Legislature(2011 - 2012)Anch LIO Conf Rm
08/15/2011 09:00 AM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation: Alaska Stand Alone Pipeline Project Plan - Alaska Gas Development Corporation. | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
ANCHORAGE, AK
August 15, 2011
9:05 a.m.
MEMBERS PRESENT
Senator Joe Paskvan, Co-Chair
Senator Thomas Wagoner, Co-Chair
Senator Bill Wielechowski, Vice Chair
Senator Bert Stedman
Senator Lesil McGuire
Senator Hollis French
Senator Gary Stevens
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Senator Fred Dyson
Representative Paul Seaton
Representative Peggy Wilson
Representative Scott Kawasaki
Representative Kurt Olson
Representative Chris Tuck
Representative David Guttenberg - teleconference
COMMITTEE CALENDAR
Presentation: Alaska Stand Alone Gas Pipeline Project Plan by
Dan Fauske, Alaska Gas Development Corporation
- HEARD
Presentation: Gasline Project: Issues Update by Dan Sullivan,
Department of Natural Resources (DNR)
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
DANIEL FAUSKE, President
Alaska Gasline Development Corporation (AGDC)
Anchorage, AK
POSITION STATEMENT: Presented on the Alaska Stand Alone Gas
Pipeline (ASAP) project.
DAN HAUGEN, Project Manager
Alaska Stand Alone Gas Pipeline (ASAP)
Anchorage, AK
POSITION STATEMENT: Presented on the ASAP project.
LIEZA WILCOX, Commercial Analyst
Alaska Gasline Development Corporation (AGDC)
Anchorage, AK
POSITION STATEMENT: Provided tariff explanations on the ASAP
project.
TINA GROVIER, Attorney
Birch Horton Bittner and Cherot
Representing Alaska Gasline Development Corporation (AGDC)
Anchorage, AK
POSITION STATEMENT: Provided legal comments on the ASAP project.
JOE DUBLER, Vice President and Chief Financial Officer
Alaska Gasline Development Corporation (AGDC)
Anchorage, AK
POSITION STATEMENT: Presented on the ASAP project.
DAN SULLIVAN, Commissioner
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Presented an update on the focus of DNR's
TAPS goals.
JOHN BALASH, Deputy Commissioner
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Presented information about DNR's current
work on TAPS.
KURT GIBSON, Director
Gas Pipeline Office
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Commented on gas/oil reserves in Alaska.
ACTION NARRATIVE
9:05:12 AM
CO-CHAIR JOE PASKVAN called the Senate Resources Standing
Committee meeting to order at 9:05 a.m. Present at the call to
order were Senators McGuire, Wielechowski, Stevens, French,
Stedman, Co-chair Wagoner and Co-chair Paskvan.
CO-CHAIR PASKVAN welcomed everyone watching. He reminded
everyone about legislation passed that required the Alaska
Gasline Development Corporation (AGDC) to prepare and present a
report by July 1, 2011 on the ASAP project. The plan was
completed in July and he said that the next three days would be
focusing on various aspects of that report.
^Presentation: Alaska Stand Alone Pipeline Project Plan - Alaska
Gas Development Corporation.
Presentation: Alaska Stand Alone Pipeline Project Plan
CO-CHAIR PASKVAN invited Mr. Fauske to give his presentation on
the Alaska Stand Alone Pipeline (ASAP) Project Plan.
9:08:24 AM
DANIEL FAUSKE, President, Alaska Gasline Development Corporation
(AGDC) and CEO of Alaska Housing Finance Corporation, said HB
369 established the development of the AGDC and required an in-
state natural gas pipeline report delivered by the July 1, 2011.
That deadline was met and the report was rolled out to the
legislature on July 5.
The plan included the project design, financing, construction,
commercial feasibility, and a project schedule. The original
goal was to have an operational line by December 31, 2015, but
the recommendation was to extend that out because AGDC wasn't
able to confidentially deliver a plan that met that timeframe.
The plan was amended to have first gas by 2018 and full
transmission by 2019.
The stand-alone gas pipeline project to transport gas from the
North Slope to Fairbanks and tidewater works parallel to the
large diameter project, The Alaska Gasline Inducement Act
(AGIA), and keeps all options open. AGDC signed agreements to
share information with TransCanada and its partners to make sure
no one was double-spending state money by doing the same
evaluations and there has been significant cooperation so far.
9:10:01 AM
SENATOR MCGUIRE joined the committee.
MR. FAUSKE said that to reduce project risk by acquiring major
permits, a draft environmental impact statement (EIS) is needed
and that would be released sometime this month or, at the
latest, in December. He anticipated that a final EIS would be
completed in the first quarter of 2012, which would be
significant. The project would require 737 miles of pipe and
would require an estimated 2200 permits. And if AGIA shows some
success in open season, the work AGDC is doing now would
represent the spur line from Fairbanks going south. He said that
AGDC is determining the cost of the transport, optimizing
economic feasibility, and preparing a permit and project data
package to transfer to a builder/owner/operator.
9:12:14 AM
MR. FAUSKE said the bills introduced relating to the ASAP are:
HB 189, which exempts AGDC from certain provisions of public
records statutes and addresses in-state team participation and
HB 203 that created a dedicated fund for the ASAP project, and
HB 215 expedited a review of the state Right Of Way (ROW) lease,
exempting ASAP from common-carrier requirements.
MR. FAUSKE said he signed the first state right-of-way (ROW)
lease three weeks ago in which DNR signed over 430 miles of ROW
to AGDC.
AGDC legislative appropriations include a lapsed fund of $1.126
million from the operating budget that got moved over to the
final appropriation of $28.2 million in capital funding; $200
million was also set aside for the in-state gas pipeline, but
not to AGDC.
9:15:01 AM
DAN HAUGEN, Project Manager, Alaska Stand Alone Gas Pipeline,
stated that the In-State Gasline Coordinator position has been
filled by Jeff Jones, who was in the audience. ANGDA was
originally part of ASAP, but involved themselves as a shipper
and therefore had to step away from being active on this project
since they are in the gas transmission business as a pipeline
organization. He said that Department of Transportation and
Public Facilities (DOTPF) is represented by the commissioner and
the Alaskan Railroad Corporation (ARRC) is represented by Linda
Leary, chair of that board.
MR. HAUGEN acknowledged the AGDC staff in the room including
Vice President Joe Dubler and Commercial Analyst Lieza Wilcox.
He also thanked several contractors including Michael Baker and
Birch, Horton, Bittner & Cherot. On the regulatory side he
mentioned ASRC Energy Services (AES), Cardno ENTRIX and Stoel
Rives LLC. On the commercial side he thanked financial advisor
Citigroup/Ramirez and Black & Veatch for their work on tariff
modeling.
9:19:24 AM
MR. HAUGEN said it was important to talk about the different
stages of independent project analysis (IPA) that breaks the
project into phases, which is an important step in not getting
ahead of oneself. The ASAP project is often spoken of as the
minor project, but it is a huge project. It is going to cost
$7.5 billion and will probably be the single largest project the
state will ever attempt. Inherent risks are associated with it
requiring a methodical stage gate approach.
The idea is to progress on what is called a "trumpet curve." It
started a year ago with a conceptual design, or FEL 1, and the
past year was spent in a business development phase. They now
have a "class 4 estimate," but are still plus or minus 30
percent on capital cost estimate. But with enough data in their
July 1 report they have moved to FEL 2. The primary activity is
completing a successful open season by the end of 2013.
9:21:44 AM
CO-CHAIR WAGONER asked if the commissioner from DOTPF was
sitting on the joint in-state development team or if he was
assigning someone to that team.
MR. FAUSKE said he had been joining the meetings.
CO-CHAIR PASKVAN asked if economic studies were available to the
legislature.
MR. HAUGEN said yes and that all reports were also available on
the AGDC website at www.gasline.us.com.
