Legislature(2005 - 2006)FAIRBANKS
08/24/2006 09:00 AM Senate SPECIAL COMMITTEE ON NATURAL GAS DEV
| Audio | Topic |
|---|---|
| Start | |
| Mayor Jim Whitaker, Chairman, Alaska Gasline Port Authority | |
| Bill Walker, General Counsel and Project Manager, Alaska Gasline Port Authority | |
| Radoslav Shipkoff, Director Greengate Llc | |
| Dr. Tony Finizza, Consultant to Econ One Research Inc | |
| Steven B. Porter, Deputy Commissioner, Department of Revenue | |
| David Van Tuyl, Commercial Manager, Alaska Gas Group, Bp | |
| Roger Marks, Economist, Dept. of Revenue | |
| Mike Menge, Commissioner, Dept. of Natural Resources | |
| Ken Griffin, Deputy Commissioner, Department of Natural Resources | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
SENATE SPECIAL COMMITTEE ON NATURAL GAS DEVELOPMENT
Fairbanks, Alaska
August 24, 2006
9:16 a.m.
MEMBERS PRESENT
Senator Ralph Seekins, Chair
Senator Fred Dyson (via teleconference)
Senator Donny Olson
Senator Thomas Wagoner
Senator Kim Elton (via teleconference)
MEMBERS ABSENT
Senator Lyda Green
Senator Gary Wilken
Senator Con Bunde
Senator Bert Stedman
Senator Lyman Hoffman
Senator Ben Stevens
Senator Albert Kookesh
OTHER LEGISLATORS PRESENT
Senator Gretchen Guess
Senator Gene Therriault
Representative Mike Kelly
Representative Bill Stoltze
Representative John Coghill
Representative Ralph Samuels
Representative Mike Seaton
COMMITTEE CALENDAR
Alaska Gasline Port Authority Presentation
Econ One Analysis of Port Authority Plan
Round Table Discussion of Port Authority Plan
PREVIOUS COMMITTEE ACTION
No previous committee action to consider
WITNESS REGISTER
JIM WHITAKER, Chair
Alaska Gasline Port Authority
Mayor, Fairbanks North Star Borough
PO Box 71267
Fairbanks, AK 99707
POSITION STATEMENT: Discussed the Port Authority Plan.
BILL WALKER, General Counsel and Project Manager
Alaska Gasline Port Authority
411 4th Avenue, Suite 200
Fairbanks, AK 99701
POSITION STATEMENT: Discussed the Port Authority Plan
RADOSLAV SHIPKOFF, Director
Greengate LLC
2001 L Street NW, Suite 901
Washington, DC 20036
POSITION STATEMENT: Discussed the Port Authority Plan
SENATOR GENE THERRIAULT
State Capitol, Room 119
Juneau, AK 99801-1182
POSITION STATEMENT: Discussed the Port Authority Plan.
REPRESENTATIVE RALPH SAMUELS
State Capitol, Room 126
Juneau, AK 99801-1182
POSITION STATEMENT: Discussed the Port Authority Plan.
DR. TONY FINIZZA
Econ One Research, Inc.
Suite 2825
Three Allen Center
333 Clay Street
Houston, TX 77002
POSITION STATEMENT: Presented analysis of Port Authority project
model.
REPRESENTATIVE MIKE KELLY
State Capitol, Room 434
Juneau, AK 99801-1182
POSITION STATEMENT: Discussed the Port Authority Plan.
DAVID VAN TUYL, Commercial Manager
Alaska Gas Group
BP
Anchorage, AK
POSITION STATEMENT: Discussed the Port Authority Plan.
STEVEN B. PORTER, Deputy Commissioner
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Discussed the Port Authority Plan.
ROGER MARKS, Economist
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Discussed the Port Authority Plan.
MICHAEL MENGE, Commissioner
Department of Natural Resources
400 Willoughby Avenue, Suite 500
Juneau, AK 99801-1724
POSITION STATEMENT: Discussed the Port Authority Plan.
KEN GRIFFIN, Deputy Commissioner
Department of Natural Resources
400 Willoughby Avenue
Juneau, AK 99801-1724
POSITION STATEMENT: Discussed the Port Authority Plan.
REPRESENTATIVE PAUL SEATON
State Capitol, Room 102
Juneau, AK 99801-1182
POSITION STATEMENT: Discussed the Port Authority Plan.
ACTION NARRATIVE
CHAIR RALPH SEEKINS called the Senate Special Committee on
Natural Gas Development meeting to order at 9:16:31 AM. Present
at the call to order were Senators Thomas Wagoner, Fred Dyson,
Kim Elton and Chair Ralph Seekins.
Mayor Jim Whitaker introduced the Port Authority representatives
Bill Walker and Radoslav Shipkoff.
^ ALASKA GASLINE PORT AUTHORITY PRESENTATION
^ Mayor Jim Whitaker, Chairman, Alaska Gasline Port Authority
MAYOR JIM WHITAKER, Chairman, Alaska Gasline Port Authority
(AGPA), said that he did not want to recap discussions that
occurred in Juneau, but to pick up where they left off.
Cooperation between the legislature, the administration, the
producers, and the Port Authority is in the best interests of
the state of Alaska and the Alaskan people. He recognized that
the producers have a significant role to play in the process and
it is important to align with them and with all the stakeholders
in the project if it is to move forward.
9:19:42 AM
^ Bill Walker, General Counsel and Project Manager, Alaska
Gasline Port Authority
BILL WALKER, General Counsel and Project Manager, Alaska Gasline
Port Authority, offered a slide presentation on the AGPA project
plan and introduced the project team:
- Bechtel Corporation - cost estimates
- Greengate LLC - financial analysis
- YPC (Yukon Pacific Corporation) - purchased from DSX
Corporation (Diana Shipping Inc.) with exclusive rights
to the permits and data that go with that
- TOTE (Totem Ocean Trailer Express) - presented proposals
for shipping
- Burmah Gas Transport (BGT) - Memorandum of Understanding
(MOU) with AGPA for tankers from their fleet of eight
U.S. built General Dynamics liquid natural gas (LNG)
tankers owned by Mitsui O.S.K. Lines, Ltd. and Nissho
Iwai (LNG Japan)
He presented a slide of West Coast LNG activity and noted that,
since the slide was prepared, a number of additional LNG
terminals have applied for permits. Most recently, BHP has begun
the permitting process to bring gas from Australia to
California, which is a concern. The most significant terminal is
Sempra's Costa Azul plant, shown on slide three, which is the
first LNG receiving terminal to be built on the West Coast. It
is currently under construction and has applied for expansion.
Slide four illustrates that one of Alaska's advantages in the
North American market is its proximity, which results in shorter
shipping times to the West Coast.
9:23:47 AM
MR. WALKER said that he would not go over each of the twelve YPC
and Alaska Natural Gas Development Authority (ANGDA) permits
listed on slides five through seven, because they were discussed
previously in Juneau, but pointed out what is noteworthy about
them. YPC spent over $100 million over a period of 15 years
obtaining the permits, and they are significant. Sempra has
invested about $1 million and Bechtel $8 million, based in part
on their review of these permits.
(Pause due to feedback from remote LIO.)
9:25:25 AM
In response to discussion about whether the permits are valid or
need to be modified, Mr. Walker said that Bechtel, Sempra, and
O'Melveny & Myers have reviewed them, and no one has walked away
from involvement in the project due to a problem with the
permits. There is also a warehouse in Anchorage full of data
compiled by YPC for this project over the past 15 years. The
recent right-of-way acquisition by ANGDA fits in well with what
AGPA is doing.
(Lost audio due to static.)
9:27:04 AM
He went on to slide eight, which shows the projects in direct
competition with Alaska for the North American gas market, and
stressed that all of these projects are moving forward. The
FERC's report to Congress, dated July 10, 2006, stated that LNG
would take away Alaska's markets if it doesn't do something
soon.
(Lost audio due to static.)
MR. WALKER said it is important to recognize that there is
significant competition and that none of the competing projects
is forming a 4-5 year study.
MAYOR WHITTAKER added that AGPA's concern is heightened by the
information on this slide. He reiterated that none of the
projects shown is being held up for a 4-year study; they are
moving forward and compete directly with Alaska's opportunity to
take gas to market.
MR. WALKER explained that slide nine is from a FERC presentation
and shows 45 terminal sites in various stages of permitting. Not
all of the sites will be permitted, but enough of them will be
that the American market should come into gas balance around
2012-2013. He pointed out that it shows significant involvement
by the North Slope producers in LNG receiving terminals for the
North American market and, while Alaska is in negotiation and
study mode, they are working aggressively to bring LNG into
their own receiving terminals.
He moved on to slide 10, showing the business plan of Cheniere,
which has a business relationship with ConocoPhillips. It has
five LNG receiving terminals in the permitting stages now and is
clearly targeting the Mid-West market.
MR. WALKER explained scenario A on slide 11. He said that the
Port Authority is not trying to prevent the gas line from ever
going through Canada to Alberta, but is opposed to holding up
the Alaska portion of the line waiting for that to happen.
Because it is in the study phase now, it is hard to say what the
timing of the Canadian pipeline might be, and the demand could
be supplied by the numerous LNG projects around the country
while Alaska is waiting.
9:33:28 AM
He went on to say that the market is not going to sit and wait
for Alaska's gas. If the project gets gas to south-central
Alaska by 2012, it could work and would bring value to the
eventual pipeline through Canada.
9:34:14 AM
MR. WALKER cautioned that if Alaska waits until after the
highway line is built, it is almost guaranteed to be too late to
capture the West Coast market. Slide 14 shows the risks to
Alaska, largely from the contract itself. The worst-case
scenario is that Alaska could be completely shut out of the
North American market due to activity elsewhere. AGPA is also
concerned about subordinating Alaska's interests to Canadian
demands. If the pipeline goes to Alberta first, there would be
approximately 35 percent in Alaska; if it goes all the way to
Chicago, 20 percent would be in Alaska and, with fiscal
certainty for 30-45 years, Canadian fiscal requirements could
impact the wellhead in ways that we cannot foresee and that
might not be in Alaska's best interests.
9:37:10 AM
He said that a 30-45 year exclusivity contract with no guaranty
of a pipeline is not good, and the no-penalty provision in the
contract is a step in the wrong direction for commercializing
Alaska's gas. Alaska's ability to manage its own resources is
also a significant concern with this contract. Point Thomson is
a glaring example of that. Right now, there is strong language
in the lease regarding development of Point Thomson and what
should have been done in the last 28 years; this changes those
development criteria to a diligence standard. There is a
provision that Point Thomson will be developed into the project,
but the gasline out of Alaska would be the only project
available for Point Thomson. He then stressed that the
sovereignty issue is huge; the state is giving up too much in an
attempt to bring reluctant partners to the table.
9:39:27 AM
CHAIR SEEKINS asked what sovereignty is being given up.
9:39:44 AM
MAYOR WHITAKER referred to Article 8 section 2 "General
authority of the Legislature shall provide for the utilization,
development, and conservation of all natural resources belonging
to the state." That exercise of sovereignty would be supplanted
by a 45-year contract. For 45 years, the legislature would have
no flexibility or control over the resource.
9:40:33 AM
CHAIR SEEKINS asked what elements of the contract would do that.
(Lost audio due to static.)
MAYOR WHITAKER responded that the timeframe would be of great
concern, the state's ability to respond to the market, and to
control the manner in which the state's resources are developed.
For the state's sovereign responsibility to be subordinated to a
commercial contract for any period of time is not appropriate or
necessary.
CHAIR SEEKINS asked if that sprang from the Stranded Gas
Development Act (SGDA).
MAYOR WHITAKER answered that when the SGDA was written in 2002,
the concern was relative to Alaska's gas having a place on the
market and the market's ability to pay a price sufficient to get
it there. The value of gas has significantly increased and there
is some relative certainty to that value, so the premise of the
SGDA has changed. The same basic question is again at issue,
whether the gas is actually stranded, making concessions
necessary to un-strand it.
9:42:56 AM
CHAIR SEEKINS said that he is trying to get to the root of the
problem, and questioned whether the legislature provided the
terms that sacrifice sovereignty in the SGDA itself.
9:44:01 AM
MAYOR WHITAKER replied that the short answer is yes. The
rationale for allowing that to occur was that the gas is
economically stranded, therefore the state would be willing to
make concessions to get to it, including some limitation of
sovereignty. The basic question is whether the gas is indeed
stranded.
CHAIR SEEKINS said that the purpose section of the SGDA doesn't
address whether the gas is stranded; that appears in some of the
assumptions later on. It was intended to provide long-term
fiscal certainty, in as much as the constitution would allow, in
order to get the gas to market. The question now is if the
contract itself is the root problem, or if it goes back to what
the legislature did in the SGDA.
MR. WALKER replied that it is the contract, not the SGDA.
SENATOR THERRIAULT said that the SGDA doesn't allow all of the
things that are in the contract, which is why the legislature is
likely to face a slate of proposed amendments. He does not
recall any significant discussion about loss of sovereignty at
the time they debated the SGDA.
9:46:06 AM
CHAIR SEEKINS said that he still wants to know precisely what
the state is actually sacrificing.
9:47:21 AM
MAYOR WHITAKER responded that it puts into question the State's
ability to control 85-95 percent of its revenue stream for 30-45
years.
9:48:06 AM
MR. WALKER reviewed the benefits of proceeding with AGPA's LNG
project. He commented that the time associated with obtaining
senior permits would be significantly reduced because AGPA
already has the permits and has only to amend them. The AGPA
project provides the earliest opportunity for in-state gas to
Alaskan communities and an independently owned pipeline provides
the best opportunity for open competition in natural gas
transportation.
