. KLEPPIN replied that the number used for Anchorage was $7.61
per million BTUs. He said that was as low a cost that AGDC
could assume for seeing if it could still work. The cost of
$7.61 assumes a North Slope netback of $1 to the producer, so
the shipping tariff would be $6.61.
2:45:44 PM
MR. KLEPPIN next compared a base case scenario for a Port
MacKenzie facility versus Fairbanks (slide 9), pointing out that
the capital cost [for Port MacKenzie] is roughly $3 billion
versus $3.6 billion [for Fairbanks]. However, he continued, the
operating costs for a Fairbanks facility [$773 million annually]
are lower than Port MacKenzie [$925 million annually] due to a
lower assumed tariff.
CO-CHAIR FEIGE said he understands the difference between a
facility at the end of the line and one midstream on the line,
but asked whether there was any consideration of the land on the
Kenai Peninsula where the Agrium plant had been located and
which has the plumbing in place for a large amount of gas.
MR. KLEPPIN responded that the base case was Port MacKenzie
because that location is near the terminus of the base case for
the gas pipeline at Big Lake. It could have been extended to
the Kenai Peninsula but then there would have been additional
costs for moving that gas to the Kenai Peninsula, as well as
potential capital costs, which would have driven up the tariff;
so construction costs would likely not vary much between [Port]
MacKenzie and the Kenai because this is a greenfield facility
which assumes all new infrastructure and buildup, which may not
be the case if existing facilities can be used on the Kenai.
MR. KLEPPIN, continuing his presentation, noted that there is
little difference in the fixed operating costs between Anchorage
and Fairbanks; it is all in the variable costs driven by the
cost of the gas.
2:48:16 PM
MR. KLEPPIN next addressed the assumptions in the economic
analysis (slide 10). The market analysis assumed the product
mix would be diesel and naphtha, he said. Another case looked
at a combination of roughly 40 percent diesel, 40 percent jet,
and 20 percent naphtha. Taking into account shipping costs, the
likely markets would be the U.S. West Coast for the diesel and
Japan for the naphtha. The project life of the plant was
assumed to be 30 years, the debt assumption was 50 percent, and
the equity assumption was 50 percent. The equity rate of return
was assumed to be 12 percent and the debt is the London
Interbank Offered Rate (LIBOR), which is essentially for the
best lenders and which would be less than the equity rate.
CO-CHAIR SEATON, referring to slide 9 showing Fairbanks as being
less in total operating cost because of the price of gas,
recollected that every presentation to the committee so far has
been that the gas tariff into Fairbanks was more expensive than
into Southcentral. He requested an explanation for this
difference.
MR. KLEPPIN answered that those were different cases that
assumed the gas stream was an enriched stream where NGLs were
injected on the slope and then those liquids had to be extracted
before getting to the gas. In the base case scenario here the
assumption is just a non-enriched gas line, so there is not the
expensive straddle plant at Fairbanks and therefore, on a
mileage-based tariff, Fairbanks would have a lower tariff. He
reiterated that this study is trying to get to whether there is
any way GTLs could work economically and trying to give [the
Fairbanks] location an optimistic view versus the extra fee for
a straddle plant.
2:50:44 PM
CO-CHAIR SEATON questioned getting two drastically different
views from the same organization, but offered his understanding
that apparently this calculation is one that would not be a wet
line because that would need a straddle plant.
MR. DUBLER explained that these three studies were conducted
simultaneously and started off a year ago as a dry gas line.
The results of the NGL study showed that maybe an enriched
stream might be more profitable - result in a lower tariff -
because more BTUs could be brought down the line. At that point
AGDC shifted to that and did not go back and re-run all the
assumptions for all three scenarios. So this was based on the
original projected dry gas line and dry gas does result in a
much better outcome for a GTL plant because no additional
processing is required to take the gas and make it available for
a GTL plant.
2:52:00 PM
CO-CHAIR SEATON said AGDC's current best case scenario was for a
wet line, which means that these would have to be changed
significantly because Fairbanks would have a higher operating
cost under AGDC's current proposal where it is charging the
facility or community that wants to use dry gas along the line.