MR. HAUGEN stated that it is important to realize that FEL 2
would be driven by the considerable commercial and engineering
work that needs to be done. FEL 3 would be the project sanction
gate at which point a recommendation would be made to go forward
or not. At that point the estimate would be for a plus or minus
10 percent and there would be a reasonable certainty that the
execution phase of the project would be done on time. The whole
idea is that every gate should present the opportunity to look
at results, and at the conclusion of the open season the market
should speak to the project.
SENATOR FRENCH asked how much state money would be spent at each
gate.
MR. HAUGEN replied that information was coming up in the
presentation.
SENATOR DYSON asked at which phase there would be a firm
commitment.
MR. HAUGEN replied that would be at the end of FEL 2, at the
conclusion of the open season.
SENATOR DYSON asked what the required committed volume would be
at that point.
MR. HAUGEN answered 500 bcf - the way the program was currently
structured and the work done to date amounts to roughly $30
million. He estimated that it would cost around $240 million to
reach a successful open season and another $130 million for the
design, for a total of $400 million.
9:26:26 AM
SENATOR DYSON asked if those were fixed prices.
MR. HAUGEN answered that it would depend on how the contractual
arrangements are worked out.
SENATOR DYSON asked if the timeframe had any built-in
flexibility to accelerate.
MR. HAUGEN answered that there hadn't been a need to do that
thus far.
MR. FAUSKE pointed out that this amount of money is not
dissimilar to what is being spent on AGIA and it is money the
state has to spend in order to determine if there is a viable
project. No company is going to spend that money on their own.
SENATOR WIELOCHOWSKI joined the meeting.
CO-CHAIR WAGONER asked if ASAP was determined to be a feasible
project how much of the state's investment would be recoupable
or could be put towards lowering tariffs.
9:29:53 AM
LIEZA WILCOX, Commercial Analyst for AGDC, responded that the
tariff model used the assumption that the total state spending
would be $320 million and that would be the upfront
contribution, not recovered in the tariff. That doesn't mean the
money wouldn't be recoverable, but the tariff would then have to
increase.
REPRESENTATIVE SEATON pointed out that the open season for this
project would end in 2013 and at the same time the state is
negotiating precedent agreements and asked if those would be
finalized by the 2013 date.
MR. HAUGEN answered that open season could begin at the start of
2013 and hopefully be completed in early fall. That obviously
assumes things go well. This project could end up in the same
situation AGIA is, because the shippers and customers would have
to make commercial judgments.
MR. HAUGEN said at the point the precedent agreements are
finaled is when the design would be frozen; there would be firm
transportation commitments and the final project definition
phase would begin and be sanctioned fully by the end of 2014.
With that schedule holding, first gas would be in 2018.
REPRESENTATIVE SEATON asked if fiscal terms or tax rates would
be finalized by the end of 2013.
MR. HAUGEN replied that those requirements would be part of any
transportation commitment.
CO-CHAIR PASKVAN said he knew that the reason the state was
looking into this is because no private developer would take it
on. He asked if it would be possible for the state to spend this
money now, but be able to hand it over to a private developer if
one decided it was economic. He wondered if they could they
exceed the .5 bcf AGIA limitation as a private developer.
MR. FAUSKE responded that the .5 bcf is in a state contract, so
the only private developer could exceed it would be by going
below the 68th parallel, like a development in the Nenana Basin
or Cook Inlet.
9:34:56 AM
CO-CHAIR PASKVAN asked if a private developer did this project
from start to finish would they be bound by the .5 bcf. He said
the ultimate question is whether the state can transfer the data
acquired throughout the investment to a private developer and
then not be limited to the .5 bcf because of AGIA.
9:36:05 AM
MR. HAUGEN replied that anything is negotiable with owner
operators. He said he could only answer the legalities with the
.5 bcf in respect to a private developer. The property that's
being developed is state property, so the commercial data is the
state's property. He said if the state brings the builder
operator on, which is another big component of FEL 2, it would
be possible to get participation during commercial negotiations.
MR. FAUSKE said that when this project was initially started,
teams went out and talked with builders, owners and operators.
The response was that the project hadn't progressed far enough,
but there was interest. The initial concern was that there might
only be interest in ownership, but several firms expressed
interest in builder and operator roles. There were also firms
that wanted to be an owner. Mr. Fauske said that as the project
continues and is viewed in a positive light, the state should be
prepared to accept all kinds of proposals.
CO-CHAIR PASKVAN said facts develop over time. On a concept like
this the question is if the state can advance from a 24-inch
line to a 30 or 34-inch line if a private developer decides a
1.5 bcf line is economical and if the state could transfer its
$275 million worth of investment to it. He also wanted to know
if the state would be subject to the .5 bcf issue if a private
developer advanced the project.
MR. HAUGEN answered that in theory that could be done if a
private developer really did want to take it over and make it a
completely private project.
MR. FAUSKE interjected that the state owns the information and
the legislature and governor can decide what to do with it. The
job was to come back with a plan to get gas down from Prudhoe
through Fairbank to South-central and execute it. After FEL 2
and into FEL 3, the state should encourage private sector
proposals.
9:40:20 AM
CO-CHAIR WAGONER asked at what point the state would be held
liable during a discussion with a private investor.
MR. FAUSKE responded that .5 bcf hasn't been exceeded anywhere
in the plan.
CO-CHAIR WAGONER wanted clarification saying that they were just
discussing a third party coming in and expanding the line
knowing that would exceed limits.
MR. FAUSKE replied that would happen during the FEL 2 open
season when the state would learn the desire of shippers and
producers. Up to that point, the project wouldn't have exceeded
or solicited that amount.
9:42:55 AM
TINA GROVIER, Counsel with Birch, Horton, Bittner and Cherot for
AGDC, said that AGDC had not considered this before because it
always stayed under the .5 bcf cap. Language that would trigger
it reads, "If before commencement of commercial operations, the
state extends to another person preferential royalty or tax
treatment or grants of state money for the purpose of
facilitating the construction of a competing natural gas
pipeline project in the state". The question would be if the
$400 million was considered facilitating the project and she
believed that it would.
9:43:46 AM
MR. HAUGEN added that what was talked about with the builder
owner operators (BOO) was a major activity of the FEL 2 process.
He thought it would be possible that in doing a duel approach,
both the engineering work required for the facilities and the
permitting activities would get proposals from private
enterprises and he wanted the state to entertain those concepts.
CO-CHAIR PASKVAN said it seems that .5 bcf is a material
limitation that is one of the premises this report is based
upon. But when you look at the volumes that are subject to
export, he asked if that material limitation, because it's so
small, impedes the ability to enter into export agreements
compared to what is going on in Japan.
MR. FAUSKE replied that AGDC held a non-binding expression of
interest meeting with industry to determine if there was any
interest above the 200 - 240 mmcf/day that would include
Fairbanks and Anchorage. Interest was expressed at 500 mmcf/day.
He reminded everyone that this process started after concerns
were raised about whether the big line was going to happen or
not. At that time, Mayor Sullivan was holding brown out
practices and when gas hit $5 gallon it caused emergency
meetings in Fairbanks. Enstar and experts in Cook Inlet had also
announced that Cook Inlet could potentially run out of gas by
2018. That is when ASAP became topical.
He reminded them that the intent of the language in the bill was
always to ensure a pipeline option that explored and analyzed
the availability of gas for 500,000 residents of the 700,000 in
the state; attracting an anchor tenant would just be a bonus.
Another entity is dealing with the commercial aspects of 4.5
bcf/day, far bigger than they are.
ASAP was asked at one point why it wasn't going to Valdez and
Mr. Fauske said his response was, "Why?" They have a .5 bcf
limitation factor. AGIA had 1 bcf - 3.5 bcf open season
inquiries as to exporting gas out of Valdez.
MR. FAUSKE said ASAP has actively sought a commercial enterprise
and was pleased with the response. One of the issues they
relayed was the importance of Fairbanks in this whole process;
as you get into the numbers, the 60 mmcf/day that Fairbanks
represents is absolutely essential to this project.