9:49:53 AM
[indisc.] He used an analogy to illustrate the problem with a
producer-owned pipeline and went on to say that AGPA looks at
the pipeline as a non-profit utility to move Alaska's gas to
market and has always proposed to move the producers' gas on a
flow-through arrangement.
9:51:24 AM
MR. WALKER pointed out that the airlines don't own SeaTac
Airport, and that is a good model to work from. He said that
AGPA's project takes advantage of the North American, West Coast
and Mid-West markets, as well as providing for shipping overseas
if that is in Alaska's best interests. It can also be sized to
accommodate gas for a future pipeline to Alberta.
He noted that AGPA's project has been criticized for being ever
changing and conceded that, although the project has always been
to move gas from Prudhoe Bay to Valdez, where it would be put
into LNG, changes have been made to improve efficiency.
9:53:49 AM
CHAIR SEEKINS recognized that Representatives John Coghill, Mike
Kelly, Ralph Samuels and Bill Stolz had joined the discussion.
REPRESENTATIVE SAMUELS referred to the third bullet point on
slide 15, RCA regulation, and asked if the FERC would still have
to regulate the Gas Treatment Plant (GTP) and downstream of
Valdez.
MR. WALKER replied yes, but said AGPA feels comfortable that it
is exempt from FERC regulation on the pipeline and any upstream.
^ Radoslav Shipkoff, Director Greengate LLC
RADOSLAV SHIPKOFF, Director Greengate LLC, added that there will
be components downstream of Valdez that will be regulated by
FERC; but AGPA will not be dealing with them. Those who will be
implementing the downstream components are already working
through the FERC process. The regas terminal in Mexico is
subject to Mexican regulation and Sempra is already in process
of permitting the expansion. The takeaway pipeline downstream of
the regas terminal, which will take gas from Costa Azul through
Mexico and into Southern California, will be regulated on the
Mexican side by Mexico, and on the U.S. side by FERC. But those
expansions and incremental infrastructure will occur whether or
not Alaska's gas is going through it, so the timeline is already
in motion.
CHAIR SEEKINS asked if the upstream GTP is subject to the FERC
permitting process.
MR. SHIPKOFF answered that AGPA believes it has many
opportunities to help the producers and, if there were a benefit
to owning the conditioning plant, which would compress the
timeframe for them, it would consider that.
9:56:47 AM
CHAIR SEEKINS clarified that he was asking about the timeframe
for permitting. The FERC said their time clock is set at 48
months or more.
MR. SHIPKOFF responded that, if the Port Authority owned the
conditioning plant, the timeframe could be compressed.
CHAIR SEEKINS asked why it would be compressed.
MR. SHIPKOFF answered that it would avoid the FERC process.
CHAIR SEEKINS said it looks like there would be a fight with
FERC over that. The FERC representatives told the committee that
it is not going to ignore one of the biggest gas projects in the
United States; it will want to control it. He asked how certain
Mr. Shipkoff is that the Port Authority could avoid the FERC
process.
MR. WALKER replied that most of AGPA's communication on this
issue has been with the Department of Energy (DOE). He believes
the issue will be resolved relatively soon; but AGPA has told
the FERC that it is not looking for a fight and will work with
them to avoid delays.
9:58:46 AM
CHAIR SEEKINS said he is trying to relate that to testimony by
FERC. They look forward to regulating the downstream and
upstream, even if the midstream is not under their jurisdiction.
It sounds as if they want to control the midstream too, so there
is a question about whether AGPA can do what it says it can.
9:59:40 AM
MAYOR WHITAKER said that AGPA's discussions with FERC were
fairly straightforward and it was clear that their goal is to
see a project move forward. FERC's closing comments were that,
when Alaska decides what it wants to do, it would be ready to
decide how to proceed.
10:00:26 AM
SENATOR WAGONER said that there is a lot of doubt about what
ConocoPhillips will do with their LNG plant on the Peninsula.
Production is decreasing and it may not have enough gas to
continue operations past 2009. The state has been talking about
building lines to Southcentral Alaska, conditioning the gas in a
straddle plant, and shipping liquids and gas to the Peninsula to
serve Southcentral. He asked if the Port Authority has looked at
the feasibility of doing something like that for their LNG
project using the existing plant, which could double in capacity
from 250 Mcf to 500 Mcf per day. The state could continue to
ship its gas to Japan and bring Sokolin gas in to the West
Coast. It would be a win-win situation for Alaska. A number of
legislators are going to start insisting that the state look at
processing gas liquids in the state, as that is where the jobs
are.
10:03:02 AM
MR. WALKER said that Senator Wagoner raised a very good
question, and one that AGPA has addressed in its efforts since
1999 in numerous discussions with ConocoPhillips about buying
gas. It believes that the spur line from Glennallen to the MatSu
Valley and tied into the south-central grid, which has a
conditional right-of-way permit from the state of Alaska through
ANGDA, can move gas south. Right now, gas moves north from the
Kenai/Nikiski area. It has also looked at the TAPS preferred
route through central Alaska from Fairbanks south to Anchorage,
but that was not permitted. The same route was attempted for the
gas pipeline, but thirty-two state and federal agencies said no,
it must run parallel to the Transalaska Pipeline. AGPA feels it
is prudent to maintain the permitted route and make sure gas is
available to that facility. Many people forget that Alaska
pioneered the LNG technology in 1969; so bringing gas to
Southcentral sooner is desirable to keep that industry going and
expand it. To divert everything in that direction and bypass the
permitted terminal site however, would not be taking advantage
of the time factor involved in what has been done to date.
MR. SHIPKOFF said that in previous presentations AGPA has shown
cases that include the assumption of up to 500 Mmcf/d going via
the Glennallen spur line in the direction of Southcentral. The
500 Mmcf/d assumption included the 200 or so that could extend
the life of the Kenai plant, so AGPA has certainly looked at
that option. It is incremental gas that helps amortize the cost
of the main line to Valdez and potentially benefits
ConocoPhillips because it extends the life of their facility.
The reason it was not included in the numbers presented to the
committee three weeks ago, is that the opportunity is not
concrete and AGPA did not want to base its economics on 200 Mmcf
that might not materialize.
10:06:36 AM
MAYOR WHITAKER agreed that Senator Wagoner's question is a good
one, and emphasized that it is central to the Port Authority's
mission to get gas to Southcentral. AGPA has talked to Agrium
Inc. extensively and is still trying to determine how to meet
their needs; but this is a linear process and before it can
write a business plan to meet Agrium's need or ConocoPhillips',
it has to have a gas supply.
10:08:43 AM
SENATOR THERRIAULT commented on the importance of preserving the
jobs in Kenai, and asked about the potential for new jobs
related to gas liquids. He asked if AGPA's proposal
predetermines where plants could or would be built along line or
in Southcentral. [Parts of testimony were indiscernible.]
10:09:54 AM
MR. WALKER replied no, it does not, but if there is no gas, or
if the liquids are bound for Alberta, there is no sense talking
about a petrochemical industry in Alaska.
CHAIR SEEKINS asked Mr. Walker if AGPA's project anticipates
buying the gas, or just transporting it.
MR. WALKER responded that AGPA is very flexible and would do it
either way.
CHAIR SEEKINS commented that he believes gas liquids could be
sold anywhere and the state would own a certain percentage of
those liquids. He asked if the Port Authority representatives
know of any pre-arrangement by which the liquids would go to
Canada.
MR. WALKER said he only knows that the premier of Alberta said
the liquids from Alaska would be Alberta's "pound of flesh" for
an Alaska pipeline. He pointed out that, if there isn't a spur
line to Southcentral, he does not know how the state would get
the liquids down there to be utilized.
CHAIR SEEKINS said that Senator Wagoner made it very clear to
the energy people in Alberta that the state of Alaska is looking
at getting those liquids processed here. At a recent meeting of
the Pacific NorthWest Economic Region (PNWER) in Edmonton,
Alberta indicated that it expected the liquids to come there
because Alaska does not have existing facilities; but the
legislators could not find any agreement to that effect. He
emphasized that many legislators are interested in making sure
those facilities are built in Alaska, to provide jobs for
Alaskans.
10:14:42 AM
MAYOR WHITAKER said that in an uninterrupted market chain, the
notion that the liquids would be available to whoever wanted to
purchase them would be true, but given that the sponsors have
vested interests in the petrochemical industry in Alberta, the
state needs to be worried. That is not to criticize the sponsors
for doing what is in their best interests; but the mission of
the legislature and the Port Authority is to do what is in the
state's best interests. AGPA has an interest in keeping as much
of that value as possible in Alaska.
CHAIR SEEKINS agreed that the legislators do too, especially
those from the interior and probably from Southcentral as well.
10:16:06 AM
REPRESENTATIVE SAMUELS said that to buy the gas and to ship it
are completely different ideas. The state bears all of the risk
in the first scenario, but is simply running a public utility in
the second. He felt that, for the Port Authority to say they
would either buy it or ship it seemed unrealistic.
10:17:06 AM
MR. SHIPKOFF agreed that the risk allocation of a purchase and a
shipping arrangement are different. The first order of priority
in evaluating a project is to determine whether the budget makes
commercial sense for all parties and whether it is economic; how
the risk is then allocated is the second order of priority and
AGPA is willing to have the appropriate discussions with the
producers about that. It believes that its numbers show the
project generates sufficient revenues to accommodate different
commercial arrangements, but it is not at the point of having
commercial discussions. The state first has to determine that
the project is economic.
CHAIR SEEKINS said that, at this point, it is a study, not a
project.
MR. SHIPKOFF countered that it is more than a study; it is ready
to proceed when they have discussions about gas supply.
MR. WALKER confirmed that that they do view it as a project.
10:19:05 AM
SENATOR THERRIAULT asked a question about the economics of a
pipe sized to accommodate additional capacity. [indiscern.]
MR. SHIPKOFF said that whether the LNG project can support
itself if it proceeds with a pipeline that is sized to
accommodate a Y-line expansion or a highway project in the
future, and then those projects do not proceed, is a very good
question. Three years ago the answer was no; it could not carry
the extra expense given prices at that time. Today, economics
are strong. Of course, there would have to be a reasonable
certainty that extra gas would be coming within a specific
timeframe before negotiating tariffs and final engineering.
10:21:47 AM
REPRESENTATIVE SAMUELS expressed concerned about the state's
risk profile in a gas-purchase situation and said that he does
not buy the argument that these are just commercial discussions.
He pointed out that the state carries all the risk if it buys
gas and, if the market price drops below the purchase price, it
could face a huge loss.
MR. SHIPKOFF responded that it is important to recognize just
what is meant by "purchase agreement." The specifics of the
netback purchase agreement AGPA proposed under the April 2005
purchase offer to the producers and the state, does not commit
the midstream entity to a firm price obligation, so it is not
taking price risks. Basically, the producers are committing to
supply the gas. The midstream entity, which would be funded on a
non-recourse basis post-completion, is taking the risk that the
gas will be shipped, and the producers on the North Slope get
the differential between market price and the cost of
transporting the gas through the infrastructure. If the price of
gas were $2.00 and the state's cost were $3.00, the producers
would stop producing because they could not afford to continue;
and the investors who built and financed that line would absorb
the difference, which has to be paid to amortize the capital of
the midstream infrastructure. The question is whether AGPA can
convince the investors that the possibility of such a scenario
is very remote. He thinks the view in the marketplace is good
enough to make that argument convincing.
CHAIR SEEKINS asked if he anticipates shipper-paid contracts.
10:25:55 AM
MR. SHIPKOFF replied that he does not know yet, that AGPA is
willing to enter into negotiations that would result in the most
beneficial arrangement between it and the producers.
At ease from 10:26:21 AM to 10:40:32 AM
CHAIR SEEKINS called the meeting to order.
MR. WALKER said that, before he went on to the next bullet-
point, he wanted to clarify an important point in response to
the last question raised about risk to the state from the Port
Authority Project. Alaska statutes are clear that the risk and
obligations of the Port Authority do not transfer to the state
or to any of the municipalities that are members of AGPA. In
addition, He believes the federal loan guarantee is non-
recourse.
CHAIR SEEKINS said that the unanswered question is what the
requirements will be for the loan guarantee.
MR. WALKER agreed.
MR. SHIPKOFF confirmed that DOE has not implemented any specific
process yet, partly because parties in Alaska asked them not to
implement any regulations before it completed its plans. So, DOE
is waiting for something to come out of Alaska before finalizing
the regulatory and implementation process.
10:42:37 AM
CHAIR SEEKINS asked what amount would be covered by the loan
guarantee.
MR. SHIPKOFF replied that it would cover 80 percent of the
project cost, up to a cap of $18 billion total.
CHAIR SEEKINS asked how much he estimated the AGPA project would
cost.
MR. SHIPKOFF answered that it depends on the configuration, but
if it is sized to accommodate a future highway project, it could
be $5-$6 billion plus another $1.5 billion for the LNG plant,
and from $700 million to $2 billion GTP.
CHAIR SEEKINS said that he thought the AGPA project would feed
primarily off Point Thomson, and asked if it is now looking at
Prudhoe Bay.
MR. SHIPKOFF said that they were asked to analyze a case in
which only Point Thomson was made available to the project; but
if only 1.2 Bcf is coming off the North Slope, it makes more
sense to take it from Prudhoe Bay, which is already fully
developed.
10:44:21 AM
CHAIR SEEKINS asked whether the projected source is now Prudhoe
Bay rather than Point Thomson.