If the line is built as wet gas those facilities and communities
would be charged for removing and then re-injecting the liquids.
Whether that is fair will be addressed at another time, but he
wants everyone to understand this.
MR. DUBLER agreed but said had ADGC re-done these with wet gas
both of these would have looked much worse because both of the
tariffs would have gone up. The reason ADGC did not re-do these
is because the GTL did not look like a viable option anyway, so
re-running it to see just how unviable it was did not seem to
make much sense.
2:53:10 PM
MR. KLEPPIN, in response to Representative Dick, explained that
naphtha can be used to make ethylene or propylene and sometimes
it is used to make gasoline. However, using gas-to-liquids
naphtha to make gasoline would lose a lot of the advantage of a
very clean, pure product, which is stated in the study.
REPRESENTATIVE HERRON asked which method for predicted accuracy
was used by the study, given that there are several methods.
MR. KLEPPIN replied that it is based on AACE methodology, the
Association for the Advancement of Cost [Engineering], which has
definitions on what standards must be met to get to that level
of accuracy.
2:54:37 PM
REPRESENTATIVE HERRON inquired whether the Hatch report analyzed
the market opportunity horizon, for which Mr. van Wijk's answer
was six to seven years.
MR. KLEPPIN responded that Hatch's assumption for the economic
schedule was that the permitting and engineering work would
begin in 2012, the plant would be constructed the latter part of
2019, and it would be fully commissioned and operational in
third quarter 2020.
REPRESENTATIVE HERRON, noting that people like Mr. van Wijk are
always seeking areas of competitive strength, observed that page
115 of the Hatch report states this could be an even better
project if advantage is taken of new carbon efficiencies and new
technologies for GTL. He asked whether this consideration was
rolled into the aforementioned horizon.
MR. KLEPPIN answered that AGDC's guidance to Hatch was to use
proven, currently utilized Fischer-Tropsch technology, so the
study stayed away from new technology. Conversations with Hatch
have indicated, for example, that with new technology the
product mix of 74 percent diesel and 26 percent naphtha could be
upped to maybe as high as 90 percent diesel, but then he is not
sure what to do with the cost estimates.
2:56:41 PM
MR. KLEPPIN, continuing his review of the study's economic
assumptions depicted on slide 10, noted that the key assumptions
included: $80 [per barrel] West Texas Intermediate (WTI)
pricing flat real and 3 percent escalation on that price; a
product price at Port MacKenzie of $7.61 [per MMBtu delivered
natural gas to plant inlet] and at Fairbanks $6.15, with the
tariff and a $1 North Slope netback included in that price; and
power generated and sold on the market garnering a higher price
at Fairbanks [$60 per megawatt hour] than at Port MacKenzie
[$45], with the power generated and sold accounting for 4
percent of the total revenue stream.
2:58:17 PM
MR. KLEPPIN summarized his presentation (slide 11), stating that
the key economic drivers are the price of crude, which tells
what price the product can be sold at; the price of gas; and the
capital investment. Assuming a hurdle rate of 12 percent,
AGDC's base case scenario only gets a 5.7 percent return. To
get to the breakeven point - the 12 percent hurdle - the
[delivered natural gas] at Cook Inlet would have to be $4.40
[per MMBtu]. Or said another way, the breakeven point for gas
delivered to Cook Inlet at $7.61 is a crude oil price of $97
WTI. For Fairbanks, due to the capital costs, the breakeven
price is even lower at $2.19 per MMBtu.
MR. KLEPPIN lastly pointed out that AGDC's intention was not to
select or eliminate any potential anchor tenant process.
Rather, the intent was to figure out what the market might be
for an anchor tenant and who might be the most likely - who will
be the shipper and the final users. Noting that the graph
depicted on slide 12 is from the July [2010] report, he related
that the graph shows that GTLs are the least likely, and LNG is
probably the most likely, for an anchor tenant.