9:50:00 AM
MR. FAUSKE said in the beginning he actually believed the state
would be writing a check for $3-$4 billion to make this work for
two reasons: there is no huge anchor tenant and there isn't
enough people. This proposal is a 737-mile pipeline with a
committed tariff of $9.63 at a 70/30 debt/equity ratio. If you
go to 100 percent debt, that price drops another dollar to $1.20
and the project undercuts what it is currently paid, $8.85, for
that same equivalent amount of gas. Imported LNG starts hitting
in at $14.00 to $16.00 mmcf and inflating those numbers pushes
it up to $21.00 for the same 1 mmcf.
CO-CHAIR PASKVAN said most of the legislators present were at a
meeting soon after the Japanese earthquake when representatives
from Mitsubishi approached the state with the potential of
purchasing of 1 bcf/day for 20 years with a guaranteed floor.
That is an incredible anchor tenant and a potential sale of that
magnitude would buy down the unit costs for Alaskan consumers.
He asked if that was being looked at by other entities on the
larger diameter line.
MR. HAUGEN replied that ASAP could get expressions of interest
that would be beyond .5 bcf during the FEL 2 phase, and also
decisions come to them via whether shippers really want to
entertain liquids transport. All those things would surface
during the open season, which would then result in an evaluation
process, which would determine whether the open season was
successful or not.
SENATOR MCGUIRE said she assumed that Birch, Horton, Bittner &
Cherot were working with the Department of Law (DOL) on the 68th
parallel issue, the .5 bcf limit, and exportation. Alaska will
be pushing the limits with this project, which is good for
consumers, but all legal angles need to be covered.
REPRESENTATIVE SEATON asked where the difference comes from
between the $400 million and the $320 million that won't go into
the tariff.
MR. HAUGEN responded that there were a lot of ways to look at
the numbers; the project could take that cost on and roll into
the rate base. Or they could get contributions in that phase by
the builder/owner/operator. The tariff number was done earlier
to show what the impact would be on the amount of money that
they would put into the tariff rate, which would be covered at a
later time.
9:54:45 AM
MR. HAUGEN talked about how important it would be to select a
builder/owner/operator that would really be the one to make this
project work and said Alaska would be depending on that
"partner." The builder/owner/operator would have to be fully
able to do the design and construction. You would expect to see
major players coming to the party, but the state has to do its
work of choosing the right one. He said they would spend
considerable time doing that during the FEL 2 process.
They can start negotiations with foundation shippers, but they
have to be careful of the open season requirements that are part
of what Federal Energy Regulatory Commission (FERC) and
Regulatory Commission of Alaska (RCA) are about. That will allow
them to determine sooner rather than later some of the true
interest on behalf of the shippers. Permitting efforts will
continue during the open season; the lion's share of the money
will be spent on the facilities side, in the class 3 estimate
that is a normal requirement shipper's look at.
CO-CHAIR WAGONER asked if there had been any discussions with
FERC up to this point.
MR. HAUGEN answered there had been preliminary discussions and
letters exchanged with the Corps of Engineers. At this point,
the pipeline portion of the project would be conducted as an RCA
regulated in-state gas pipeline. Export facilities would fall
under FERC jurisdiction.
SENATOR STEDMAN said he wanted copies of the Corps of Engineers'
letters.
SENATOR DYSON said North Slope producers will be reluctant to
sell the gas necessary for driving oil through reservoirs and
asked when the state will be able to get assurances from them
that they will be willing to sell gas.
MR. HAUGEN responded the moment of truth would be open season.
SENATOR DYSON asked if it wouldn't happen under step two.
10:00:22 AM
MS. WILCOX responded that the completion of a binding open
season would happen after the FEL 2 phase.
SENATOR DYSON said his question was at what point the state
would get some assurances that gas would be commercialized
without hurting oil interests.
MR. FAUSKE replied that currently North Slope gas is being used
for Enstar recovery. The Alaska Oil and Gas Conservation
Commission (AOGCC) said an off-take of 500 mmcf would be
acceptable in 2018 and ASAP would be well below the threshold
that would cause an interruption.
SENATOR DYSON said that answered his question, but it varied
from other information he had heard.
10:02:24 AM
MR. HAUGEN said that compared to the small support staff used in
the FEL 1 phase there would be significantly more activities
during the FEL 2 phase. He acknowledged that HB 369 stated that
the project would be up and running by 2015, but he didn't
necessarily recommended that and thought time needed to be spent
during FEL 2 and 3 before going to project sanction. He
recommended mechanical completion by 2018 with first gas by
2019.
MS. WILCOX stated that the market is what a gas line project
needs and the Cook Inlet supply forecast will determine the
timing for this project.
CO-CHAIR PASKVAN asked what the residential and commercial
demand was for Southcentral.
MS. WILCOX replied 200 - 240 mmcf/day.
SENATOR FRENCH asked if the model assumed that Cook Inlet gas
would be essentially gone by the time this line started
delivering.
10:07:49 AM
MS. WILCOX said the forecast relied on the DNR study which
excluded exploration projects and some of the riskier resources.
AGDC took 50 percent of that volume. Using that information,
production starts declining around 2016. There was no assumption
that it would be zero around the ramp up period and that was
included in the tariff numbers.
SENATOR FRENCH asked if the model assumes Cook Inlet gas would
still be going into the local distribution network when the ASAP
pipeline was done.
MS. WILCOX answered yes.
CO-CHAIR WAGONER asked what the average well produces.
MS. WILCOX replied that DNR would be in a better position to
answer that but about 8 tcf has been produced to date, but she
couldn't answer on an individual well.
REPRESENTATIVE P. WILSON asked if a big discovery in Cook Inlet
would change everything with this project.
MS. WILCOX replied if a significant discovery was made that
could be brought on line at competitive prices, it would
possibly change the picture for a period of time.
10:10:56 AM
JOE DUBLER, Vice President and Chief Financial Officer at AGDC,
said the largest impact would reduce the amount of LNG that
Enstar would have to import during the construction phase. A
large discovery in Cook Inlet would allow them to put off
importing LNG's and not incur those expenses. To give everyone
an idea of size, the large discovery of 35 bcf a month ago is
about 4 months of residential use with no exports. So it would
have to be a very large discovery - in the trillions.
CO-CHAIR WAGONER asked if that discovery was just one well. He
thought they were going to drill 2-7 more wells in the next few
years.
10:12:05 AM
SENATOR WIELECHOWSKI asked if this report was done before the
latest United States Geological Survey (USGS) estimates of 19
tcf of gas in Cook Inlet.
MS. WILCOX replied yes.
SENATOR WIELECHOWSKI asked if the model had been rerun with that
information.
MS. WILCOX replied that the 19 tcf would relate to the
exploration wedge that is not on this chart, and she didn't
think DNR had revised their estimates after they published the
study.
SENATOR WIELECHOWSKI clarified that the estimated total amount
of gas they estimate will be used in Cook Inlet at that point
will be around 250 mmcf.
MS. WILCOX replied yes.
SENATOR WIELECHOWSKI asked if the estimate for Cook Inlet in
2019 was still 100 mmcf, leaving 150 mmcf to sustain current
levels.
10:14:15 AM
MS. WILCOX asked them to go to the "Demand Slide" and wound up
the "Supply Slide" saying 240 mmcf current demands are the top
green wedges. You can see a line that represents the Cook Inlet
production that takes away from the demand available for this
pipeline. The bottom wedge is Fairbanks, which is critical for
demand assumptions of this pipeline (this assumption numbers
came from the Northern Economics study). The industrial anchors
in the "Estimate of Demands" are the existing LNG exports and an
industrial mining project; it's not a specific one. Northern
Economics did an analysis of the mining projects in development
in the state at the time and made the assumption that at least
one of them or a combination of them would need about 30
mmcf/day of gas. The yellow wedge is the NGLs that are primarily
exported and the fuel gas volume that is required for the
pipeline. That's is how the 500 mmcf builds up. In order to get
there, the industrial anchors are critical. There is an
assumption that Cook Inlet will continue to produce. So, the
total demand for the state will exceed the capacity of the line.
SENATOR WIELECHOWSKI remarked that some experts have said that
it will be a long shot for the state to market NGLs in the world
market on a price basis and he asked if she had different
information.