MR. SHIPKOFF replied that they can't entirely control where the
gas comes from, so they are forced to look at a range of
possibilities including both Prudhoe Bay and Point Thomson.
CHAIR SEEKINS asked whether the GTP would be $750 million
instead of the $2.6 billion the committee heard about in
previous discussions.
MR. SHIPKOFF answered that the GTP is fairly linear and modular,
so they just scaled it down.
CHAIR SEEKINS asked whether there would be any loan guarantees
available after this project.
MR. SHIPKOFF responded that this would use only about half of
what is available.
CHAIR SEEKINS asked if the federal loan guarantee is a multi-
project commitment.
MR. WALKER replied that he is not sure how the federal
government will view it. The specific language reads that only
one guarantee will be awarded, but they believe it could be
viewed as a piece of a larger project. He stressed that
ExxonMobil openly opposed the loan guarantee however, so he is
not sure that it is an issue for their project.
10:46:23 AM
MR. SHIPKOFF added that there are many precedents in the
financing marketplace, in which large scale projects pre-
negotiate expansion with the lenders during the initial phase,
and that AGPA intends to address that with DOE at the outset.
CHAIR SEEKINS commented that it is still an unanswered question.
MR. SHIPKOFF agreed that negotiation has yet to occur.
10:47:33 AM
CHAIR SEEKINS prefaced his question by saying that, regarding
the federal loan guarantees, he assumed that it would be very
difficult for anyone to get financing for a project this large
without shipper-paid contracts. He asked if Mr. Shipkoff was
saying they would not be necessary.
MR. SHIPKOFF explained that the loan guarantee would only
protect the lenders that are funding under it, not DOE; so, DOE
will have to be convinced that it is a sound investment. Many of
the LNG projects have U.S. Export-Import Bank participation,
which is basically the same thing.
10:48:44 AM
MR. SHIPKOFF continued that firm shipper-pay commitments are
certainly a commonly accepted way to provide security and
reasonable certainty of revenue to midstream lenders, but it is
not the only way. They will accept an alternative arrangement if
the economics are strong enough, and AGPA believes they are.
10:49:39 AM
CHAIR SEEKINS asked Mr. Shipkoff if he thinks the DOE would
provide the loan guarantees without shipper-paid commitments.
MR. SHIPKOFF responded that he cannot answer that if he does not
know what the rest of the picture looks like; but if there is a
strong contractual and commercial structure, which mitigates the
risk properly, the answer is yes.
10:50:05 AM
SENATOR DONNY OLSON joined the discussion from Anchorage.
10:51:24 AM
MR. WALKER continued with the seventh bullet-point on slide 15.
He said that AGPA believes the larger the footprint of this
project in Alaska, the better it is for the state. If one
considers only the construction jobs associated with the
pipeline, the Port Authority project and the Sponsors' project
are comparable; but AGPA is looking at the operations,
maintenance, and spin-off industries as well. One of the driving
forces behind AGPA in this project is to maximize the instate
use of the gas liquids, which are the "feedstock" for a
petrochemical industry in Alaska.
He said that the last slide is a list of what has been
accomplished to date and what still needs to be done. In brief,
AGPA was established by a public vote, received an IRS ruling of
exemption from federal income taxes, obtained firm project cost
estimates from Bechtel, structured the project to accommodate
in-state needs through the ANGDA spur line, secured an exclusive
option on YPC permits and data, worked with marketing interests
in North America for LNG out of Alaska, obtained MOU's with
Jones Act compliant shippers, performed financial modeling,
submitted a formal offer to the producers to purchase Alaska
North Slope (ANS) gas, and continue to address changes in the
North American and export markets. What remains to be done is to
acquire commitments for gas supply.
10:55:24 AM
SENATOR WAGONER asked Mr. Walker if he had a breakdown of
pipeline maintenance and LNG jobs.
MR. WALKER replied yes, that he would get that list to him.
MR. SHIPKOFF brought slides showing some of the key themes from
his presentation in Juneau three weeks earlier. He said that he
would not go into the same detail he did at that time, but that
he did bring the detailed slides with him in case anyone has
questions that are not covered in today's presentation.
Before beginning the presentation, Mr. Shipkoff elaborated on a
comment made by Mr. Walker, that they have heard comments that
the Port Authority project keeps changing. He believes that AGPA
has been very consistent in the project it is proposing. It has
also been very diligent in optimizing its project and responding
to changes in circumstances, as any responsible developer would
do. The fundamental project has not changed. It proposes to
transport gas from Prudhoe Bay to Valdez through a pipeline
parallel to TAPS, to liquefy it, and send it to market. The
market plan has changed since 2000, because the better market is
now on the West Coast.
10:58:27 AM
He stressed that AGPA is not proposing a Y-line project; it is
proposing an LNG project that enables the producers to develop
their highway project via a Y-line expansion. The Y-line is not
AGPA's project. He said it is important to know that they view
the LNG project as incremental to, not competing with, the
highway project.
11:00:09 AM
MR. SHIPKOFF directed the committee's attention to his first
slide, which shows that AGPA's project proposes a minimum
initially of 1.2 Bcf on the North Slope, for about 1.1 Bcf of
LNG going to the West Coast after fuel and consumption. The
large stylized representation of the pipeline from Prudhoe Bay
to Delta Junction is intended to illustrate that it will be
sized to accommodate a future highway project. The highway
project has been described as a project that takes 4.3 Bcf on
the North Slope and transports it to Canada. If you add that 4.3
to this project's 1.2, it is 5.5 Bcf on the North Slope, so AGPA
believes it adds an incremental value.
MR. SHIPKOFF commented that some have suggested that a Y-line
worsens the economics of the highway project because some volume
is taken away from the pieces that are not shared, and therefore
the highway project loses its economy of scale. That is only
correct if the assumption is that the same amount of volume is
taken on the North Slope and is then split in two separate
directions. It is true that, under that scenario, the pieces of
the highway project that are not shared would have some
diseconomies of scale; but there is no reason that the project
has to take 4.3 on the North Slope. There is no magic to that
number; it happens to be the number that optimizes their
economics. If 4.3 is the optimal volume of gas to go down the
highway, that can be done. It is not clear how 4.3 could be
limited by reserves, given that a 4.3 project as proposed
currently under the contract, needs 50 Tcf. That is 15 Tcf more
than what is currently known to exist on the North Slope, so if
it is premised on an additional 15 Tcf as yet undiscovered, the
question is whether exactly that amount will be discovered. If
the discovery is higher than 15 Tcf, it means a larger project
than the 4.3 highway project could be implemented over 30 years.
If it is less than that, the highway project as currently
proposed does not work, and the economies of scale laid out in
the fiscal findings no longer exist.
11:03:12 AM
He said that AGPA believes the scenario that was evaluated under
the fiscal interest findings, which was a Y-line taking 4.3 on
the North Slope and splitting it two ways, was flawed, not only
because the fiscal interest findings ignored AGPA's cost
assumptions and seemed to arbitrarily increase them, but because
that case does not necessarily make sense. If 4.3 is the optimal
amount that should go to Canada, exploration results in exactly
15 Bcf of reserves, and the reserves are limited to 50 Tcf as
assumed under the highway project, 4.3 can still go down to
Canada by shortening the life of the project. If the objective
is to use the same reserve space, one can compare the two
projects on a 50 Tcf basis and simply look at what happens if
the LNG project goes first. Assuming it goes for 30 years and
needs 13.5 Tcf, then the highway project might need up to an
additional 35.9 Tcf to total 49.4 with a life of 22 years. If
there is more than 15 Tcf discovered, for a total of 63, which
is the scenario we presented 3 weeks ago, the highway project
can proceed with 4.3 for the entire 30 years and the full
economies of scale will be achieved on the shared components.
11:05:24 AM
MR. SHIPKOFF said it is important to recognize that if
infrastructure for the highway project is amortized over a
shorter time than 30 yrs, the incremental cost will go up.
However, on a net present value (NPV) basis, AGPA's numbers show
that the increase in cost associated with shortening the life
from 30 to 22 years still puts the total present value (TPV)
generated by the producers at a significantly higher level than
it would have been if the highway project was implemented on its
own. From AGPA's perspective, the question isn't how much volume
the highway project sends to Canada, it is whether the LNG
project can support itself if the highway project doesn't come
to fruition, and the answer is yes.
11:07:06 AM
MR. SHIPKOFF said that, if the highway project is implemented
and starts operating in 2016, the netback jumps up significantly
over what is projected for LNG only, starting from $2.00 and
increasing from there. On a real basis, the netback in 2012 is a
little below $2.00, increasing over time. The assumption is
$5.50 Henry Hub (HH), with a $.50 basis in Southern California
(SoCal). The netback increases, even on a real basis, because
levelized nominal tariffs decline in real terms over time.
He displayed a slide showing the NPV associated with several
configurations of an LNG project and a subsequent highway
project, or a highway project that is implemented at the same
time. The LNG project on its own, starting in 2013, generates a
significant present value to the producers, assuming 12 percent
discount rate in the upstream. The highway project on its own
generates approximately $11 billion. If the Y-line is
implemented with an LNG project starting in 2012 and assuming a
30-year project life, then a highway line is implemented
assuming 4.3 Bcf to Canada, the project life on the highway
component is shortened so that the total amount it produces is
49 Tcf, and the value increases to $12 billion. If there are
future discoveries in addition to the 15 Tcf that is necessary
to bring the reserves up from 35 to 50, the value is closer to
$13 billion.
MR. SHIPKOFF explained that, even if both projects are
implemented simultaneously, the present value is higher than the
highway project.
11:10:24 AM
He said that that this picture is mirrored by the returns to the
state. The LNG project generates approximately $5 billion of
present value to the state. The Y-line generates about $18
billion at 49 Tcf, and about $22 billion at 63 Tcf. The Y-line
project, even if the LNG component is delayed until 2016,
generates a higher value than the highway project alone.
11:11:23 AM
MR. SHIPKOFF said that some have questioned whether 5.5 would be
too much gas to the market, and whether 1.2 can be absorbed on
the West Coast. AGPA believes that the total gas to market is
likely to be same under any of the scenarios it has looked at;
But Alaska would get the largest share under the implementation
of an LNG project first, to be followed by the highway line.
He went on to the next slide, showing potential supplies from
discreet sources to the North American market. The west coast
would receive more that 1.5 Bcf, but he has used that figure
because it is the unsubscribed capacity announced by Sempra for
the expansion. The highway project can deliver 4.2 to Canada or
the Midwest starting in 2016 or later. There will be 1.5 Bcf
going to the West Coast. In the highway project, that 1.5 will
be supplied from elsewhere, so the total between what is coming
in via Costa Azul and what is coming in from Alaska will be 5.7.
AGPA proposes that 1.1 go to the West Coast starting in 2012. An
additional 400 Mmcf/d will be filled from foreign energy
suppliers, and the highway project can still deliver its 4.2 to
Canada and the Midwest.
11:14:18 AM
MR. SHIPKOFF reminded the committee that it is possible that the
highway project might never be implemented, in which case there
would still be 1.5 of foreign LNG coming to the West Coast, and
the 4.2 would have to come from somewhere on the Gulf Coast.
[indiscern.]
He commented that the independent producers have expressed
concern that the provisions for open season and expansions under
the contract are not sufficient. If there is some uncertainty
whether pipeline capacity will be available, it might discourage
explorers from investing. Having a pipeline that is sized for
expansion downstream will serve as an exploration incentive, and
if the pipeline can pay for itself, it isn't a problem to have a
pipe that is partly empty for a few years. [indiscern.] Early
implementation of an LNG project will make a highway project
more likely. [indiscern.] The reverse is not true, because if
the LNG project has to wait for the highway project to be
implemented, there might no longer be a market for the gas.
[indiscern.]
11:17:04 AM
MR. SHIPKOFF said that the LNG project gives Alaska the
opportunity to access markets that will not be accessible to the
highway project. Once the pipeline is built and the LNG
facilities are constructed in the way that enables expansion, it
enables Alaska to capture additional markets such as Japan and
East Asia.
11:18:08 AM
He said that he wanted to finally address a question that the
Port Authority often hears, which is: If you have such a good
project and it's bringing all this incremental value to the
producers, why aren't the producers coming to you. He feels it
is a legitimate question and, while AGPA may have missed
something or be wrong in its calculations, he does not think
that is true; he has confidence in the analysis and would
welcome the opportunity to sit down with the producers and
discuss it. He believes that when the producers are ready to
seriously consider a project, they will implement an LNG project
because the value is there. The state simply has to be in a
position to prioritize an Alaskan project, and it isn't yet. the
contract does not create the conditions that prioritize the
project.
11:19:16 AM
REPRESENTATIVE KELLY prefaced his question by saying that, since
the legislature met with AGPA in Juneau, there has been a
significant change in the political picture and, while the
legislature has been at the table negotiating the agreement, gas
and oil prices have increased dramatically. People are skeptical
that the current governor and the legislature can complete a
contract and get legislative approval within 100 days. He asked
if the legislature needs to start over on several major issues
associated with the gasline contract, due to the price
increases.
11:22:38 AM
He also wanted to know what AGPA recommends with regard to this
project, assuming the legislature recognizes that the gas is
less stranded due to market price and still wants to move
forward.
11:23:02 AM
MAYOR WHITAKER replied that it is appropriate to "hit the reset
button". It is clear that the people of Alaska think so too. The
Port Authority has been prepared to compete from beginning, and
to present a project that is in the best interest of Alaska.
AGPA will continue to do what it is doing and is willing to
engage with the legislature and any new administration to get
this done.
