Legislature(2009 - 2010)BUTROVICH 205
03/22/2010 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB228 | |
| SB287 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 287 | TELECONFERENCED | |
| += | SB 294 | TELECONFERENCED | |
| *+ | SR 10 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| = | SB 228 | ||
SB 228-TAX INCENTIVES FOR GAS-TO-LIQUID
3:40:15 PM
CO-CHAIR MCGUIRE announced SB 228 to be up for consideration.
[CSSB 228(RES), 26-LS1324\P, was before the committee.] She said
in preparation of SB 228 they would hear first from Paul Metz.
3:40:22 PM
PAUL METZ, Director, Mineral Industry Research Laboratory,
University of Alaska, Fairbanks, Alaska, did a presentation
called "The Key to Energy Security: Converting Coal to Gas to
Synthetic Fuels to More Petroleum Production." He said this
presentation was not on behalf of the Laboratory but it was
approved by the University. He said he would look at Alaska's
energy challenges, look at the alternatives for developing an
energy plan, discuss the subject of coal to synthetic gas and
converting it to liquid fuels, discuss carbon dioxide enhanced
oil recovery, and present some alternatives for financing these
megaprojects, discuss how to get these products of these
resources to markets via the Alaska Railroad, and summarize the
synergistic effects of these major energy projects.
He began with Alaska's Energy Challenges. Alaska has decreasing
oil production and revenues from the North Slope, decreasing
natural gas production in Cook Inlet, and increasing federal and
state regulations that increase incentives to find and develop
more natural oil, natural gas and coal, in particular, the
increasing federal and state regulations that increase the cost
of petroleum refining and will increase with climate change and
carbon capture and storage, alternate and lower cost sources of
supply of natural gas to the contiguous states that place the
large diameter natural gas pipeline in question, and highly
fluctuating energy cost as a function of the world-wide demand
for petroleum - natural gas being priced as a function of the
market price of petroleum. Finally, the combined and negative
effects of these costs and limited fuel supplies on the air
cargo industry in Anchorage, in particular, and the
transportation and tourist industries in general.
3:43:21 PM
MR. METZ said the key to developing a plan that provides cost
effective and stable energy supplies and energy security for
Alaska and the nation includes a public private partnership
between the state, the federal government and the various
industries that facilitate the full utilization of our coal
natural gas and petroleum resources. Our fossil fuels are and
will remain major sources of energy for the foreseeable future.
3:43:57 PM
The resources are: natural gas - about 26 tcf of proven reserves
on Kuparek and Prudhoe Bay fields, about 9 tcf at Pt. Thomson;
for a total of 35 tcf that will provide about 23 years of supply
for a 4.5 bcf/day natural gas pipeline. Most gas pipelines are
designed for a 30-year life or longer. So, additional resources
would have to be found on the North Slope to support even a 4.5
bcf/day pipeline.
CO-CHAIR MCGUIRE asked if the state has data on gas hydrates
potential.
MR. METZ replied no; these are reserve estimates. Resources such
as gas hydrates, coal bed methane, synthetic gas from coal are
potentially useful to humans, but aren't measured quantities
under current economic conditions. The gross value of the
measured reserves at various prices of natural gas range from
$200 billion $500 billion.
3:45:33 PM
By comparison, he said, about 67 billion barrels (BB) of oil
were in place on the North Slope when the TAPS pipeline came
into production; an expected total recovery without enhancement
is about 22 BB. That leaves about 45 BB of oil in place when and
if the pipeline is shut down before enhanced oil recovery is put
into action. The gross value of recovering 8 BB of additional
oil through enhanced oil recovery methods is $1.1 trillion, much
larger values than the proven reserves of natural gas on the
North Slope.
3:46:52 PM
MR. METZ said by comparison, the coal resources that are widely
distributed in Alaska, are immense. The USGS estimates that the
western end of Arctic Slope of the Brooks Range the North Slope
contains an estimated 5.5 trillion tons of high unit value coal.