10:16:27 AM
MS. WILCOX replied that the economic feasibility study that R.W.
Beck preformed for them came up with upstream netbacks of
somewhere between $1.50 and $2.00, which is below the LNG
netbacks. So, it was a more marginal project than the LNG. So,
at this point, further work is needed.
MR. DUBLER reiterated that the answer to that question would
come at the end of the open season. NGLs were included because
they assumed they would be shipping enriched gas, because it
helps the tariffs out a lot if you can ship the enriched gas
down. If that is not the case, it would become a dry gas line
and the project would need to be modified. Basically, the market
will determine what comes down the line, not anybody else.
10:17:30 AM
SENATOR WIELECHOWSKI asked how Alaska can compete in the world
market with the tariff when the Nikiski Plant in Cook Inlet is
closing down because it can't.
MS. WILCOX said she believes the stated reasons for the LNG
closure were a combination of the small volume they were able to
offer at the time, below 240 mmcf - because one of the trains
had been shut down thus making unit costs go up for that
production - and the availability of gas in Cook Inlet at a low
enough price. The logic is the availability of gas that can
deliver a tariff that is low enough to either build a new plant
or refurbish an existing plant would be a better opportunity
than what is available with Cook Inlet gas only.
MR. FAUSKE reminded everyone that during the expression of
interest phase of this project interest was stated in the excess
gas above what is currently needed for residential and
commercial.
10:20:06 AM
SENATOR DYSON said he had seen figures about the demand for
power generation and domestic use that was about half what AGDC
was showing and he wanted to see the numbers that got usage up
to 250 mmcf.
MR. DUBLER replied the numbers were an average for one year. One
of the requirements for this project was enough storage in Cook
Inlet to either store gas underground or in tanks to meet demand
during peak months.
SENATOR DYSON said his figures were about half of his for power
generation and domestic use and he wanted to see his backup.
MS. WILCOX responded that Mr. Dubler's figures were an average
of a year and obviously in January and February the use would be
a lot higher than 240 mmcf. That is why storage in Cook Inlet is
really important.
SENATOR DYSON asked what the usage is now on an average basis
for public generation and domestic use.
MS. WILCOX replied 240 mmcf/day including the power generation
going up from South-central to the Interior. She pointed out
that the full assumptions of the Susitna Hydro Project were in
the report as well. Susitna would deliver 75 percent of the
power needs of South-central, which is why it was classified as
complementary to the pipeline in the project plan.
CO-CHAIR PASKVAN said it seems like the LNGs is an important
part of the demand chart and asked if there were no LNGs what
impact that would have on the tariff. He wanted to know how the
glut of NGLs due to shale gas would impact the project and what
the price expectation is for the relative difference of the NGLs
to gas itself.
10:23:36 AM
MS. WILCOX answered the first question - what happens when there
is no LNG. Since it is a major industrial anchor, the logical
leap is that the pipeline would have to be smaller (from 500
mmcf to 250 mmcf). With NGLs, those tariffs numbers are
presented in the report. They compare $7.75 in nominal dollars
for a South-central tariff to about $12.00 for both Fairbanks
and Anchorage.
As far as the NGLs are concerned, the true blend of the shippers
in this line becomes available after the end of open season, and
while they represent a major wedge in the assumption, they are
not necessarily the only tenant that could fill that space.
Other tenants may need dry gas, so they may not have as big an
impact on lowering the tariff as the NGLs will. But ultimately
you attract all the shippers that you can and figure out what
project you can get a design out of and what tariffs you can
offer. Their report compares a dry gas pipeline of the same size
in which the tariff goes from $7.75 to $9.25 if you take out
NGLs but still pump 500 mmcf of utility gas.
SENATOR STEDMAN said he'd like to see a chart like this looking
at a project except in reverse where with the most assured
markets on the bottom (Anchorage and Fairbanks) and more
speculative markets on top. He asked if this is the only
alternative for power generation for the Railbelt.
MR. FAUSKE replied that he didn't intend to not be informative.
He and Ms. Wilcox have deferred certain questions to DNR,
because those people did the studies; it's not that they haven't
looked at the issue of other power generation. They only had one
year to answer questions and you can't answer them all in that
time. The chart can be redone and he added that an awful lot of
information hit them at the end of the day, like the USGS study
with the 19 tcf of gas in Cook Inlet and the 600 million barrels
of oil and 49 million barrels of propane, which was too recent
to be included.
10:29:09 AM
He exclaimed that Fairbanks is in a desperate situation; that
city cannot sustain itself at $23 compared to the same mmbtu
that South-central is paying $8.85 for. If you break that into
fuel oil, it's $30.00 for the same number of btus. There is
great concern around the state that they don't get into
"analysis paralysis." The problem must be solved and Alaska
needs to stop telling the world it is out of gas. Because the
next time people like him go back and try to sell 30-year
mortgage revenue bonds on Wall Street, they're going to go
aren't you the people who said you have five years of gas left?
The problem needs to be stated to the investor and then they
need to be told the solution and he hopes AGDC will be a part of
that process. As CEO of the Alaska Housing Finance Corporation
(AHFC), he said they have $2.3 billion in assets in the affected
area and those won't be worth very much if they don't have gas.
His own house is in that area; so, the problem must be solved.
AGDC wants to create useful graphs.
He said there has been a lot of pressure from other people. HB
369 delivers gas for a project at the least possible cost to
Alaskan consumers; he can't do that with a 48-inch piece of
pipe. Just the incremental cost from Prudhoe Bay to Fairbanks is
$2.8 billion. Doing the large line is a policy decision for the
state to make.
10:33:23 AM
He explained that other states have dealt with similar
situations. Wyoming's Gasline Authority is an example of a
design that started out at 1 bcf and is now over 12 bcf/day. So,
systems are built and expanded through looping and compression.
Many systems aren't built to their maximum capacity, mainly
because regulatory agencies won't allow that cost to be passed
on to consumers. Real considerations have to be given to
building a larger line.
MR. FAUSKE remarked that $400 million is a lot of money for the
state to put up, but he always thought it would have to put up
between $3 and $4 billion. Currently, at plus or minus 30
percent, the state is putting $400 million into this project and
selling revenue bonds to finance the rest. The rating agencies
base the bonds on the revenues that support the project and the
tariffs would pay the duty on the revenue bonds. So it would be
an investment of $7.5 billion, but not all in cash. Cash can be
used for those things that are not bondable.
Without AGIA, which is far a larger project, Mr. Fauske said,
this would be the biggest project in North America. It is worthy
of their consideration and study. They can't continue forward
with this "up in the air are we going to have gas or not."
Alaska is probably the only state in the union that is in a
position to even be having this discussion.
10:35:38 AM
SENATOR STEDMAN stated the need for an update on the Donlin
Creek Mine and its potential LNG issues and opined that he would
be extremely surprised if Alaska would be able to issue a
substantial amount of debt for an instate gas line to private
investors if it didn't have the cash to back it up.
As long as he has been on the Resources Committee, Senator
Stedman said they have tried to increase the gas supply out of
Cook Inlet. The state's tax structure was been substantially
changed recognizing the gas price was so low in Anchorage that
no one would develop there. The year before that, $60 million in
credits was passed which caused a "Cook Inlet stampede" that
appears to be working because a jack up drill rig is sitting
there now. At the same time, there has been a substantial
increase in the estimate of available resource there. The issue
of gas into the Railbelt did not materialized in just the last
12 months; Alaska has been incrementally stepping on the
economic throttle in Cook Inlet for at least seven years. "As
Cook Inlet would not respond, meaning more gas to the Railbelt,
we kept hitting the throttle harder and harder to the point now
where we're virtually paying for the first jack up well and then
incrementally the next couple after that."
CO-CHAIR WAGONER said that currently if they hit a commercial
find, 50 percent of the credits are reimbursable to the state.
He asked if a figure on the need for gas and alternative heating
sources in Fairbanks and outside of Anchorage was available. He
remarked that he had constituents that had an Enstar gas line
going right past their house and they couldn't get it hooked up.