11:24:20 AM
CHAIR SEEKINS asked Mr. Whittaker whether he is correct in
assuming that the AGPA proposal doesn't depend on the SGDA.
MAYOR WHITAKER answered that it does not.
REPRESENTATIVE KELLY wanted to clarify that the delay resulting
from the end of the special session and the change in
administration will not cause any change in direction as far as
the Port Authority is concerned.
MAYOR WHITAKER said it would not.
11:24:54 AM
CHAIR SEEKINS asked for other questions before transitioning to
the Econ One presentation.
SENATOR THERRIAULT commented that the presentation was mailed to
the participants who are attending via teleconference.
At ease from 11:25:48 AM to 11:37:19 AM
CHAIR SEEKINS introduced Dr. Finizza
^ ECON ONE ANALYSIS OF THE PORT AUTHORITY PROPOSAL
^ Dr. Tony Finizza, Consultant to Econ One Research Inc
DR. TONY FINIZZA, Consultant to Econ One Research Inc., provided
a brief background of his qualifications and an overview of
today's presentation. He has had industry experience and worked
at Atlantic Richfield until he retired in 1992. He currently
does consulting work in the energy area and teaches energy
economics, industrial organization, and business work ethic at
the University of California, Irvine. He said he would be
presenting an analysis of the Port Authority project and would
discuss the financial metrics he intended to use, his use of the
AGPA model in this work, key drivers, results, sensitivities,
and recommendations.
11:39:38 AM
DR. FINIZZA said that he would address the project economic,
compare alternatives, and look at the timing, as it is obvious
that the Port Authority's work is driven in part by its ability
to monetize natural gas sooner. His comparisons will use
existing projects of a similar size in terms of reserves and net
present value.
DR. FINIZZA started on page 12, showing that the appropriate
financial criteria is net present value (NPV) of future cash
flows. It is a way of determining whether the project would add
value to a firm, and these cash flows would be discounted at a
rate that represents the uncertainty of the cash flows. He noted
that Econ One used a different discount rate than AGPA, but it
is the same one they have used in all of their other work, and
the same one that the other analysts have used. Finance theory
holds that, if NPV is positive, the project adds value to a firm
and is a project that should be done.
11:43:38 AM
He explained that internal rate of return (IRR) isn't
particularly helpful, so he would not go into that. He moved on
to page 18, Financial Metrics Used, and reiterated that he would
be using NPV to evaluate the economic merits of the project.
[static or wind noise]
He went on to say that he used the Port Authority's model for
his analysis. Mr. Shipkoff and Mr. Walker briefed him on the
plan after the August presentation and offered the model to Econ
One for analysis. He determined that it was a sound model for
what he was doing, and was then able to argue on the basis of
assumptions rather than the model. His first step was to
benchmark their model by the highway project, so he had to
change some key assumptions, including discount rates, inflation
rate, profile of capital expenditures, upstream capital,
severance and royalty rates, effective SIT rate, and liquids
value in Asia.
11:47:52 AM
DR. FINIZZA pointed out that slide 22 is slightly different from
the copy on page 22 in the packet provided to the committee. By
using the common assumptions on gas and oil price, the basis
differentials between AECO [Natural Gas Exchange] and Henry Hub,
changing all the discount rates and inflation to what is listed
on page 19, using 2005 fiscal terms, and using the capital cost
assumptions in the AGPA work in Econ One's model, he found that
the NPV was virtually the same for analysis of the AGPA project
and a highway line. The state revenues are very close and
royalty values are virtually the same. Based on this match, he
felt he could use AGPA's model with Econ One's assumptions.
11:49:50 AM
SENATOR THERRIAULT corrected information on page 20. In the Econ
One column, net revenues are shown as 14,890, but should read
15,259.
11:50:17 AM
DR. FINIZZA touched on page 22, the key drivers of the economic
value that will feed into the assumptions. [Parts of the
testimony were indiscernible.] Econ One had to make assumptions
about commodity value, the benchmark for North American gas, and
basis differentials in the two market places, AECO and Southern
California. It also had to make a call on oil, because there is
great potential for liquid petroleum gas being extracted from
the gas stream, and there is a difference between where the LPG
is projected to go under the AGPA project and AECO. The second
set of key drivers listed on that page includes capital costs,
natural gas resource rate, and the timing of projects.
REPRESENTATIVE KELLY commented that Dr. Finizza had said
unconventional natural gas pricing will be the benchmark for the
key driver, not LNG, and asked if Dr. Finizza could relate that
to the hurry Alaska is in.
DR. FINIZZA responded that he would talk about that later.
[Additional discussion between Representative Kelly and Dr.
Finizza was broken up and partly obscured by background noise.]
11:55:19 AM
DR. FINIZZA went on to page 23, which is a picture taken from
the annual energy outlook of the Department of Energy, Energy
Information Administration. It illustrates the importance of
Alaskan gas and LNG in the demand mix that is needed for the
next 20-30 years in the United States. Alaska is projected to be
about 6.5 percent of the total gas; LNG is expected to be even
larger.
11:56:04 AM
He turned to page 24, a bar chart representing assumptions about
gas prices, and explained that P20 indicates there is only a 20
percent chance prices would average below that figure over the
time period in question; P80 indicates that there is an 80
percent chance that prices would average below that figure over
the same time period.
He noted that it is important to recognize that people who are
developing projects will always try to test a stress price at
which they don't expect to get very high returns, but do expect
some economic return. They don't want a negative NPV at that
lower price.
11:58:36 AM
DR. FINIZZA said that, once he had information about the market-
setting price Henry Hub, he also had to make assumptions about
the price differential in other markets. Page 25 illustrates
basis differentials on gas around the country, Henry Hub,
Alberta, Chicago, and Southern California. The assumption Econ
one used in its highway analysis is that the AECO differential
is $.90 below Chicago and Henry Hub. So whatever the Henry Hub
price is, the price that the market would give Alaska gas going
to Alberta is $.90 lower. The differential in the Southern
California market would be $.50 lower than Henry Hub. Page 26
shows that price average at $.58, but it is quite volatile.
He turned to page 27, which shows the ratio of West Texas
Intermediate (WTI) to HH spot prices over time, and noted that
there is a lot of volatility. The average over the 5-year period
2001-2005 was roughly 7:1. The AGPA analysis used 6.55, which is
close enough, so he used that assumption in this work.
12:01:27 PM
DR. FINIZZA said that both gas streams will have the advantage
of an uplift from extracting liquids plus propane and butane,
and could expect some extraction of ethane, but only included
the potential for extracting propane and butane in this
analysis. Different assumptions will be used for propane
extracted in Canada vs. Japan. On page 28, the top line
illustrates that the average differential propane price is
relative to a basing point, Mont Belview or Japan. It averages
roughly $.05 per gallon. The lower line is the comparable ratio
difference between propane prices in Alberta, and is -$.05, so
the difference between one and the other is roughly $.10. That
means that, if you could bring propane to Japan, you would
obviously get a greater value there.
CHAIR SEEKINS asked where Mont Belvieu is.
12:03:26 PM
DR. FINIZZA answered Texas. He said he also had to do the
comparison for Butane, which has a higher economic value than
propane. The picture on page 29 shows the ratio of butane to
propane. Alberta averages about $.10 and Japan about $.083.
12:04:14 PM
He said that page 30 shows some stylized supply and demand
curves, with the first reflecting conditions today. There is a
small amount of LNG coming in, which can be brought in cheaper
than most gas, then there is a large amount of conventional gas
that is still below the market price, and then much higher cost
unconventional gas, which is what he believes is setting the
price of natural gas in today's market.
12:05:24 PM
DR. FINIZZA fast-forwarded to Page 31, showing conditions in the
year 2020. He would expect more natural gas to be coming into
the gulf coast mainly, and expects a greater demand. The demand
shift is possibly a little less than the incremental LNG that
was brought in over this time period, so higher costs and
unconventional gas are still setting the market. He created this
schematic to illustrate how much LNG would have to be brought in
to get this intersection of supply and demand out of the higher
cost and unconventional gas area. Given these demand conditions,
he does not believe there would be enough LNG to push it that
way.
12:06:41 PM
He proceeded to page 32 and commented that it is possible that
the price of natural gas will be lower with all of the natural
gas coming in, but it will be a small change.
12:07:20 PM
CHAIR SEEKINS said the committee would recess and reconvene at
1:20 pm.
Recess 12:07:43 PM to 1:37:04 PM
DR. FINIZZA said that page 33 summarizes the key pricing
assumptions and, with the exception of uplift value expected for
propane in Japan, AGPA's assumptions and Econ One's are very
much in accord. He commented that another important assumption
to include here is the capital costs, as shown on page 34. In
the pipeline segment from Alaska to the Yukon, the assumption is
for higher capital costs than in the original producers' study,
which seems appropriate given the price increase that was
expected from the escalation of component prices of the pipeline
since the producers' study was done. This came from work that
Bechtel did for AGPA. The pipeline from Yukon to Alberta is also
higher than the producers' study and is derived by taking the
ratio 5100:5900 used in the producers' study, and applying the
same thing to the various pipeline segments from Alaska to
Alberta. In other words, there was no independent calculation of
the Yukon to Alberta pipeline; it was just scaled up in
proportion to the higher costs expected from the Alaska portion.
The point here is that, these assumptions are using higher, and
perhaps more realistic, capital cost numbers.
1:40:00 PM
DR. FINIZZA turned to the upstream development numbers on page
35, which he used throughout this work. He assumed that no
capital development would be required on the North Slope, $1.2
billion in capital development for Point Thomson, $870 million
for other ANS, and $400 million over a 12-year span for the
'yet-to-find'.
He reviewed the national supply figures on pages 36-39, which
show that, according to the U.S. Geological Survey (USGS),
Alaska contains 40 percent of the undiscovered U.S. reserves. If
only the unconventional reserves are considered, and USGS only
looks at unconventional reserves for Alaska, it is 25 percent of
the U.S. reserves. Known North Slope reserves are 35 Tcf and,
according to USGS, roughly 120 Tcf is technically recoverable
for a total of 155 Tcf. According to the Alaska Division of Oil
and Gas 2006 report, the 35 Tcf in known reserves breaks down as
24.5 in Prudhoe (23.5 Prudhoe and 1.5 Greater Point McIntire),
8.0 in Point Thomson, and 2.9 in other ANS.
DR. FINIZZA discussed the USGS Assessment of Technically
recoverable gas resources in Alaska on page 40. The mean value
breaks out to about 60 Tcf in the National Petroleum Reserve in
Alaska (NPRA) and 34 on the central North Slope. Page 41 presents
economic reserves on the central North Slope, where it specifies
distribution at a given market price that is backed up by taking
away transportation costs, the fiscal regime, and the cost of
development, to see what is economic. At $5.00 per million BTU
in today's dollars, it shows approximately 20 Tcf just from the
central North Slope that would be economic.
1:45:01 PM
DR. FINIZZA presented various cases that differ by the
configuration, or the type of throughput volume and the starting
year of that segment. For example, the first Y-line indicated on
page 43 is a case that has a total of 4.3 Bcf, 1.2 Bcf LNG and
3.1 Bcf highway volumes. The LNG component is shown starting in
2013, the highway segment in 2016. All of the cases except the
LNG only, end up bringing 49 Tcf to market. In the case of the
LNG only, it assumes that the pipeline from Prudhoe Bay to Delta
Junction is sized for expansion.
He proceeded to page 44 on the economics of the LNG project as a
stand-alone at 1.2 Bcf/d, or 13.5 Tcf over the life of the
project, with start-up in 2013. This case assumes that AGPA
sized the pipe for a future Y-line expansion that did not
materialize. At a fixed dollar base price of $6.00, there is a
positive NPV of about $6 billion NPV10, for producer upstream
net cash flow. The state would get just under $5 billion using
NPV8. These numbers are larger than those shown by Radoslav
Shipkoff, because he was using an NPV12. Testing this at the
downside stress test case of $4.00, there would still be a
positive NPV according to these assumptions.
1:48:29 PM
DR. FINIZZA said that one way of looking at it is, when the NPV
goes to zero for the producer at about $2.92, there is no
economic value to the project. The key feature of the project is
the timing of the LNG piece relative to the part of the project
that goes down the highway after 2016. Page 45 lays out some of
the LNG and highway projects' implied netbacks with and without
the diversion option. It indicates that the LNG segment will
provide a lower netback because of the higher costs related to
LNG; but the project counts on the fact that there would be some
value in LNG from 2013-2015, which more than balances the
averaged-in netback for the rest of the life of the project when
the LNG is holding it back. So, the question becomes whether the
LNG project can get on line in 2013, at least three years before
a highway project. If that is true, it does have economic value.
1:51:14 PM
He moved on to page 46, showing an economic comparison of an
early LNG start-up on three scenarios. The first case shows the
highway line only, starting in 2016 and resulting in an NPV of
$16.5 million. The second shows the Y-line starting in 2013 with
the highway coming on in 2016, and results in an NPV of $17.3
million. The third case shows the Y-line starting in 2016, at
the same time as the highway line, in which case the producer
cash flow and NPV are below either the highway project alone or
the highway and the Y-line starting in 2013. Without that time
advantage, the economic value is lost.
1:53:10 PM
DR. FINIZZA took a moment to explain the diversion option. LNG
prices in Japan are highly correlated with oil prices, largely
due to contractual linkages. The Port Authority identified a
potential option to capture value from the volatility in gas
prices and decided it would be worthwhile to divert cargoes to
Japan when gas prices are high. That option adds about $.50 per
million BTU to the value of the stream. The analysis looks
sound; but it might be imprudent to consider it in the base
case.