The magnitude of this resource is if we could convert our
domestic requirements for electricity into 100 percent-coal,
Alaska could generate the electrical demand for the United
States for about 2500 years. If we converted all of our liquid
fuel demand (23-million barrel/day consumption) of oil to coal
as well as generated all of our electricity with coal, the
western Arctic would still have enough coal to supply the U.S.
for about 1000 years. In addition to the western Arctic another
estimated 3 trillion tons of deep coal is in the Cook Inlet
Basin and smaller coal resources in the Upper Susitna Valley and
the north flank of the Alaska Range. The values at various
prices per ton of coal dwarf the estimated resource values for
the oil and gas measured in thousands of trillions of dollars.
Mr. Metz said the gas reserves on the North Slope contain about
1617
3X10 btus, oil in place contains 4X10 btus, and the coal
20
resources have 2X10 btus, ten-thousand times the energy
contained in natural gas.
3:49:12 PM
He posed the question of whether these energy sources are
competing or have synergisms in looking at some aspects of the
instate gasline - a coal-to-liquids plant, for instance (the
Fairbanks example has some conceptual engineering design and
numbers for a project that was advocated by the Fairbanks
Economic Development Corporation) and enhanced oil recovery
through the use of the CO2 that would be produced from a
synthetic fuels plant.
3:50:22 PM
He stated that the Cook Inlet Basin has supplied Anchorage with
electrical generation and domestic and commercial heating for
three-plus decades. Shortages are expected by 2015 during peak
demand periods. The Department of Energy estimates it would take
capital investment of $5-6 billion to replace the original 3 tcf
in Cook Inlet. But the difficulty with the whole natural gas
market in the state is the low quantities that both Fairbanks
and Anchorage would actually require and the fact that bringing
it from the North Slope is a large capital investment.
3:51:19 PM
For the sake of having numbers, Mr. Metz said, the Enstar bullet
line (bringing gas to Fairbanks, Anchorage and potentially to
export from is estimated to cost $3.8 billion for 24 in. 0.5
bcf/d from either the Gubik field (dry gas) on the North flank
of the Brooks Range or alternatively from the Prudhoe Bay field
that has wet gas that would require investing in a conditioning
plant. Anadarko's estimated it would cost $1 billion for
delineating sufficient resources in the Gubik field. Taking the
large diameter gas line and scaling a $6-plus billion
conditioning plant to a size to handle 0.5/day would cost about
$1 billion. Because of the limited market and the high capital
cost he thought it would cost significantly more than $3.8
billion to build. There needs to be a large domestic or
international industrial user of the excess gas from 0.5 bcf/d
line. A coal-to-liquids plant as envisioned by Fedco could
actually use all of the gas in an instate gas line if the
project were up-scaled.
CO-CHAIR WIELECHOWSKI asked how much it would cost to expand
that to 1 full bcf/d and if it is better to build a 500 mcf now
and expand it later or is it better to build bigger now.
MR. METZ replied that there is insufficient market today for the
0.5 bcf/d and to build a larger plant than that and have it idle
for a considerable period of time is not a good return. He said
the Fedco project looked at a 40,000 barrel/day plant with a
capital cost of $4.6 billion. That has been revised down to $3.2
billion. The products in that plant would be Jet A and diesel at
a production cost of about $2.60/gallon. That plant at that
scale was estimated to return about 12 percent on the capital,
but in 2008 prices of diesel went up to $5/gallon.
CO-CHAIR WIELECHOWSKI asked where they projected building this
plant.
MR. METZ replied somewhere in the Interior. This is a
preliminary design only. The money that was provided initially
for the Air Force was to site the plant at Eielson Air Force
Base, but for a number of reasons that won't happen.
3:56:38 PM
SENATOR WAGONER asked what they would do with the CO2 emissions.
MR. METZ replied that he is proposing to use that for enhanced
oil recovery on the North Slope.