10:40:05 AM
MR. FAUSKE replied that he would get that number for him.
CO-CHAIR WAGONER asked about the hydro project and said there
was no mention of the Ormat project or CIRI coal gasification.
He wanted to know why those are excluded.
10:41:56 AM
MR. FAUSKE said the number in the Railbelt area near Anchorage
is 175,000 households with gas; he didn't know the total number
but would get it for him.
SENATOR STEDMAN felt the energy equivalency cost from around the
state should be looked at. Whether you are in Fairbanks or
Juneau, he said the cost of heating a home with oil should be
roughly the same.
MS. WILCOX answered Senator Wagoner's question saying that the
two basic reasons Ormat and CIRI are not on the chart was
because the technology was in an earlier stage of development
and the cost numbers weren't as good for that power.
CO-CHAIR WAGONER suggested looking at that technology again and
said that geothermal has been around for decades.
10:44:37 AM
MR. DUBLER indicated that at the time of putting this
presentation together he didn't have information on which kinds
of power would be produced, and of course that would be included
in the future.
CO-CHAIR WAGONER said the initial project was 40 megawatts.
10:45:47 AM
At ease from 10:45 to 11:01 AM.
11:01:11 AM
MS. WILCOX said the next slide starts setting up the case for
what this gas pipeline project can deliver to South-central and
a point of comparison based on the LNG import study by SAIC. It
started with a cost of $14 (2011 dollars) for importing LNG to
fulfill the South-central demand. The study looked at demand
over 20 years during which the required regasification facility
would be depreciated. They looked at full demand for the
modeling case rather than any ramp up, which would be what would
really occur. With that, they believe the $14 would be one of
the lower costs for getting LNG into Cook Inlet (assuming use of
Pacific Rim markets for pricing) and without the costs
associated with local distribution. They used an oil-indexed
cost for LNG plus $1 for regasification.
Compared to that $14.00, she said, the ASAP project could
deliver the $5.63 tariff, plus the assumed $2 netback on the
North Slope, plus the current local distribution cost of $2
(Enstar number), for a total of $7.63. But with local
distribution, the full consumer cost is estimated to be $9.63.
CO-CHAIR PASKVAN asked if the imported LNG price would be
comparable to the price the state would get exporting Alaska
natural gas.
MS. WILCOX answered yes; they use consistent price assumptions
for import and export scenarios.
CO-CHAIR WAGONER asked if the $5.63 was based on having an
industrial user or, in other words, having the maximum amount
coming through the line, not just 2.5 mmcf.
11:05:38 AM
MS. WILCOX said that right now the state is at a crossroads and
has many energy options that were not included in the report
since LNGs are the most able and reliable to fill the entire
demand. Renewable energies, including hydroelectric and
geothermal, Cook Inlet exploration, coal, and the storage of
natural gas (essential to this project because it evens out the
demand throughout the year) were all acknowledged.
She said the question they were faced with was how to define
"commercial liability." It could be defined by asking if Alaskan
gas is competitive with other suppliers, but since this report
had a narrower scope, they defined it by asking themselves if
the pipeline could deliver an economic netback for the sale of
the gas on the North Slope and if they could deliver a tariff
that would be competitive with the next best alternative for the
consumers.
Other considerations included (from builder/owner/operators) a
100 percent firm transportation commitment over the first 20
years and being able to depreciate the project over 20 years as
well. This project has enough risks and investors need to have a
return they can count on.
11:08:36 AM
REPRESENTATIVE SEATON pointed out that there are two ways to
analyze netbacks and one is using a 3 percent escalator for
inflation. But this project was not analyzed with any escalator
built into the gas supply contract. He asked if there was any
kind of parameter to look at in terms of other contracts and he
wanted to know if 3 percent was an industry standard.
MS. WILCOX answered LNG sales prices vary up and down depending
on where oil prices are. The modeling assumption was that oil
prices would inflate at 3 percent just like everything else in
the project. In reality, the sale price would be indexed to
whatever oil prices are.
REPRESENTATIVE SEATON asked what producer gas contracts look
like.
MS. WILCOX replied since the majority of the gas would be sold
in a market that is indexed to an oil price, the netback would
therefore also be indexed. Ultimately that is where the revenue
comes from.
11:12:08 AM
SENATOR WIELECHOWSKI asked if estimates were based on an $80
barrel oil price.
MS. WILCOX answered yes.
SENATOR WIELECHOWSKI said DNR projections were for $100/barrel,
so the tariff goes up 35 cents for every $10 increase in the
price of a barrel. So at $100, the $9.63 tariff would go up to
70 cents.
11:13:01 AM
MS. WILCOX answered that was right. And since LNG imports are
indexed to oil they would go up accordingly. AGDC held a non-
binding expression of interest in May and June and received
responses from a diverse group of players and total interest
came close to pipeline capacity. Not everyone participated, so
they anticipate more upside potential. The estimate of pipeline
capacity by 2019 refers to the rate of ramp up that the pipe
could achieve. Most of the participants said they would be
interested in a long term contract ranging between 10 and 30
years.
CO-CHAIR WAGONER wanted to know if the same commercial customers
were interested in the TransCanada project by.
MS. WILCOX replied that she didn't know.
REPRESENTATIVE SEATON said that exported gas would be taxed
under the ACES model and in-state gas usage would be taxed at 70
cents per mcf or 5 percent for NGLs and wanted to know if that
was brought up as discussion for precedence agreements needing
negotiations with the state for fiscal terms.
MS. WILCOX answered no.
11:16:00 AM
MR. DUBLER said they had frank discussions with 11 pipeline
companies in the last year. Size and capacity was not an issue,
but the State of Alaska would have to fund a project through
open season, because companies weren't interested in taking that
gamble and discussions with DNR have begun about using the State
of Alaska as a firm shipper, which would mean using the royalty
gas of the state in return for 90 percent firm shipping
commitments from others if customers were willing purchase the
gas. He said the 100 percent firm transportation commitments
would be required for financing of a transaction like this and
the AGDC will select a BOO during FEL 2. They have at least four
letters of interest from companies already that want to build
this line today.
11:19:00 AM
SENATOR WIELECHOWSKI asked what the rate of return on equity for
the pipeline company would be.
MR. DUBLER answered that it would be in the range of 11-13
percent; they assumed 12 percent in their projections.
SENATOR WIELECHOWSKI asked if any organization would be
responsible for reviewing that.
MR. FAUSKE answered that was a generally accepted rate of return
on projects like this from Maine to Honolulu; and it could go as
high as 14 percent. He also stated there is a reason AGDC
recommends state ownership - the cost of capital and the return.
SENATOR WIELECHOWSKI said he understands one of the advantages
of having RCA oversight was that they will look at the costs
that are being incurred to make sure they are fair.
MR. DUBLER said AGDC will have an ownership committee to oversee
this project and ensure that the state's costs are fair.
CHAIR PASKVAN thanked him and noted they were now into the
individual tariff components.
MS. WILCOX introduced Mike Ellenbach, Manager at Black & Veatch,
who was responsible for the tariff projections in the AGDC
modeling.
11:21:43 AM
MS. WILCOX said in the economic analysis, AGDC tried to bring
everything back to 2011 dollars. That was the reason the tariff
build-up was without inflation. It was calculated with $5.63 in
South-central and $6.45 in Fairbanks with the same assumption as
the real world with the startup of the pipeline in 2019 and a
ramp up over three years. The only thing excluded was inflation.
Black & Veatch ran that projection to compare that number to
current consumer costs. The real tariff would depend on
inflation during the construction phase and the ultimate terms
of financing.
She said the report showed $7.75 (compared to $5.63) for the
actual nominal tariff, which did take inflation into account
between 2019 and 2038; this tariff was used in all of their
economic feasibility studies and included the 3 percent
inflation. The portions of the tariff that were related to the
gas conditioning facility (GCF) were $1.42 for the pipeline
portion and $2.56 for the GCF between the North Slope and Dunbar
(all of the molecules are gas that are going through that
portion of the line).