1:56:40 PM
He illustrated the economic impact of the diversion option by
pointing out that if the diversion option were included in the
figures on page 46, the second Y-line option, with a start-up of
2016, would produce a better NPV than the highway line alone.
Moving on to page 49, Dr. Finizza showed the economic impact of
more rapid production on the highway line. This analysis shows
two Y-line options, one assuming that the highway volume starts
at 3.1 Bcf/d and is added to the Y-line's 1.2 Bcf/d; the other
assuming that the highway volume starts up at 4.3 Bcf/d and is
added to the Y-line's 1.2 Bcf/d. Both options assume that the
project is over as soon as total gas reaches 49 Tcf. In both
cases, the NPV is higher than the highway line alone.
1:59:08 PM
REPRESENTATIVE SAMUELS asked if Dr. Finizza ran an analysis
assuming 5.5 Bcf/d from the highway line.
DR. FINIZZA replied no, because he could not figure out how he
could add to the capital. He knows the highway line has
expansion capabilities and that it could be done, but he has not
figured it out.
2:00:04 PM
REPRESENTATIVE KELLY asked if, since it doesn't involve looping
up to 6 Bcf, it would have favorable economics with compression.
DR. FINIZZA replied that it might show favorable economics, but
he would be concerned about what it would do to the field and
what the resources look like.
REPRESENTATIVE SAMUELS asked about the first Y-line case on page
49, that shows 1.2 LNG and 3.1 from the highway. He said he
believes TransCanada testified that their economics fell apart
below 3.5 Bcf/d on the highway; so, if the field cannot support
more than 4.3 and 1.2 goes into LNG in 2013, it could result in
a quarter of the gas and a higher tariff, preventing the 3.1
highway line from going forward until more gas is available.
DR. FINIZZA responded that he is not sure he understands
Representative Samuels' question.
REPRESENTATIVE SAMUELS replied that, if 3.1 is not an economic
number and the field will not support 5.5, the 1.2 LNG project
is all you'll get until more gas is discovered.
DR. FINIZZA answered that Representative Samuels had identified
a risk that he hasn't actually looked at, but that might be
worth pursuing.
He directed the committee to page 50 to see how production would
have to look to fill the pipeline. This analysis assumes the
production at Prudhoe and Point Thomson is as expected,
providing 5.5 Bcf/d, and that the additional resource would be
found by the time the highway line is ready to go.
CHAIR SEEKINS asked if that would make the possibility brought
up by Representative Samuels even more onerous.
DR. FINIZZA agreed that there is increased reserve risk with
expanded production.
2:05:47 PM
SENATOR THERRIAULT asked for an explanation of the graph on page
50.
DR. FINIZZA said that this assumes that 5.5 Bcf/d is required
and shows how production would have to be split to support that.
It shows a little over three from Prudhoe Bay, a little over one
from Point Thomson, a little less than one from other ANS
reserves as yet unknown, and about a half from yet-to-find. This
illustrates that the project would have to tap the yet-to-find
sources fairly early.
SENATOR THERRIAULT [indiscern.]
DR. FINIZZA replied that by the time the project life is into
the late 30's, all production would be yet-to-find. In this
scenario, he questions whether the increased reserve risk is
manageable, and what the impact of the faster ramp-up would be
on reservoir economics.
Moving on to page 52, he mentioned that the assumption in the
2000 fiscal findings was that property tax would be based on
capital and, because LNG is more capital-intensive, it would
raise more property tax. He said AGPA had features in their
model that allowed one to look at a throughput based property
tax, but that would result in less property tax.
DR. FINIZZA said that he did a case for increased capital
escalation, but he isn't sure how legitimate it actually is. It
reflects a $2 billion hit on the NPV to the producer upstream
net cash flow.
2:08:54 PM
REPRESENTATIVE KELLY asked how linear the increase would be in
the comparison between the NPV and the percentage on the
increase.
DR. FINIZZA replied that, between the two cases shown on page 53
it is probably pretty linear, but as the midstream capital goes
up, they start to diverge rapidly. Page 54 is a slide he showed
in June, which is included to illustrate the estimated netback
values at the pipeline inlet.
2:11:20 PM
In conclusion, Dr. Finizza said that:
- The highway line of 4.3 Bcf/d has a higher netback than
an LNG project delivering gas to the West Coast.
- The AGPA project does add value if it can bring gas to
market 3 years before the highway line as it proposes to
do; but the advantage disappears if the LNG component is
delayed.
- The project has a diversion option that adds materially
to the LNG netback and is soundly motivated, although it
is imprudent to include it in the base case.
- There is a large gas potential on the North Slope. The
initial expansion will be relatively cheap, but later
expansion would be more costly. An LNG spur or expansion
of the proposed LNG component might be less costly at a
later date.
- An LNG Y-line is economic if gas can be brought to market
significantly before the highway line, and if the cost of
expanding the highway line at a later date is higher than
LNG.
- If the LNG component can be built early as proposed, it
is in the best interest of the producers to do so, and
the current contract is not consistent with this.
2:12:17 PM
DR. FINIZZA mused that those who propose that this plan will not
provide the stated advantage because there will be litigation,
are thinking it isn't in the producers' best interests. He
wondered what they know that AGPA doesn't.
2:13:13 PM
SENATOR THERRIAULT alluded to the TransCanada analysis.
[indiscern.]
DR. FINIZZA asked if they had proposed taking all of existing
Tcf and no additional yet-to-find, for a total of about 3.5.
SENATOR SAMUELS commented that he believes, in the presentation
Mr. Shepler made after the Port Authority spoke in Juneau, he
said that the economics get shaky at around 3.5 and at 3 it just
doesn't work.
2:14:46 PM Recess 2:16:10 PM
MAYOR WHITTAKER said that AGPA met with TransCanada and they
made it very clear that, until Alaska decides what it wants to
do, they are not prepared to say exactly what they will do. They
did say however, that when the proposed pipeline hits Canada, it
is theirs and they own the rights to it. They also said that 3
to 3.5 Bcf/d at the Canadian border is a deal maker for them.
MR. SHIPKOFF said that he thought Dr. Finizza's presentation was
very helpful. He asked the committee to turn to page 19 of Dr.
Finizza's presentation, which highlighted some of the
differences between AGPA's and Econ One's projections. With
respect to the producer upstream discount rate, he pointed out
that they disagree about what is the appropriate discount rate,
but using a higher rate results in lower present values, so AGPA
is being more conservative in its analysis than Econ One. On
upstream capital expenditures, AGPA is not engaged in
discussions with the upstream players and has to rely on what is
available in the public domain, while Econ One has access to
confidential information; so it may have keyed off incorrect
information to arrive at $3.2 million as opposed to Econ One's
$4.8 million. He said he did not think that changing $3.2
million to $4.8 million would affect the relative value of the
results. On state income tax rates, AGPA used 9.4 to set tariff
rates at the midstream level, but at the upstream level it used
4.7 as a proxy for the effective tax rate after the
apportionment factors were taken into account. So, there is very
little difference between Econ One's 3.75 percent SIT rate and
AGPA's 4.7 percent.
2:20:33 PM
MR. SHIPKOFF continued to say that he would address the
differential on East Asia pricing of the uplift from propane
later, in the pricing assumptions.
2:21:17 PM
He said that on page 26, Dr. Finizza's data goes back five years
and shows a historical average of $.58 discount. AGPA took a
similar approach. It looked at the historical data, went back
five years and came up with a $.47 discount. He pointed out that
various publications show historical price data, and they do not
all agree. In either case, these are historical figures and not
projections.
DR. FINIZZA pointed out he was right about $.58, but he used
$.50.
MR. SHIPKOFF next commented that slides 31 and 32 do a very good
job of illustrating that it is irrelevant whether AGPA's project
can compete with foreign LNG at tidewater. It is competitive
with all of the suppliers into the market place.
He reviewed the differences in assumptions shown on slide 33,
commenting that, as Dr. Finizza pointed out, AGPA and Econ One
are essentially in alignment on these items with the exception
of Japan's uplift. He believes there is a conceptual disconnect
if all of the pricing assumptions used in an evaluation except
for one, are based on historical data instead of what the
expectation of the future is going to be. If the analysis is
going to be strictly on the basis of historical data, it should
be consistent throughout. If the analysis is going to use
expected volumes and projected markets, it would be better to
re-evaluate all of the assumptions and engage a firm that
specializes in running North American gas pricing models to run
all of the cases going forward. He said he has a problem with
selectively applying expected data to just one assumption.
2:26:25 PM
CHAIR SEEKINS asked Mr. Shipkoff if AGPA intends to ship 1.1 LPG
to Japan right out of the gate.
MR. SHIPKOFF replied yes. Shipping propane and butane out of
Valdez has strong economics.
SENATOR THERRIAULT asked about the price differential relative
to shipping LPG to Japan. [indiscern.]
DR. FINIZZA said that Mr. Shipkoff is right that this is
somewhat a disconnect from the historical levels of the last
five years, and the view that led Econ One to include this, is
that much of what propane is used for will be replaced by other
commodities such as natural gas itself.
MR. SHIPKOFF said he agrees with the validity of Dr. Finizza's
approach; but that it might be worthwhile to perform the same
exercise for some of the other elements of the assumptions.
2:28:27 PM
He skipped to page 43, which shows various configurations of the
Y-line, the LNG, and the highway project. From AGPA's
perspective, if 4.3 Bcf/d is the volume that makes sense to go
through Canada, there is no reason to reduce it. As Mayor
Whitaker pointed out, the cases that have been presented using a
lower number were formulated in response to discussions in
Juneau last February.
SENATOR WAGONER said that, if the pipeline to Canada is
calculated at 4.3 Bcf/d and 1.1 LNG goes to Delta and only 3.2
or so to Canada, it seems as if Alaska's tariff will increase.
He asked if anyone has calculated Alaska's tariff overall.
MR. SHIPKOFF replied that the 4.3 Bcf/d project going through
Canada is a 30-year project with a requirement of 50 Tcf, which
is 15 Tcf in excess of known resources on the North Slope. So,
existing resources do not drive the 4.3. If the project is
limited to the 35 Tcf currently known, that provides about 3.5
Bcf/d to Canada over 35 years. To get to 4.3 would require
shortening the project life unless other reserves come in. He
believes that the 4.3 Bcf rate is the best rate of flow to
achieve economies of scale.
MR. SHIPKOFF stressed that, although he questions the validity
of the case, even with 1.2 to the LNG segment and only 3.5 going
down the highway to Canada, the present value effect of the
three year differential is better than is provided by the
highway project alone. The loss in netback is more than offset
for both the producers and the state, by the value of generating
some revenue earlier.
DR. FINIZZA said he thinks the roundtable should discuss how the
4.3 Bcf/d line was established. It certainly had to be related
to what Mr. Shipkoff suggested as well as the resource base. He
said he has a feeling it relates to production from the two key
fields where no reserves exist.
SENATOR THERRIAULT asked a question about the volume required
for the highway route. [indiscern.]
MR. SHIPKOFF responded that Senator Therriault is correct. It
appears that the state and the producers would be better off
keeping the volume down the highway line at the same flow rate
and shortening the life of the project, if there is a limit on
the total reserves produced.
2:35:55 PM
REPRESENTATIVE KELLY asked why the producers sized the highway
line at only 4.3 Bcf/d.
CHAIR SEEKINS said they would discuss that during the
roundtable.
MR. SHIPKOFF said that, on slide 43, the analysis does not take
into account that lower volumes going to the same market will
command a higher price, which partially offsets the fact that
the gas is being split out from the highway line to the LNG
segment. Even without taking that into account, assuming the
timing advantage exists, the NPV is better with the Y-line.
He proceeded to slide 45 comparing the netback with and without
the diversion option and pointed out that when the diversion
option is taken into account, the difference between the highway
only segment and the highway with the LNG segment is well within
the 20 percent expected margin of error for calculating all of
these projects. To suggest that one netback is clearly better
than another at this point is disingenuous and is probably
missing part of the picture. From his perspective, netback
potential showing within the tenths of cents instead of dollars
shows that the two projects are a tie.
DR. FINIZZA commented that the inclusion of the diversion option
adds $.50 that is obviously not within the margin of error,
since it is one of AGPA's reasons for doing this project.
SENATOR WAGONER asked what was the volume of the Y-line proposed
by ANGDA to go to Southcentral.
MAYOR WHITTAKER said he believes the discussion was 200-400 Mmcf
per day, but he wasn't sure.
2:42:15 PM
MR. SHIPKOFF commented on the option value and its inclusion in
the analysis (page 47). He said that he agreed with Dr. Finizza
that, when a project is being evaluated on a stand-alone basis
for investment purposes, it makes sense to look at the economics
without a diversion option. He also agreed that, in a downside
scenario, to stress test the economics of the project, one would
not want to include this diversion option. However, he did not
agree that it should not be included in the base case, which is
supposed to be the best estimate, nor does he think it is
accurate when comparing two projects to assign a value of zero
to the option.
He agreed that Dr. Finizza's question of whether the historical
value of this option will hold for the future is a good one.
There is no certainty that the relationship between Japanese LNG
pricing and oil prices will remain the same; it is calculated on
contractual formulas provided for by long-term supply contracts
that expire and have to be renegotiated. The value of the option
does not necessarily derive from the link between Japanese LNG
prices and oil however, but from the lack of correlation between
Japanese and U.S. pricing. Even if Japanese LNG pricing changes
and is no longer linked to oil pricing, it does not necessarily
mean that it will correlate more closely to U.S. prices. As long
as Japanese and U.S. prices do not move together, there is the
opportunity for arbitrage, which is what the value of the option
tries to address. Every LNG project has a diversion option
implicit in it. A more reasonable approach is to include the
option into base case.