SENATOR WAGONER said for that to happen the plant would have to
be closer to the North Slope.
3:57:12 PM
MR. METZ replied no; a pipeline would be built to the North
Slope. He said for every ton of coal you burn you get about 3.5
tons of CO2 and that could be considered a bad thing, but it is
good in terms of enhanced oil recovery. In 2005 the Department
of Energy did an analysis of enhanced oil recovery potential on
the North Slope as well as the potential in the Gulf of Mexico
and found about 8000 kilometers of CO2 pipeline to the
Mississippi Valley bring CO2 to the offshore oil fields in the
Gulf. Some of the fields in the Gulf of Mexico as well as the
North Slope are amenable to miscible CO2 injection and enhanced
oil recovery. Cook Inlet is not, but the resource on the North
Slope at 45 billion barrels is very large.
CO-CHAIR MCGUIRE asked the difference in recovery rates between
CO2 and gas as a mechanism for lifting up the oil.
MR. METZ replied injecting CO2 or natural gas changes the
physical and chemical characters of the oil. The CO2 decreases
the viscosity, increases the volume of the fluid and adds
pressure to the reservoir before it becomes miscible. Methane
injection reduces viscosity, too, but the CO2 enhancement is
much more effective.
3:59:51 PM
CO-CHAIR MCGUIRE asked why injecting CO2 as an enhanced oil
recovery technique is not possible in Cook Inlet.
MR. METZ responded that oil is not amenable to miscible
injection of CO2. The CO2 will not form a single phase in the
oil when it's injected at high pressures, therefore you don't
get the reduction in viscosity or the increases in volume that
you do on the North Slope or in the Gulf of Mexico.
4:01:10 PM
(Slide 9) He said the operators on the North Slope have
experimented with this, but the problem is it has insufficient
CO2 at about 10 percent. That is part of the reason for the
conditioning plant - to remove the water as well as the CO2 from
the natural gas. But even if they were producing at 4.5 bcf/d
they would still have 1/10 of the CO2 that would be necessary
for enhanced oil recovery. That is where the coal-to-liquids
plant comes in. Scaling the 40,000 barrel/day plant up to what
the oil industry feels is a minimum plant size for synthetic
fuels of 200 barrels/day would produce about 1 tcf/year of CO2.
That is what the DOE estimated would be the requirements for
recovery of 8-12 BB of oil. The DOE estimated that in addition
to the large volume of CO2 you would had to have it at a
reasonable price, and it was estimated at 5 percent of the
wellhead price of oil. At that time they were looking at
$25/barrel.
4:02:12 PM
He provided an extract of the rates of return (ROR) from the
sale of CO2 from a 200,000 barrel/d plant at 5 percent of the
wellhead price of oil at various prices. Adding this to the 1/8
royalty resulted in very large numbers. Nothing else would
generate this kind of income and return for the state.
4:03:12 PM
CO-CHAIR WIELECHOWSKI asked if these figures include the cost of
piping it to North Slope.
MR. METZ replied it is just from the direct sale by the plant
assuming that a prudent North Slope producer would engage in the
capital investment to build a pipeline that could deliver 1
tcf/yr. to the North Slope. He added that CO2 is very
compressible compared to methane and he estimated $2.5-3 billion
for that. The price of CO2 within 5 percent of the wellhead
price would make that investment very attractive to the oil
industry.
4:04:20 PM
Slide 12 showed the financing for a coal-to-liquids plant
anywhere in Alaska. The plant would use about 17 million tons of
coal a year or 10 times what the Usibelli Coal Mine produces
today. Delivering the 1 tcf of CO2 to the North Slope and the
recovery of additional oil at simply a 1/8 royalty at $80/barrel
oil would bring $100 billion to the state in royalties
(equivalent to the amount of taxes in total that the state has
recovered from North Slope oil production since 1977). At 12 BB
that increases to $120 billion. In addition, the state would
receive royalties on the coal that is produced whether it goes
into gasification or into a plant.