A smaller volume goes to South-central; some was taken off in
Fairbanks. And the NGL extraction that happens in South-central
(assuming this is a rich gas pipeline) is $1.65 charged to
South-central users only. That makes up the $5.63 Southcentral
tariff. The Fairbanks portion, the $2.47, is the recognition
that as a rich gas pipeline, NGLs would be taken out of it and
put back into the line and re-extracted again at Cook Inlet,
which is $1.65. But in order to bring the Fairbanks gas to
utility grade with the smaller economies of scale, they would
pay $2.47, adding up to $6.45.
CO-CHAIR PASKVAN asked if a tariff model like Detroit in the
issuance of its motor vehicles had been considered. In other
words, why impose this "$250 million straddle" on Fairbanks? The
report indicates that both Big Lake and Fairbanks have NGL
handling, yet the only tariff imposed was the NGL handling in
Fairbanks.
11:26:04 AM
MR. ELLENBACH answered that some NGL extraction costs were
included in the $1.65 (pipeline Dunbar to Big Lake
Interconnect). The costs are allocated to the customers that are
receiving the service from those costs, and because Fairbanks
has a lower demand, it receives a slightly higher tariff. But he
noted that overall, Fairbanks is getting a lower tariff because
of all the demand flowing to Anchorage (less than if no gas were
going to Anchorage).
CO-CHAIR PASKVAN said he assumed a reciprocal advantage for
Anchorage in terms of a lower tariff because of Fairbanks
demand. He was looking at the "$280 million in the Fairbanks
straddle" and how that relates to a $2.47 tariff when a $3.1
billion investment equals a $2.56 tariff. Why isn't that
straddle imposed on all the .5 bcf users?
MR. ELLENBACH explained that the model charged it to the
Fairbanks customers, but it could be modeled a different way.
CO-CHAIR PASKVAN said under their modeling, Fairbanks doesn't
get any benefit from the NGLs.
MR. ELLENBACH responded that was not true, because NGLs are in
the pipeline and that lowers the overall tariff for the entire
project.
CO-CHAIR PASKVAN asked why the same logic wouldn't apply to
distributing those costs over the whole line.
MS. WILCOX responded that the tariff was modeled after the most
defendable model in front of a regulator as well as for the
project as a whole. And besides Fairbanks, other communities
might want to take off gas from this pipeline. In that case,
they wondered if that would create a straddle plant at every off
take location. If the position is taken that everyone pays a
postage stamp rate for the system, from the precedents they had
seen in other pipelines, it would be less dependable in front of
a regulator and it would be difficult to determine which off
takes are economic and which aren't.
11:30:14 AM
CO-CHAIR PASKVAN asked if the cost of that saddle were
distributed across the line, would the increased tariff be less
than 20 cents per mcf.
MS. WILCOX replied that she didn't have the answer to that
question. A tariff needs to be low enough to create an
industrial consumer and build a 500 mmcf line and not have the
tariff jump to $12. That is the balance the project shows at
this time, but it is an estimated structure. If the policy of
the state is to have all consumers share cost equally, it would
be a different model.
SENATOR WIELECHOWSKI asked the impacts of three different
things: were Enstar's local distribution costs were factored in;
the impact of removing NGLs completely; and the impact to the
tariff of removing LNG completely.
MS. WILCOX replied that Enstar's local distribution costs were
not included in the tariff. According to Enstar's information
those are around $2 mmbtu, which was included in the $9.63. If
this pipeline is still rich gas, but it is built for 250 mmcf
rather than 500 mmcf, then the tariff would go to $11.82 for
Anchorage and $11.88 for Fairbanks, because economies of scale
in going to Anchorage would be lost. Same case if it was a 500
mmcf pipeline but it is dry gas; then the tariff goes to $9.25
compared to $7.75 (in nominal numbers). So, the impact of a
smaller pipeline on the tariff would be bigger than the impact
of removing NGLs. It's one of the factors driving them to try to
get the tariff as low as possible to have the best chance of
getting an industrial tenant.
SENATOR STEDMAN said he assumed this was "kind of an anomaly
project" compared to other gas lines around the country in that
the state may put in half of the upfront cost. If the state took
a 50 percent equity position and is looking at tariff
differences between Anchorage and Fairbanks, how would the
regulators look at the equity infusion when it comes out of a
state treasury that is owned collectively by the entire state.
Or do they have to deal with that?
MR. DUBLER replied that in their model the equity comes from the
builder owner operator and not from the state. In all the
assumptions they ran, the state's contributions were limited to
the initial $320 million upfront money. Any money after that was
not considered in their tariff runs. The 30 percent equity would
come from a third party, an Enbridge or Mapco, and they would
earn a 12 percent return on that equity for building the
pipeline. The 70 percent would be debt that the pipeline company
would issue, and it probably wouldn't be necessary for the state
to guarantee that in the opinions of a couple of companies they
talked to. They said it was a "turnkey operation."
11:37:40 AM
MR. FAUSKE added that if you go to 100 percent debt, the $9.63
figure probably drops by $1. One of the issues is state
ownership. A private ruling from the IRS would be needed to even
explore how to use the Railroad's tax exempt bonds. The issue of
ownership needs to be based on adherence to the law.
SENATOR STEDMAN wanted some clarification. Looking at Susitna,
half the money will come from the state. Susitna is not going to
charge 12 percent back to the customers in the Railbelt. He
didn't think that was financially viable without substantial
support from the state. He wanted to know how to compare equity
across the state.
MR. FAUSKE replied that his concern was that the state would
have to put up cash to make that project viable. The $9.63
tariff was at a 70/30 debt-to-equity ratio with no state input
other than the initial $400 million. The rest was an investment
where the state would sell revenue bonds. One option AGDC looked
at was charging communities that would get gas immediately a
surcharge that would go into a fund to generate money for
residents of the state that wouldn't get gas immediately, but
regulators wouldn't allow that. The issue goes back to a policy
decision. The state needs to find out if it can beat the price
that is currently being paid for propane.
11:45:16 AM
SENATOR MCGUIRE stated that it is important to remember that
both the Senate and House tasked AGDC to come up with the most
creative financing they could. She commended the presenters on
their hard work.
11:49:34 AM
CO-CHAIR PASKVAN said the committee would like to see
information on the no inflation option, specifically the
difference between the enhanced stream NGL and a dry pipeline to
figure out what the tariffs would be. He said he would like to
know what AGDC thinks about NGLs going through the oil line.
Right now NGLs are being transported through the TAPS line and
there is talk about injecting those NGLs south of pump one so
vapor limits can be sidestepped.
MS. WILCOX answered that NGL availability for this project would
be sorted out on the North Slope. Ultimately, producers will
make those decisions on how much is available and how to ensure
oil production is not hurt in the process. AGDC modeled an
enriched stream that includes some propane and butane that does
not come from a natural gas facility and all indications so far
are that some NGLs will be present but not enough for a large
export operation.
CO-CHAIR PASKVAN asked if there would be any problem off-taking
NGLs to service Interior Alaska.
11:54:32 AM
MS. WILCOX answered that in terms of cost, another piece of
infrastructure would be needed in order to do that.
REPRESENTATIVE P. WILSON asked if non-cash benefits had been
considered as incentives and if the AGDC had checked to make
sure there was no violation of AGIA. She also wanted to know if
the out of balance in-kind royalties would be construed as
putting money into the project.
MS. WILCOX replied that even if they were considered a monetary
contribution, the trigger would be the size of the pipeline.
11:55:55 AM
REPRESENTATIVE SEATON asked if carrying NGLs would significantly
change tariffs. It looked like carrying NGLs would raise the
Fairbanks tariff and lower the Anchorage tariff.
MR. ELLENBACH replied that when looking at a dry gas figure,
AGDC used a similar approach of allocating the costs to the
customer.
REPRESENTATIVE SEATON followed up by asking about the spike gas
user. The NGL user was getting subsidized by the higher tariff
that Fairbanks pays. He asked for AGDC to get back to him with
that information.
MR. FAUSKE thanked the committee and his team.