2:47:21 PM
SENATOR THERRIAULT asked a question about gas exports.
[indiscern.]
MR. WALKER responded that AGPA has a 25-year export license.
CHAIR SEEKINS said he would be interested to know how many
diversion options have federal guarantees for the loans attached
to them.
MR. SHIPKOFF responded that his understanding is that the
highway project intends to use the loan guarantees fully, and
that a large part of the gas is not going to end up in Alaska,
but in Canada.
CHAIR SEEKINS said that he has been told just the opposite and
would like some information to confirm it one way or the other.
His understanding is that most of the BTU value that goes in at
the northern border with Alaska will be coming out the southern
border from Canada. If that is not true, he hopes it will be
clarified in the round table. Alberta said it doesn't want our
gas for the tar sands [low quality source of hydrocarbons]
because they are using their own plus MacKenzie gas.
SENATOR WAGONER agreed that Alberta said MacKenzie gas would be
their primary source.
2:49:49 PM
MR. WALKER said that they will certainly provide what they have
available. The highest number he has seen in the tar sands
project for gas is 3.7 Bcf. The MacKenzie Valley is projected to
be 1.2 Bcf. The 3.7 is at 3 MMbd and beyond that, it continues
to increase. He said the producers have been building a pipeline
out of the tar sands into the Lower 48 refineries and, based on
comments they've made themselves, their goal is to get the gas
into the tar sands as it feeds off the steam to get the oil out.
CHAIR SEEKINS said that one of the questions brought up to the
Canadians at the Energy Council and at Pacific Northwest
Economic Region (PNWER), is where the gas is going when it
leaves Canada. They anticipate that once it gets to the Canadian
hub, it may not be necessary to build any infrastructure south
of that to get it to the U.S. market, because they expect a
decrease in their exports that would free up space in the
existing infrastructure.
SENATOR WAGONER said that, for every barrel of oil produced out
of the tar sands, they average $3.00 in value of gas to produce
a barrel of oil.
CHAIR SEEKINS reiterated that the Canadian government is telling
him that is not the case.
2:52:51 PM
SENATOR THERRIAULT questioned the BTU value of the gas.
[indiscern.]
CHAIR SEEKINS said that is assuming the gas coming out of Alaska
is going to Alberta. Canada would like to have the gas liquids,
but Senator Wagoner made it clear that Alaska is going to try to
take those out before they get across the Canadian border.
SENATOR THERRIAULT commented on the transportation cost of gas
through Canada and the diversion of molecules of gas from Canada
back to the United States. [indiscern.]
2:53:48 PM
CHAIR SEEKINS responded that he would not object to that, as it
means a larger netback for the people of Alaska, but as he
understands from Alaska's federal delegation, they are planning
on the gas getting to the U.S. and that is one of the reasons
they are offering the loan guarantees.
DR. FINIZZA said that he wonders, in the absence of the Alaskan
gasline, if the volume of gas crossing the Canadian border is
going to be equal to the Alaskan production or not.
CHAIR SEEKINS answered that he thinks they are counting on at
least that number of BTU's, if not the actual molecules, getting
across the border.
2:55:04 PM
MR. SHIPKOFF commented that both the Chair and Senator
Therriault made a good point, which is the difficulty in
assessing where the gas is going, because there is a difference
between physical gas and contractual gas; and once the molecules
enter the Alberta hub, is the state tracking physical molecules,
or BTU displacement.
CHAIR SEEKINS replied that he thinks it would be tracking
volumes.
MR. SHIPKOFF continued that, once those issues come into play,
one has to look at the economic equation, in which it doesn't
matter where the gas goes. The diversion option only arises in
one economic set of circumstances, and that is low prices in the
U.S., which means no gas shortage, and high prices in Japan.
2:56:38 PM
SENATOR WAGONER said he doesn't know what is contained in the
legislation regarding loan guarantees, but he assumes that
getting gas to the lower 48 is part of it.
CHAIR SEEKINS responded that the federal delegation agrees.
MR. SHIPKOFF commented on pages 49-50 regarding depleting gas
reserves. In all of AGPA's model cases, it assumes production
from each field is limited by what the long-term sustainable
rate of production from that field is going to be, as best it
can calculate that figure from available data. When AGPA says it
is increasing production, it is not suggesting that it is
ramping up production from the same field and depleting the
reservoir faster and possibly imprudently. Fields that would
have been developed at a later date are simply brought forward
earlier. There is the same amount of production at the same
rate, but separate investments occur at an earlier date. This is
illustrated by Dr. Finizza's slide 50, where the YTF has to
occur faster. The question then, is whether it increases reserve
risk.
He said that, from his perspective, reserve risk means the risk
to the producer-owner of the project that the reserves will be
different from the expectation. It is important to note that, to
proceed with any of the options under discussion, the 50 Tcf has
to be proven to exist. Investors will not put money into a
project that relies on a 50 Tcf base to pay for itself, before
it is known with a high degree of certainty that 50 Tcf does
exist.
3:00:33 PM
MR. SHIPKOFF said that Dr. Finizza makes an important point on
page 51, that there is a potential for liquid loss. AGPA's model
does not take that into account, because it does not have access
to the appropriate information. Liquids from Point Thomson are
not taken into account for the same reason.
Finally, he pointed out that one of the principal advantages of
the LNG project is, if you look at the overall cost of
transporting the gas from Prudhoe Bay to market, the total cost
of the LNG project is less subject to uncertainty than the
highway project and has a relatively low risk of overruns.
3:03:51 PM
SENATOR WAGONER commented that the reason the producers have
stated for wanting to build the pipeline is that they have the
technical capabilities and experience building a pipeline in
Alaska. He pointed out that the last pipeline they built was 800
percent over the estimated cost, and asked Mr. Shipkoff what
makes him think AGPA could do any better.
MR. SHIPKOFF replied that he doesn't know, but the pipeline on
AGPA's project is a much smaller component of the cost of
getting gas to market. There is a lot of uncertainty associated
with it and the reason Bechtel's numbers were so much higher
than everyone else's is that Bechtel acknowledged that and
loaded them with contingencies that had to be stripped out in
order to compare "apples to apples".
MR. WALKER added they have looked at other companies, such as
TransCanada, that have an impressive record of coming in on or
under budget on similar projects.
MAYOR WHITAKER stressed that AGPA does not intend to build a
pipeline; it intends to hire the best in the world, with the
best track record, to build the pipeline.
SENATOR THERRIAULT voiced concern about costs during
construction and asked whether AGPA has considered any
mechanisms to keep costs down.
3:06:52 PM
MR. SHIPKOFF responded that AGPA recognizes that overruns in the
midstream result in adverse impacts on the upstream economics,
and it has offered the producers a role in the construction
process.
DR. FINIZZA commented that, regarding Point Thompson, Mr.
Shipkoff said his model does not take credit for the liquids
from that project and Econ One did not include them either.
MR. WALKER thanked the committee for engaging Econ One to
prepare this analysis and for allowing AGPA to meet with them.
He said that they are pleased with the open process and think it
was very helpful.
REPRESENTATIVE KELLY asked the AGPA representatives exactly what
they want the legislators to do and in what time frame.
MAYOR WHITAKER thanked Representative Kelly for getting to the
point and replied that they believe it would be a mistake to
continue with the contract as it is. They think that the
legislature should enter into an agreement in the next six
months that results in approximately 2 Bcf/d of gas to a Port
Authority-type entity, allowing for an LNG project to underpin
in-state usage and an eventual highway project. He ended by
saying that AGPA believes there is a lot of room for cooperation
and collaboration between the legislature, a new administration,
the producers, and the Port Authority or another entity that can
accomplish the same end.
At ease from 3:10:42 PM to 3:19:32 PM
^ ROUNDTABLE DISCUSSION OF THE PORT AUTHORITY PLAN
CHAIR SEEKINS introduced members of roundtable discussion:
David Van Tuyl, Commercial Manager, Alaska Gas Group, BP
Mike Menge, Commissioner, Dept. of Natural Resources
Ken Griffin, Deputy Commissioner, Dept. of Natural Resources
Dr. Tony Finizza, Econ One Resource, Inc.
Roger Marks, Economist, Dept. of Revenue
Steven Porter, Deputy Commissioner, Dept. of Revenue
Bill Walker, General Counsel, Alaska Gasline Port Authority
Radoslav Shipkoff, Financial Advisor to the Port Authority
Jim Whitaker, Chairman, Alaska Gasline Port Authority
Representative Bill Stolz
Representative John Coghill
Representative Ralph Samuels
Representative Mike Kelly
Senator Thomas Wagoner
Senator Ralph Seekins, Chair
Senator Therriault
Senator Kim Elton (via teleconference)
Senator Fred Dyson (via teleconference)
^ Steven B. Porter, Deputy Commissioner, Department of Revenue
STEVEN B. PORTER, Deputy Commissioner, Department of Revenue,
commented on the importance of the Port Authority's
participation with the state in the LNG project, and said that
the state has entered into a memorandum of agreement with the
Port Authority to work together to develop that option to the
point that it can move from being technically feasible to being
commercially economic and competitive with the Canadian route.
He said that one of the things he has been looking at is the
risk to the state of participation in a mega project. He quoted
from a book titled Mega Projects and Risk: an Anatomy of
Ambition that is specifically about local and state government
participation in mega projects:
When actual versus predicted performance of megaprojects
are compared, the picture is often dismal. We have
documented in this book that cost overruns of 50 percent to
100 percent in real terms are common in megaprojects, and
above 100 percent are not uncommon. Demand forecasts that
are wrong by 20 percent to 70 percent compared with actual
development are common. The extent and magnitude of actual
environmental impacts of projects are often very different
from forecast impacts. Post-auditing is neglected.
Substantial regional, national, and sometimes international
development effects commonly claimed by the project
promoter typically do not materialize, or they are so
diffuse the researchers cannot detect them. Actual project
viability typically does not correspond to the forecast
viability, and the latter often being brazenly over-
optimistic. We have identified the main cause of this
megaproject paradox, namely the fact that the more and
bigger megaprojects are built despite their poor
performance record, as one of the risks is negligence and
lack of accountability in the decision-making process. We
have shown that project promoters, unsurprisingly, are
happy to go ahead with highly risky projects as long as
they themselves will not carry the risks involved and will
not be held accountable for the lack of performance. We
have also shown that with the conventional approach to
megaproject development, all too often promoters have been
able to dodge risk and accountability. Finally, we have
proposed measures in institutional development to curb this
problem. The aim is to decrease the risk of government,
taxpayers, and private investors, being led or misled, as
often turns out to be the case, to repeatedly commit
billions of dollars to under-performing projects. Clearly,
nobody has an interest in risking an under-performing
project in and of themselves; however, contractors and
other project promoters who could stand to gain from the
mere construction of projects, and who are often powerful
movers in the early stage of project development, may have
a self-serving interest in underestimating the costs,
overestimating demand, and similarly underestimating
environmental impact and overestimating development
effects.
MR. PORTER said that the key is to always track where the risk
lies. Sometimes a person who is a true believer in a project
might unintentionally paint a rosier picture than is
realistic. He pointed out that in some areas of their
proposal, the Port Authority has been quite optimistic and
that is OK, but it is important to recognize it and to
understand where the risk really lies. Their proposals
generally carry no risk to the Port Authority; it is usually
transferred to the producers, the bondholders, or the
downstream. That means that any incremental value AGPA takes
from the project, is taken without contributing the risk-
benefit to the project. In an ideal world, it makes sense to
transfer as much risk as possible; but that carries a cost,
and it is important to ensure that the benefits go with it.
When risks are transferred to the bondholders, bonds will be
more expensive, and that has to be weighed in the economics.
For example, when Bechtel came up with their numbers, they put
a premium on them because it is a turnkey deal. That is a fair
approach, but it leaves money on the table. In the producers'
world that is called "leakage", everyplace that a billion
dollars or a hundred million dollars leaks from their pocket
to somebody else's, and they will try to grab that back. So,
when you do a "turnkey" deal, you pay for it. Those are real
dollars, and you always have to be asking yourself where the
risk went and if it cost you money.
3:29:56 PM
MAYOR WHITAKER said that he could not argue with anything Mr.
Porter said; the transfer of risks does carry a cost. He found
it hard to understand why the state negotiated a contract that
clearly transfers significant risk from the producers to the
state without gaining any benefit from the assumption of that
risk. [Parts of testimony were indiscernible.]
MR. PORTER agreed with Mayor Whitaker that the risk analysis
applies to all projects.
MR. SHIPKOFF echoed Mayor Whitaker's comments. He agreed with
Mr. Porter's remarks and felt it was important to recognize that
both projects are megaprojects and carry a significant amount of
risk. It is also correct that any risk-mitigation strategy has
implicit in it a cost to pay whoever is taking that risk on. One
of the reasons for adjusting the numbers in AGPA's current
analysis and stripping out some of the extra cost that came with
the Bechtel turnkey numbers, was to put the two projects on an
equal footing so the state can determine for itself whether to
engage in a turnkey contract or not. He repeated that AGPA would
be happy for the producers to manage the construction project or
to do it themselves. AGPA wants a project, not necessarily a
project built by Bechtel under a turnkey arrangement.
CHAIR SEEKINS asked Mr. Walker if this is the first time that
has been stated in testimony.
3:34:18 PM
MR. WALKER replied that it might be the first time in testimony,
but not the first time it has been presented. He said that they
discussed all of this with BP some years ago.