MR. METZ said an added synergism for the Susitna hydro project
is adding the ability for it to generate hydrogen and oxygen
from the electrolysis of water rather than using steam to
convert the coal to methane which would greatly reduce the
capital cost of the coal-to-liquids plant. At 200,000
barrels/day, Hatch proposed a coal-to-liquids plant that would
use 2000 mgw (120 mgw more power than Susitna). The beauty of
this alternative is that once the need for CO2 on the North
Slope was achieved oil production would taper off and the coal-
to-liquids plant could be operated with hydrogen and oxygen from
the electrolysis of water. The result would be a zero CO2
emission coal-to-liquids plant, which would then produce liquid
fuels with lower total carbon emissions than refined petroleum.
"So, there is a great synergism between having a low-cost source
of electrical energy and liquids fuels production."
4:07:22 PM
CO-CHAIR WIELECHOWSKI asked if he envisioned mining the coal and
then converting it or doing underground coal gasification.
MR. METZ replied that underground combustion is far more
attractive. It would lower the capital and operating cost of the
coal-to-liquids plant - producing coal gas and then conditioning
that and transporting it to a plant at some location.
CO-CHAIR WIELECHOWSKI asked how much CO2 could be captured with
this process.
MR. METZ replied that they would be looking at 70-80 percent
recoveries, but the existing technologies are expensive and
capital intensive and he didn't know the exact answer. The DOE
is spending a lot of money on research in that area and that
technology is changing very quickly, however.
4:09:32 PM
He summarized that the synergisms between a coal-to-liquids
plant and enhanced oil recovery has the potential of extending
the life of the North Slope oil fields for another 30 years,
replacing Cook Inlet natural gas with North Slope gas to both
Anchorage and Fairbanks, and supplementing the petroleum
production from North Pole with low sulfur synthetic fuels.
Availability of markets outside of Alaska would not be an issue
with respect to an instate gas line.
The price of coal is not tied to the price of petroleum, so it
would have less fluctuation than the price of synthetic Jet A
and diesel as compared to petroleum derived products. There
would be long term stable fuel supplies for the military both in
state and in the Pacific Rim, there would be stable prices for
the air cargo and other transportation industries in Alaska,
which would anchor those industries here.
MR. METZ said that last Friday the Department of Defense
announced that the Defense Energy Supply Center and the Air
Transportation Association of America had signed a cooperative
agreement for a public private partnership to develop synthetic
fuels, which they have been saying for the past year needs to
happen.
4:11:46 PM
CO-CHAIR MCGUIRE said that this presentation pertained to two
bills, SB 228 and SB 287, which incentivize these kinds of
plants through two different methods. The first is SB 228 the
Special Investment tax credit and the other is the amendment to
ACES clarifying that gas used in the state as a fuel or feed
stock in the manufacturing process creating an end product in
the state shall be considered as instate gas at the instate gas
rate. And there is the potential for ARRC bonds to be used as a
part of the financing for a project like this.
Finding no further comments, Co-Chair McGuire closed public
testimony.
CO-CHAIR WIELECHOWSKI stated that the more he learns the more he
thinks a gas-to-liquids plant or a coal-to-liquids plant or
several of them are critical for Alaska's future; they create
anchors for the bullet line and provide the opportunity for
enhanced oil recovery and creating whole new industries. Experts
have estimated that creating one plant could create 650 new full
time jobs, not to mention 10-15,000 construction jobs. It would
help protect our military bases and provide heat sources for
generating 350 mgw power plants. He moved to report CSSB
228(RES), version P, from committee with individual
recommendations and attached fiscal note(s). There were no
objections and it was so ordered.
CO-CHAIR MCGUIRE noted that she talked to a Sassol
representative in Houston who confirmed they had looked at
Alaska for two decades and sadly, the reason they hadn't done
more here is they consider Alaska to have an unattractive
business climate.
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