CO-CHAIR PASKVAN thanked AGDC and at 12:01 p.m. adjourned the
meeting until 1:30 p.m.
CO-CHAIR PASKVAN called the meeting back to order at 1:32 p.m.
and invited Commissioner Sullivan to speak.
DAN SULLIVAN, Commissioner, Department of Natural Resources
(DNR), said his presentation would cover the Governor's Secure
Alaska's Future Initiative, which is principally focused on oil
but has an important gas aspect. His presentation would also
cover oil and gas synergies, progress on commercializing North
Slope gas and ideas that are important for a path forward.
First, Commissioner Sullivan gave a quick update on the focus of
DNR under the first part of Parnell's administration, which was
to reverse the TAPS throughput decline and get to the goal of 1
million barrels a day.
1:36:39 PM
COMMISSIONER SULLIVAN said DNR has a comprehensive five-part
strategy. The first key aspect is to enhance Alaska's global
competitiveness and investment climate. The second part of the
strategy is to ensure the permitting process is structured.
Third, Alaska needs to facilitate the next phases of North Slope
development. Fourth is unlocking partnerships with key
stakeholders, like the federal government. In some ways it's a
two steps forward, two steps back process with them. Recently
U.S. Secretary of the Interior Ken Salazar visited Alaska and he
made some very important statements on the importance of oil and
gas development for the country, but then at the same time Fish
and Wildlife designated ANWR 1002 as a Wilderness Area and the
EPA is looking at dramatically expanding Clean Water
jurisdictional issues. Alaska needs to promote positive
investments to world markets. DNR is getting out and telling
companies the stories on the geology of Alaska.
1:41:53 PM
COMMISSIONER SULLIVAN talked about why oil matters when these
meetings are mostly talking about gas. There are very important
synergies between oil and gas development. AGDC and DNR have
been working closely together and have specific assignments. DNR
has a very different one, which is how does a gas line fit with
other resource development issues in the state. DNR's long term
goal is to help spur TAPS and to have two lines delivering oil
and gas.
There has been progress on commercializing gas and AGDC and AGIA
are examples. Commissioner Sullivan stated that the state had
reached resolution with the unit operator and that advances the
state's interests. The settlement terms are still confidential
but the settlement focuses on the development of the Pt. Thomson
unit which contains both hydrocarbon liquids and gas. DNR could
provide more specific information to the legislature on a
confidential basis.
1:47:26 PM
CO-CHAIR PASKVAN said he would like to see the settlement and
that it would be a material step forward in Alaska's future.
SENATOR FRENCH asked if the state and Exxon are through
negotiating and now Exxon is negotiating with its partners.
COMMISSIONER SULLIVAN stated that it was fair to say that.
SENATOR WIELECHOWSKI asked for the administration's opinion of
the big line and if they still support AGIA.
COMMISSIONER SULLIVAN answered yes. DNR doesn't see the AGIA and
AGDC projects as being in competition with each other. They
address important but very different issues. There are ways to
integrate some of the different approaches.
CO-CHAIR PASKVAN interjected that most members of the committee
and the public are assuming the tariffs to the consumer under
AGIA would be the lowest. The problem looking at the difference
between the AGDC and the AGIA line is trying to balance access
to natural gas compared to the lowest potential tariff.
1:51:20 PM
COMMISSIONER SULLIVAN said DNR was not setting up AGIA and AGDC
as an either/or situation. They were continuing to work with the
partners and the licensee on the big line.
CO-CHAIR PASKVAN asked when that information about the Pt.
Thomson deal would become public.
COMMISSIONER SULLIVAN replied that it would be available soon.
He added that those discussions were not being driven by a
timeline.
CHAIR WIELECHOWSKI wanted to know why consumers would buy more
expensive gas from a smaller line.
COMMISSIONER SULLIVAN said he would address that further along
in the presentation. He emphasized the sense of urgency and said
that it is a legitimate concern but it should not force the
state to make strategic mistakes. DNR has been focusing a lot on
the TAPS issue, which is an immediate strategic issue facing the
state along with developing North Slope gas. He stressed the
real need for flexibility as Alaska goes forward saying that
markets are fluid and have shifted considerably.
COMMISSIONER SULLIVAN said the future is uncertain; even the
bullet line would be a mega project and big projects don't turn
around in two or three years.
1:58:23 PM
CO-CHAIR PASKVAN asked about the dual pipeline term. He asked if
that meant both gas and oil.
COMMISSIONER SULLIVAN answered that he was talking about TAPS.
CO-CHAIR PASKVAN asked if that means two pipes rather than one
with dual products.
COMMISSIONER DAN SULLIVAN answered yes, two pipes. Any project
in Alaska will have challenges including shipper commitments,
fiscal terms and scattered allegiances. Projects also face
common synergies. Markets beyond the existing state needs are
also an issue.
2:00:50 PM
COMMISSIONER SULLIVAN talked about the importance, from the
states perspective, of including alignment on data acquisition
and permitting in projects. The administration has been working
on looking at the key principals that would be applied to any
gas project including low cost energy to the state, maximizing
the resources base through high volume, particularly with gas,
and making sure any project incentivizes exploration of oil and
gas development.
Integration in many ways makes sense from the states
perspective. The state needs to reduce redundancies and look at
the ways certain entities get set up. DNR is not coming to this
committee saying which way to move forward, but these ideas have
a lot of potential. In terms of the integration of projects,
there are all kinds of possibilities in flexibility and
creativity; it could be something as simple as data sharing.
2:05:26 PM
SENATOR FRENCH asked what the difference was in the cost of the
AGDC line as far as gas to Anchorage verses a spur line.
COMMISSIONER SULLIVAN asked if he could get back to Senator
French with that answer.
CO-CHAIR PASKVAN asked Commissioner Sullivan to provide that
information to his office.
COMMISSIONER SULLIVAN said consensus will be critical. The key
will be getting ideas out and working on different approaches.
The state needs to work with producers. There will be additional
guiding principles that are important as the state looks at
moving forward with gas line issues. The state has a licensee
right now and it's important to honor those contractual
commitments.
2:10:22 PM
COMMISSIONER SULLIVAN concluded by thanking the committee. The
DNR has been focused on what they see, from a natural resources
perspective, as the single most critical issue Alaska faces,
which is working on reversing the TAPS throughput issue.
Commercializing North Slope gas is also important. The AGDC
report spurs the issue of the need for public discussion. DNR is
working on moving forward with developing gas resources and in
doing so, addresses the needs for in-state gas use at the lowest
cost while maximizing the commercialization of exports.
CO-CHAIR WAGONER congratulated Commissioner Sullivan on
advancing Pt. Thomson litigation.
COMMISSIONER SULLIVAN said that settling litigation is never
easy and it is not over, but it is important to move forward
quickly. Pt. Thomson is important for addressing the TAPS
throughput issue.
2:14:05 PM
REPRESENTATIVE SEATON asked if the administration supported a
gas line that would be exclusive to an initial bidder.
JOE BALASH, Deputy Commissioner, Department of Natural Resources
(DNR), answered that the state needs to do something that
continues to promote utilization. Common carriage verses
contract carriage is one of the recommendations in the AGDC
report and it is fair to say that it is one of the realities
needed to secure shippers. Currently, under state law all
pipelines are required to be common carrier. In order to move
away from that, the state needs to eliminate that provision or
replace it. The AGDC report identifies that issue and the means
for solving it within the confines of the project. Looking at it
with boarder interests in mind, something needs to be done to
replace common carriage with something that promotes utilization
of infrastructure. On a common carrier pipeline, regardless of
capacity, room has to be made for any common customer. That
includes pro-rating the throughput of all current customers.
There needs to be some way to assure the first entrants that
they will continue to have space in the line. One of the ways
AGIA deals with that is through periodic expansion.
2:19:07 PM
REPRESENTATIVE SEATON said that until the small pipeline becomes
a big pipeline, there would no incentive for exploration because
it would go to a private carrier and asked if there was a way to
enhance exploration.