CHAIR SEEKINS asked if this is a point he wants on the record.
MR. WALKER replied that he is happy to have it on the record.
They want a project and would love to engage with the producers.
^ David Van Tuyl, Commercial Manager, Alaska Gas Group, BP
DAVID VAN TUYL, Commercial Manager, Alaska Gas Group, BP,
responded to an earlier comment suggesting that the producers
are not serious about pursuing ANS gas development. He said that
is not the case, BP is very serious about pursuing development
of North Slope gas and its actions over the past few years speak
to that more loudly than words. In a joint study in 2000 with
ExxonMobil and ConocoPhillips, BP spent $125 million on
development of ANS gas. Since that time it has worked with the
state to develop and improve a contract to accomplish that. He
did agree with the Port Authority that it is best to pursue an
economically viable project sooner, which is why he is involved
in these discussions. [indiscern.]
3:38:32 PM
^ Roger Marks, Economist, Dept. of Revenue
ROGER MARKS, Economist, Dept. of Revenue, asked how plausible
the scenario that Econ One analyzed actually is and whether it
would be able to start up in 2013.
CHAIR SEEKINS pointed out that Econ One did not analyze the
plausibility of the project, but a model that was provided to
them.
DR. FINIZZA added that both Econ One and FERC believe this
project will be under FERC jurisdiction and, although the Alaska
Natural Gas Development Act says municipalities are exempt from
it, the context is projects that are within municipalities for
intra-state shipment of gas. The Port Authority may disagree,
but if it were under FERC jurisdiction, then if someone builds a
4 Bcf/d pipeline to Delta Junction and 1 Bcf goes from Delta
Junction to Valdez with no commitment for another 3 Bcf of gas,
FERC would not allow the cost of the empty space to be recovered
in the tariff. So, if the Port Authority builds a non-recourse
pipeline, that is, project revenues alone repay the investors,
and the FERC does not let them recover the cost of the empty
space, investors stand to lose a huge chunk of money if the
pipeline doesn't go from Delta Junction to Alberta and on to the
Lower 48. This means that there has to be a sanctioned project
from Delta Junction to Chicago in order to proceed without
risking loss to investors; and that puts the project on
basically the same time schedule as the producers are.
Consequently, He does not think the scenario he was given to
analyze is realistic.
3:42:47 PM
MR. SHIPKOFF responded that they have heard that argument
before, and that their FERC counsel in Washington said it would
not be an issue.
Before explaining why that is so, he wanted to step back and
talk about the scenario they are proposing. The Port Authority,
in agreement with the shippers, decides to accommodate future
expansion because both the Port Authority and the shippers
anticipate the need. The Port Authority will not be doing this
in a vacuum; it will be the result of discussion. That being the
case, any agreement between the producers and the Port Authority
will be a negotiated rate, not a recourse rate. By definition,
that means that the Port Authority and the shippers have agreed
that it is the most economic scenario. He said that he
personally finds it inconceivable that, if all parties think
that is the most commercially reasonable deal, FERC will not
allow it in the tariffs. The regulatory approach is not going to
drive the economics of the largest oil and gas project in the
United States. There are precedents in which FERC has approved
including unused space in its rates. It is not over sizing, it
is sizing the pipeline properly for future volumes. AGPA's FERC
counsel thought that, not only would FERC allow this, it is
highly unlikely that they would approve anything less, because
building a smaller diameter pipe initially would essentially
hamper future expansion.
3:45:54 PM
MR. VAN TUYL pointed out that Mr. Shipkoff suggested that, if
all parties to the gasline approached FERC agreeing that this is
the best commercial deal, FERC would bless it; but that won't
happen. As BP has stated before and as Dr. Finizza's Econ One
analysis states, the cost of delivery for LNG on a per-unit
basis is significantly higher than the gas pipeline project. Of
course, one can't know what the market will do, but it is
possible to gauge the cost of a project and pursue the lowest
cost project. The highway project is that. The LNG project
carries a higher per-unit cost and a gas pipeline at reduced
volumes, which is a combination of the worst of both worlds,
because you lose the economies of scale on the gas pipeline and
deliver gas at a higher per-unit cost. The gas pipeline is the
best way to get Alaska's gas to market at the lowest possible
cost.
CHAIR SEEKINS asked Mr. Whitaker if there have been discussions
with the producers about jointly approaching FERC.
MR. WALKER replied no and reminded him of the TAPS arrangement
negotiated with FERC, which was negotiated between the state of
Alaska and the producers. It was later ruled by the regulatory
commission (RCA) that it was not in the best interests of
Alaska.
3:48:34 PM
^ Mike Menge, Commissioner, Dept. of Natural Resources
MIKE MENGE, Commissioner, Dept. of Natural Resources, said that,
concerning any assertions related to FERC and loan guaranties,
Section 116(b) of the Alaska Natural Gas Pipeline Loan Guarantee
Act states that:
(b) CONDITIONS- (1) The Secretary may issue a Federal
guarantee instrument for a qualified infrastructure project
only after a certificate of public convenience and
necessity under section 103(b) of this division or an
amended certificate under section 9 of the Alaska Natural
Gas Transportation Act of 1976 (15 U.S.C. 719g) has been
issued for the project.
(2) The Secretary may issue a Federal guarantee instrument
under this section for a qualified infrastructure project
only if the loan or other debt obligation guaranteed by the
instrument has been issued by an eligible lender.
(3) The Secretary shall not require as a condition of
issuing a Federal guarantee instrument under this section
any contractual commitment or other form of credit support
of the sponsors (other than equity contribution commitments
and completion guarantees), or any throughput or other
guarantee from prospective shippers greater than such
guarantees as shall be required by the project owners.
3:49:43 PM
MAYOR WHITAKER said that they are very familiar with the statute
and there is nothing in the language that they find prohibitive.
He said he expects a letter from the secretary [of Energy]
indicating that there will not be a problem given that the
project moves forward. He also said that the specific reference
to an LNG project in the statute is very telling.
CHAIR SEEKINS asked Mayor Whitaker if a copy of that letter
could be made available to the committee.
MAYOR WHITAKER said yes.
MR. WALKER said that, when he met with the general counsel for
the Department of Energy for clarification of the section that
Commissioner Menge read, the direction to him was that if AGPA
is FERC exempt, bring the project directly to the Department of
Energy to apply for the loan guarantee. Counsel was very clear
on that, and he expects to receive a letter to that effect
within 30 days. He said he would provide a copy of that letter
to the committee as soon as it is received.
MR. PORTER said he wanted to go back to Mr. Van Tuyl's mention
of the per-unit cost of development. That is what the producers
will look at; the state has to create an LNG project that is
competitive on the per-unit cost of development standard. The
problem with this project is that its success is predicated on
getting to market earlier. It is never wise to take an
uneconomic project and try to make it economic by speeding it
up. The project has to be commercially viable and "heads-up"
competitive with the Canadian line.
3:54:18 PM
MR. MENGE pointed out that the Port Authority did Herculean work
in the closing hours of Congress to get the project included in
the loan guarantee; but he cautioned that the language in the
statute clearly indicates that the certificate will have to be
issued before the Department of Energy can issue the loan. That
means the Department of Energy will either have to ignore the
statute or to seek clarifying language from Congress, both of
which are risky.
MR. WALKER said he disagreed. His comment to Mr. Van Tuyl is
that the overarching problem the Port Authority has had in the
state is that there is nothing in the lease that says the risk
has to be down to a certain level before a project can proceed.
3:56:24 PM
He continued that the Port Authority was not created to be a
hindrance, but to create additional value and benefit, and it
has continually tried to do that despite a rather hostile
response from the administration. It is not trying to force the
state into something uneconomic; it genuinely wants to see a
project in Alaska that is good for the producers and good for
the state.
3:57:32 PM
MR. MARKS said that what concerns the Department of Revenue
about the LNG project is the limited West Coast market for LNG
gas. The West Coast now has about a 9 Bcf/d market and growth is
projected to be slow between now and 2020. Because it is an
isolated market, gas sells for $.50 less on West Coast than it
does in Chicago; the action is in the upper Midwest. Through
the evolution of the Port Authority project, it first focused on
Asia, but that market didn't work. Then it looked at putting 4
Bcf on West Coast. Now it is down to 1 Bcf to the West Coast,
and he conjectured that they have realized that market is pretty
small. The target of the analysis is the Sempra Plant in Baja
California, which seems to be the only West Coast site with a
chance of being built; but it is over subscribed. Sempra is the
parent corporation for Southern California Utilities, and it
doesn't care how much gas comes in or what happens to the price,
because it makes money by moving gas through its pipes. The
Kitimat plant has permits, but does not have financing. It
doesn't have financing because it doesn't have gas, and it
doesn't have gas because it is commercially challenged. The
forecasts show that there will be only about 1.8 Bcf/d of LNG
needed on the West Coast by 2020, including the 1.2 Bcf/d
starting up in 2008.
4:01:10 PM
He said that the other big source of gas for the West Coast is
the Rocky Mountains. This is the non-conventional gas that Dr.
Finizza talked about, not only conventional gas but also coal
bed methane and shale gas. Resource estimates for the Rockies
are upwards of 300 Tcf. It is a classic example of supply
response to higher price; with higher prices, more gas becomes
economic. There are three pipelines that come into the Rockies
from the West Coast and could be expanded, but they are building
an 1800 MMcf pipeline from the Rockies to eastern Ohio because
the West Coast doesn't need the gas. So, the department believes
that there is no West Coast market for LNG, and that is another
reason the administration believes the highway route makes more
sense.
4:03:10 PM
SENATOR THERRIAULT asked Mr. Porter whether his comment about
the danger of trying to accelerate the project was in response
to a perceived notion that the producers are not moving fast
enough, or was a criticism of the Port Authority's assertion
that they can get it done sooner.
MR. PORTER replied that the issue applies to any project. The
producers' timeline to project sanction is about four years.
Somehow, the Port Authority got that down to a couple of years.
The producers have learned over time not to overlap certain
tasks, because doing so increases the risk of mistakes and cost
overruns; so when reviewing the AGPA project, you have to ask
what parts of project are being worked concurrently and what
that does to the risk.
4:05:25 PM
MAYOR WHITAKER responded to Mr. Porter's comments about the
small West Coast market and competing sources of power. He also
addressed Mr. Marks' assertion that risks are somehow limited on
the Canadian line, pointing out that the state is being asked to
sign a deal with no knowledge of what the Canadian side wants
out of it. He said that what he has is a project that can move
forward. It may hit a roadblock that it cannot get past, but he
knows it has viable permits, available funding, and a stable
market. [Parts of response were indiscernible.]
4:09:01 PM
He said he also knows that it is normal to pay to reduce risk,
yet the state is paying concessions to assume more risk, and he
does not understand that.
4:09:48 PM
MR. SHIPKOFF disagreed with Mr. Marks' comments on the West
Coast market. With regard to the administration's view that
there is not room in the West Coast market for more than 1.8 Bcf
of LNG, he pointed out that Sempra is expanding the terminal to
2.5 Bcf and has received expressions of interest to 2.9 Bcf so
far. The West Coast market is smaller than the Mid-West and East
Coast markets combined, but it is not uneconomic. The Rockies
Express project is not sending gas to the West Coast because
there is a bottleneck in their ability to send the gas to all of
the markets they might access, and they will get a higher value
in the Mid-West. Once they start sending 2.9 Bcf to the Mid-West
however, it will decrease the price of LNG in the Mid-West and
increase it on the West Coast.
MR. WALKER said that it is not true that Sempra does not care
what the gas sells for; he was in the meeting when Sempra
proposed to put $5 million into this project outside of the
federal loan guarantee. It is interested in investing in this
project and has not done so only because of the response it
received from Governor Murkowski.
MR. MARKS responded to Mr. Shipkoff and Mr. Walker that, just
because Sempra got more interest than expected in the recent
open season, does not mean the market will absorb that much gas.
The Rockies Express underscores that fact that producers are
willing to pay higher shipping costs to the East Coast and make
less profit, because they do not believe the West Coast market
can absorb the volume of gas. He reiterated that Sempra makes
money on their pipes, not buying and selling gas.
4:16:08 PM
SENATOR THERRIAULT asked Mr. Marks if the fact that the Rockies
Express project has invested in pipe to the Mid-West and East
Coasts indicates that the market has evaluated the potential for
the import of LNG and determined that the market will not be
flooded and will continue to be economic.
MR. MARKS replied that, as Mr. Shipkoff stated, gas is
bottlenecked in the Rockies for lack of pipeline capacity.
Prices there are low because more gas is being produced than can
be consumed, and some available gas is not being produced
because there is no market. There are three pipelines from the
Rockies to the West Coast that could be expanded for less than
what it will cost to move the gas to Ohio. The lion's share of
imported LNG is targeting the East Coast and the coastline where
it comes in. As it moves inland it becomes less economic, so the
target market for Alaskan gas is the middle of the U.S. and far
from LNG import sites.
4:18:04 PM
MR. VAN TUYL said that he has never said that there is a magic
number necessary or tied to BP's lease obligations. His
observation was that the lowest cost way to move gas to market
is through a gas pipeline. He also responded to Mr. Walker's
implication that the study BP did in 2001-2002 netted two pages
of results, by assuring the committee that it resulted in rooms
full of binders, data, and samples, everything that is needed to
begin the permitting process.
4:19:58 PM
MAYOR WHITAKER replied that he did not mean to imply that there
were only two pages of data collected or available; the
definitive statement was that the legislature received two pages
of bullet points that failed to address the issue. He offered to
provide a copy of those two pages to the committee.