3:00:34 PM
CO-CHAIR SEATON understood Mr. Kleppin to be saying that most
all of the economic driver is the tariff on shipping the gas
through the pipeline. He noted that the tariff could be taken
away by building a GTL plant on the North Slope and using TAPS
as the transmittal line. Diluting a previously pure product or
taking it down the road in trucks is not the issue, he said.
The issue is that if the tariff is taken away it makes a huge
difference in the economics of GTLs for Alaska.
MR. KLEPPIN confirmed that the operating costs would be
significantly reduced because no tariff would be paid on the gas
pipeline. What that would do to the construction costs, capital
costs, or shipping costs with TAPS was not analyzed, he
continued, so he cannot compare the two projects. However, he
agreed that that would be another option that may want to be
studied.
CO-CHAIR SEATON realized that that was beyond AGDC's scope, but
stated he was trying to determine whether the project said that
GTLs anywhere in Alaska will not work or that GTLs shipped on a
pipeline to either Fairbanks or Southcentral does not work.
MR. KLEPPIN agreed that that is a very fair characterization.
3:02:41 PM
REPRESENTATIVE HERRON inquired whether there was ever a
collective epiphany within AGDC about why did "the big guys" or
anyone else not do this before and just do the GTL project.
MR. DUBLER replied that last May AGDC offered a nonbinding
expression of interest (EOI) and was expecting that anybody
having a desire to build a project like a GTL, NGL, or LNG plant
would submit a proposal. While the responses to an EOI are
confidential, he continued, he can say that no one responded
with a GTL proposal.
REPRESENTATIVE HERRON, re-stating his question, asked whether
AGDC ever had a collective conversation about why someone has
not yet done it since it make sense.
MR. DUBLER responded he does not believe so.
CO-CHAIR SEATON clarified that [AGDC's] study has said it does
not make sense to do it in Southcentral or Fairbanks. The study
did not analyze whether it makes economic sense to do it on the
North Slope. Since the largest driver was the tariff for the
transmission of gas, AGDC's study does not preclude that it
would make sense to do it on the North Slope.
3:04:56 PM
REPRESENTATIVE DICK, returning to the Janus Methanol
presentation, related that when the weather is cold the bar oil
for his chainsaw gets pretty thick, so he mixes gasoline into
the bar oil to thin it out. Regarding the challenge of heavy
oil on the North Slope, he said he cannot stop thinking that
gas-to-liquids might enhance the process of extracting heavy
oil.
CO-CHAIR SEATON pointed out that GTL may have lots of waxes and
paraffins, which may be a poor characteristic for injecting into
TAPS. Noting that he has been a supporter of GTL on the North
Slope, he pointed out that Fischer-Tropsch has a number of other
products that could give problems depending upon where the
process is done, so he does not want it glossed over that
everything could be mixed.
MR. KLEPPIN agreed this may have been glossed over a bit. He
explained that coming out of the Fischer-Tropsch process there
is the upgrading, which essentially has paraffinic compounds,
and these are fractured or hydro-treated to make the diesel,
jet, and naphtha.
3:07:31 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:07 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 01-18-2011 ltr to Rep Seaton re GTL (2).pdf |
HRES 1/25/2012 1:00:00 PM |
|
| 1-8-10 ltr to Rep Seaton re GTL.pdf |
HRES 1/25/2012 1:00:00 PM |
|
| 12 01 25 HRES on GTL overview FINAL.pdf |
HRES 1/25/2012 1:00:00 PM |
|
| 2012-01-20 House Nat Res by DKleppin final.pptx |
HRES 1/25/2012 1:00:00 PM |
|
| Hatch-GTL-Report-Final-June-06-2011.pdf |
HRES 1/25/2012 1:00:00 PM |
|
| PP Presentation Alaska 20120125 (0).pptx |
HRES 1/25/2012 1:00:00 PM |
|
| Rep Seaton GTL Letter to Commissioner Galvin September 22 2009.pdf |
HRES 1/25/2012 1:00:00 PM |