MR. BALASH mentioned the Fairbanks pipeline project, which he
said wasn't being talked about. The lifeline of that project is
projected to be 104 years. No one would want a situation where
104 years go by before there is room in the pipe to put any new
gas. From the state's perspective, the question will be how long
before capacity can be expanded.
2:22:31 PM
REPRESENTATIVE SEATON asked if the administration was going to
oppose the limitation on participants putting gas into the
pipeline or would they be flexible. He wanted to know if the DNR
guiding principles are in opposition to the AGDC project.
MR. BALASH answered that DNR was not in opposition to AGDC
recommendations, because they are not specific enough, but the
loss of common carriage would be a concern.
CO-CHAIR PASKVAN asked if the AGDC line would be a contract
carrier north of the 68th parallel and a common carrier south of
that. That would be a distinction where someone has access.
MR. BALASH replied that the Right-of-Way Leasing Act does have
some legacy provisions from the 1990s relative to what was
contemplated then as an LNG project, but the language in that is
very specific. One of the things they would have to identify and
work with the AGDC on to ensure works for whatever might move
forward here.
2:24:38 PM
CO-CHAIR PASKVAN asked if someone could find gas north of 68th
parallel and inject 400 mmcf a day after 500 mmcf/day are
contracted.
MR. BALASH answered that the pipeline capacity would have an
impact, but he wasn't sure if Senator Paskvan was referring to
the financial assurances piece of the AGIA law or the Right-of-
Way Leasing Act rules.
SENATOR WIELECHOWSKI said some financial analyses needs to be
done between Cook Inlet and building a bullet line. He asked
what happens if Cook Inlet doesn't pan out, because if a big
line is built then there is no need for a bullet line.
CO-CHAIR PASKVAN agreed that there needed to be more internal
DNR studies.
MR. BALASH apologized for the confusion and said another session
the next day would focus on some of those issues. He said he
gets nervous about state officials saying Cook Inlet is the
answer. From a policy perspective, there should be questions
about Cook Inlet capacity and investment dollars. A year ago no
one saw the exploration or the USGS numbers. The state can study
and estimate, but there has to be an increase in smart
investment dollars from the private sector and that will be an
important factor.
DNR won't say that AGDC issues have gone away, but there is
increasing evidence that there have been positive changes. DNR
doesn't want to make policy decisions that would undermine
anything. Alaska has to build the infrastructure where the gas
is. There should not be a deadline, since the private sector
will be making the financial decisions in the end.
2:35:44 PM
MR. BALASH said DNR is very interested in moving forward with
the flexibility, but it doesn't want to get locked into
anything.
SENATOR WIELECHOWSKI asked if anyone had looked at the
possibility of building the bullet line because of the increased
interest in Cook Inlet.
MR. BALASH replied that it was not in the state's interest to do
something that dis-incentivizes Cook Inlet exploration. At the
same time, the state shouldn't bet the bank on the fact that
Cook Inlet will have resurgence to such a degree that concerns
will go away.
2:38:19 PM
SENATOR MCGUIRE asked for a scenario checklist considering
timing of AGIA versus the AGDC pipeline and their intersection.
Specifically, she wanted information on any absolute barriers
and wanted to know where the state could leverage its value. She
said commercial market build-up and synergies with the global
market were areas where people should be looking.
2:43:09 PM
MR. BALASH replied that DNR would be happy to get those numbers.
CO-CHAIR PASKVAN said that the Interior had a much higher
anxiety over energy costs and he wanted to know what the
potential was for pipelines coming from the North Slope heading
south. He said there needs to be information for an alternative
to the 48-inch line and the 24-inch line and even the Artic Fox
line that might service just the Interior. And with the new USGS
numbers, Senator Paskvan said he wanted to see what the cost was
for a line coming out of Cook Inlet going north.
CO-CHAIR WAGONER said there was a big difference between the 19
tcf that was possible and the proven reserves on the Slope.
REPRESENTATIVE SEATON asked if DNR had been investigating
converting natural gas to methanol for transport as another way
of commercializing it.
MR. BALASH responded that the DNR had heard from several
proponents of using North Slope gas for methanol. There was some
feedback on the technical challenges. Certainly that would be an
option, but it faced some big challenges including how the gas
would be acquired in the first place.
2:48:35 PM
REPRESENTATIVE SEATON said the intriguing part of this
presentation was looking at the Siberian pipeline that is 30
percent methanol. It seems like the AGDC line would not allow
the exploration and commercialization from additional sources.
MR. BALASH said DNR was listening to all parties and mentioned
the Marsh Creek project that deals with high voltage direct
current transmission lines to move energy from the North Slope.
SENATOR FRENCH asked if the Commissioner would like to comment
on the news that this year will be the busiest winter on the
North Slope in anyone's memory with at least 15 new wells.
2:52:32 PM
MR. BALASH said that was great news. The plan was not hurt by
any of those projects, but Alaska was still not where it should
be in terms of investment. The state is focused on getting to a
million barrels and it is going to have to invest billions to do
that. Even with new wells, Alaska is still not in the game. The
ultimate number to look at is TAPS throughput.
CO-CHAIR PASKVAN said that the committee was here to address how
to distribute the lowest-value hydrocarbon for in-state use and
export the highest-value hydrocarbon, which is oil. With respect
to the natural gas, AGDC projects that 50 percent of the volume
will be set as exports. He wanted to know what DNR is doing to
access the natural gas export market, so Alaskan resource can
potentially fill the demands of Japan or Korea or others.
MR. BALASH said DNR hadn't gone overseas to the Asian markets.
They have been principally focused on oil, although gas reserves
have certainly been mentioned. If there were interested
customers, whether in Alaska as anchor tenants or Asian buyers,
DNR would take all those meetings.
CO-CHAIR PASKVAN asked what Alaska is doing from the
administration's standpoint in following up with Japan for
future plans on nuclear development.
MR. BALASH answered that from his perspective, LNGs shouldn't be
off the table. It's important to remember private sector
partners are critically important. The state can identify the
market and just hope everything else will just fall into place
but it's more complicated than that.
2:59:36 PM
KURT GIBSON, Director, Gas Pipeline Office, Division of Oil and
Gas, Department of Natural Resources (DNR), said that while DNR
may identify where opportunities may or may not exist, as policy
makers, it is important to look at where the resources reside
and look at it in a way that protects the state's interests. At
the end of the day, the entities paying the bill will determine
the market.
He said, in 2009, the Division of Oil and Gas did a study on the
major fields in Cook Inlet and looked at the remaining reserves.
Tomorrow they will hear a new report on the production costs.
More work that needs to be done by the department.
REPRESENTATIVE SEATON mentioned the earlier discussion about
open season and precedence agreements like the ones currently
going on with AGIA where fiscal terms fall under ACES. He wanted
to know if there was a constrained timeline and what the
legislative involvement would be on fiscal terms with LNGs.
COMMISSIONER SULLIVAN said that was a very good question. Those
discussions have not begun yet and were probably premature.
REPRESENTATIVE SEATON wanted to know if that meant open seasons
will become synchronized at some point.
COMMISSIONER SULLIVAN said the idea will be to see shippers get
behind a project. Multiple open seasons may have some merit, but
there will be some disconnect between the timing of the initial
open seasons; AGIA was passed in 2007 and HB 369 wasn't passed
until 2010. Just having an open season won't result in an
outcome for the major gas sale project and, at the same time,
interest might be expressed in the AGDC project. However, that
may not be an "apples to apples" comparison.
COMMISSIONER SULLIVAN concluded that this was a discussion of
synergy points and the ideas weren't set in concrete. They were
just ideas DNR wanted to run by the legislature.
3:08:13 PM
CO-CHAIR PASKVAN thanked everyone for their presentations and
adjourned the meeting at 3:08 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| AGDC RESPONSE Wielechowski12Aug2011_FINAL.pdf |
SRES 8/15/2011 9:00:00 AM |
|
| Sullivan_Senate Resources Aug 15 2011_FINAL.pdf |
SRES 8/15/2011 9:00:00 AM |
|
| 2011-08-15 Senate Resources AGDC Presentation.pdf |
SRES 8/15/2011 9:00:00 AM |