DR. FINIZZA asked how the producers arrived at the 4.3 Bcf/d
figure for the line to Canada.
CHAIR SEEKINS asked Mr. Van Tuyl to respond to that question.
MR. VAN TUYL answered that there were three main factors in
determining the appropriate off-take rate: what the upstream
impact of exporting gas from slope might be, downstream pipeline
design for the lowest unit cost and maximum expandability, and
field off-take. The result of these considerations was a nominal
4.5 that came to be a 4.3 actual delivered volume. He explained
that, if the figure were increased 1 Bcf/d, in order to have an
expandable design you would need to use a high-pressure system
and bigger pipe. The cost of manufacturing and handling that
kind of pipe is prohibitive, so there would be a step change in
the unit cost. The 4.3 Bcf/d design provides a low unit-cost
delivery and is expandable at basically the same unit cost using
in-fill compression. The producers are still working with Alaska
Oil & Gas Conservation Commission (AOGCC) to determine what the
appropriate off-takes should be for those fields. Currently
Prudhoe Bay Oil Pool rules limit gas off-take to 2.7 Bcf/d and
they are still looking at Point Thomson.
4:24:08 PM
CHAIR SEEKINS asked Mr. Van Tuyl about the to Canada/through
Canada issue.
MR. VAN TUYL said that it is the producers' intent to deliver
the gas to North American markets, meaning Alaska or the Lower
48, not Canada. Language in the federal statutes expresses the
sense of the Congress and defines what the qualified project is.
Section 103 of the Alaska Natural Gas Pipeline Act reads:
The commission shall presume that sufficient downstream
capacity will exist to transport the Alaska natural gas
moving through the project to markets in the contiguous
United States.
He said that the definition of a qualified infrastructure
project refers to parts of the project "...that are used to
transport natural gas from the Alaska North Slope to the
continental United States." This language underscores the intent
to deliver gas to the Lower 48, not to other markets. In
addition, the National Energy Board (NEB) and Canadian producers
have raised concerns about leaving the gas in Canada, as that
would have deleterious effects on their market.
4:26:32 PM
CHAIR SEEKINS asked if it is that these molecules of gas leave
Canada, or if there would be an exchange.
MR. VAN TUYL said that it could occur either way. There will be
an open season in Alberta and the producers are not sure what is
going to happen with the physical construction of pipe out of
Alberta. There may be sufficient existing capacity at a
reasonable cost to allow all of Alaska's gas to flow on existing
pipe, or to expand existing pipe to allow that, or it may be
necessary to build new pipe, which is the base-case that the
producers have assumed. If they have to build a new pipe, it is
possible that other shippers will move their gas on the new
pipe, so molecules might be intermingled and exchanged.
MR. MARKS added that Canada is a significant exporter of gas to
the United States, so the arrival of 4.5 Bcf from Alaska does
nothing for demand in Canada and would simply mean more gas
would move from Canada to the U.S.
4:29:50 PM
MR. WALKER said, in response to Mr. Van Tuyl's comments about
gas into Canada, that a project is only required to bring gas
all the way to the U.S. if it has a loan guarantee, and the
producers have not applied for one. Also, BP has no interest in
the tar sands, but ExxonMobil and ConocoPhillips do; and a
representative from ConocoPhillips said it just wants to get its
gas to the tar sands and take it out as oil. He said AGPA would
get a paper to the committee on it.
4:30:47 PM
MR. VAN TUYL said that he can speak for BP, and repeated that it
is BP's intent to move the gas to consumers in Alaska or in the
Lower 48 states. He said that Mr. Walker was correct that he was
reading from two parts of the statute, one that describes the
loan guarantee, and it is the producers' intent to access that.
The other quote is from the Alaska Natural Gas Pipeline Act
itself, which is the entire regulatory structure for this
project.
4:31:52 PM
MAYOR WHITAKER said he sensed that some people may believe the
Port Authority plan intends to take gas somewhere other than the
Lower 48.
CHAIR SEEKINS said he does not believe that is the case. The
question stemmed from the comment that a majority of the gas was
going to Canada.
4:33:01 PM
MR. SHIPKOFF said that Mr. Van Tuyl has confirmed his
understanding of the origin of the 4.3 figure used in the
highway project. He is not suggesting that the highway project
plus the Y-line or any incremental project should be limited to
only 4.3 Bcf/d total. AGPA's numbers suggest that if 4.3 goes
down the highway line and an additional 1.2 to Delta Junction,
the NPV is still significantly in favor of doing both projects.
4:35:59 PM
REPRESENTATIVE KELLY asked if the AOGCC was asked to give an
opinion on whether the North Slope will provide the 5.5 Bcf/d.
COMMISSIONER MENGE replied that the AOGCC is in process of
gathering that information, but does not have an answer at this
time.
4:36:59 PM
SENATOR THERRIAULT said he believes that the AOGCC expects to
have an answer to that question for Prudhoe Bay by the end of
this year. It has gotten great cooperation from the companies,
so it has not had to replicate the reservoir modeling for
itself. It is possible that, if one develops Point Thomson as a
gas field, it will trap a lot of liquids in the ground; so, the
AOGCC may not allow a retrograde field to be developed as a gas
field.
4:38:21 PM
DR. FINIZZA said that, if one can send 4.3 Bcf/d to Canada and
an additional 1 Bcf to the West Coast at a profit, the present
worth (PW) goes up; but that isn't the right question. If that
incremental 1.5 Bcf were put through the same Canada line, it
would bring more money, so the question isn't whether one can
make money sending LNG to the West Coast, it is whether it is
competitive with the other option.
MR. SHIPKOFF responded that may be true, but the producers are
not proposing to bring 5.5 to Chicago, they are proposing to
bring 4.3 to Chicago. There is a limit on how much the market
can absorb, how it would affect price, and downstream take-away
capacity. Also, AGPA is not suggesting that the field be ramped
up beyond what is prudent in the long-term.
DR. FINIZZA interjected that he assumes it is more economic to
take the gas down through Canada. Looping economies might change
and actually become more competitive, but the state will have to
monitor that.
MAYOR WHITAKER said he thinks that consideration of NPV as a
determinant is being missed.
MR. PORTER responded that he believes he has covered that.
4:40:49 PM
CHAIR SEEKINS said that, as Dr. Finizza pointed out, starting a
project three years sooner has value; but he questions whether
the assumptions are correct. For example, whether the project
will be exempt from FERC regulation, whether it will get the
federal loan guarantees, and whether AGPA will buy gas or get
the producers to ship it, and under what arrangement. He said he
understands the need for flexibility in planning, but the key on
the economic side seems to be the NPV arrangement.
4:42:30 PM
MR. SHIPKOFF responded that the value the project brings to the
table is that implementation can commence as soon as they have
an agreement for gas supply, and that the starting time
differential may be longer than three years. There is even the
unlikely possibility that the LNG project is the only one that
will ever be implemented.
4:43:24 PM
CHAIR SEEKINS agreed that the committee has heard repeatedly
that delay hurts everyone in terms of NPV. Econ One did an
analysis of what a year delay would cost the highway project.
4:43:44 PM
DR. FINIZZA replied yes, that delay represents a present value
loss.
REPRESENTATIVE SAMUELS said that the loss was projected to be
one percent for a 1-year delay. For example, if the state had a
7.25 deal to break even on an NPV basis, with a 1-year delay it
would have to go to 8.25. With a 3-year delay, it would have to
go to 11.25. So, it would have to raise the tax rate by 50
percent with a 3-year delay to go to NPV basis and break even.
He noted that the information the committee did not get from Dr.
Finizza is, if we have 5.5 available from the field in 2016 and
it goes down one line, how does that compare on an NPV basis, to
sending 1.2 south and 4.3 to Canada.
DR. FINIZZA interjected that is assuming 5.5 is feasible with
field production.
REPRESENTATIVE SAMUELS agreed that, if it is not feasible, then
a 1.2 line is all that would ever be built, because shipping
only 3 across the continent is not economic.
4:45:42 PM
^ Ken Griffin, Deputy Commissioner, Department of Natural
Resources
KEN GRIFFIN, Deputy Commissioner, Department of Natural
Resources, directed the committee's attention to page 49 of Dr.
Finizza's presentation and the first case, showing highway-only
figures with producer net cash NPV of $21.6 million. The next
case is a Y-line starting in 2013 and a highway line starting in
2016, splitting the 4.3 Bcf. There is a two percent increase in
producer net cash NPV to $21.9 million; but to get that required
two pipelines installed at comparable cost, and the addition of
the full infrastructure for the LNG project. So, for what is
essentially the same NPV, both capital investment and completion
risk have increased substantially. He said that this illustrates
that IRR or PI is important as a measurement of the efficiency
of the investment. He said that Dr. Finizza showed the total
value of the two projects as essentially equal given the
assumptions here, but he did not show the efficiency of the
capital that was invested. If that figure were calculated, it
would show that the highway project has much higher investment
efficiency for the same return.
4:48:01 PM
DR. FINIZZA responded that he did talk about the efficiency but
that he didn't calculate it.
4:48:17 PM
CHAIR SEEKINS Announced that they will recess at 5pm and come
back at 9am.
4:49:01 PM
MR. PORTER agreed with Mayor Whitaker that the unknowns in
Canada do pose a substantial risk. Aboriginal agreements and
other issues could delay project sanction beyond the four years
projected, throwing the whole timeline off. The problem with
moving forward now is that, if Alaska builds a line to Delta
before things are settled in Canada, it will get beat up in
negotiations due to the unused pipe it is carrying.
4:50:18 PM
MR. SHIPKOFF responded that Mr. Porter's assertion that the line
to Delta would weaken our negotiating position with Canada is
only true if the line to Delta is not economic in its own right.
He also pointed out that the differentials in NPV on page 49 are
all calculated based on the assumption that incremental reserves
are exactly 15 Bcf, which is a conservative estimate. He also
reminded the committee that the LNG project could be implemented
immediately, while there is no assurance if or when the highway
project could take place.
4:52:14 PM
MR. GRIFFIN stated that it is not accurate to say the LNG
project reduces risk to the state. The largest part of the
construction risk for any of these projects will be the Alaska
portion due to terrain, weather, and logistics. We do have TAPS
right-of-way, but a lot is working against construction here
with regard to cost and timing; so, while Alaska is able to cut
off the cost risk of getting a pipe across Canada, the major
portion of that range of risks will exist in Canada [Alaska]. We
will have a 1 Bcf/d project to balance that against vs. the
potential for a 4.5 Bcf/d project going through Canada. We are
not going to be able to sit down and frame the estimates of that
total project the way it was perceived in conversation.
4:54:14 PM
MR. MARKS said he'd like to explore the plausibility of starting
up with a 1 Bcf pipeline in 2013. If the state builds a 4 Bcf
pipe to Delta Junction before deciding to do the highway project
and can recover only 1 Bcf/d, it will not be able to get
financing. If it is non-recourse financing and there is no money
to repay the investors, it won't be approved. If it goes into
the project planning to build the highway project, it is on the
same timeline as the producers' project with a startup in 2016.
Consequently, the 2013 startup is implausible and the NPV
benefit does not exist.
4:55:43 PM
MR. SHIPKOFF said that AGPA does not know with certainty that it
will be able to deliver gas in 2013, but the highway project
does not know with certainty that it can deliver gas in 2016
either. He believes the LNG project has an advantage because it
has a headstart on the permitting and can start three or more
years earlier than the highway project.
4:56:28 PM
MAYOR WHITAKER said he was dumbfounded by Mr. Marks' assertion
that the risk comparison is valid! He said that he totally
disagrees with his statements.
4:57:23 PM
MR. MARKS asked if the committee wants to start talking about
why the administration wrote the gas contract as it did, and how
it calculated the risks.
CHAIR SEEKINS answered no, not at this time.
SENATOR WAGONER said he hadn't heard a response from Mayor
Whitaker to Mr. Marks' comments about AGPA's inability to obtain
financing for a line sized to accommodate expansion.
4:58:52 PM
MR. SHIPKOFF said he thinks he answered that in Juneau three
weeks ago, and that Mr. Marks' assertion is absurd.
4:59:26 PM
MR. MARKS said that he does not believe the FERC will allow the
project to recover the cost of empty space, in which case he
does not believe that a lender would finance it with no
assurance it can get the money back.
5:00:16 PM
MR. SHIPKOFF responded that he answered this question about an
hour ago, that their FERC counsel in Washington DC said he
thinks the FERC will not only allow, but insist on sizing the
pipeline for future expansion. The larger issue is that the
project will not proceed in isolation, it will be done in
agreement with the shippers, and FERC is not going to overrule a
commercial deal because its recourse rate regulations do not
allow that.
5:01:09 PM
MR. PORTER said that he understands the statement that, if it is
going to work, there has to be a commercial agreement with the
shippers. That means the producers have to agree to pay the
premium and get a smaller netback, and buy into the idea that
the present worth is based on getting gas to market three years
earlier. He said he doesn't think the producers believe that is
a rational choice, so there won't be a commercial deal. It also
means that this creates multiple projects, which means multiple
mobilizations and de-mobilizations on a large scale. All of that
is what is referred to as "leakage". He said he keeps coming
back to the fact that the only way the Port Authority is going
to get the producers on board with a commercial deal, is if it
comes in with a low enough per-unit price.
5:02:37 PM
REPRESENTATIVE SEATON asked whether the question of maximum
value to state would be addressed.
CHAIR SEEKINS said the committee would be working on that
tomorrow.
Adjourn 5:03:26 PM
| Document Name | Date/Time | Subjects |
|---|