Legislature(2009 - 2010)BARNES 124
02/01/2010 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Overview by Tony Palmer, Transcanada Alaska: Agia Update/open Season | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
February 1, 2010
1:03 p.m.
MEMBERS PRESENT
Representative Craig Johnson, Co-Chair
Representative Mark Neuman, Co-Chair
Representative Kurt Olson
Representative Paul Seaton
Representative Peggy Wilson
Representative David Guttenberg
Representative Scott Kawasaki
Representative Chris Tuck
MEMBERS ABSENT
Representative Bryce Edgmon
COMMITTEE CALENDAR
OVERVIEW BY TONY PALMER, TRANSCANADA ALASKA: AGIA UPDATE/OPEN
SEASON
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
A.M. (TONY) PALMER, President
TransCanada Alaska, LLC;
Vice President
Alaska Development
TransCanada
Calgary, Alberta, Canada
POSITION STATEMENT: Provided a PowerPoint presentation and
update on TransCanada's Alaska Pipeline Project.
PAT GALVIN, Commissioner
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: During the overview on the Alaska Pipeline
Project, answered questions.
ACTION NARRATIVE
1:03:05 PM
CO-CHAIR MARK NEUMAN called the House Resources Standing
Committee meeting to order at 1:03 p.m. Present at the call to
order were Representatives Seaton, Guttenberg, Kawasaki, Tuck,
Johnson, and Neuman. Representatives P. Wilson and Olson
arrived as the meeting was in progress.
^OVERVIEW BY TONY PALMER, TRANSCANADA ALASKA: AGIA UPDATE/OPEN
SEASON
OVERVIEW BY TONY PALMER, TRANSCANADA ALASKA: AGIA UPDATE/OPEN
SEASON
1:03:50 PM
CO-CHAIR NEUMAN announced that the only order of business is on
overview by Tony Palmer, TransCanada Alaska: AGIA Update/Open
Season.
A.M. (TONY) PALMER, President, TransCanada Alaska, LLC; Vice
President, Alaska Development, TransCanada, noted that he is
chairman of the management committee of the Alaska Pipeline
Project. He introduced members of his project team present at
the hearing: Paul Pike, Senior Project Manager for the project,
ExxonMobil Development Company (ExxonMobil); Patty Baloski (ph),
External Affairs for the project; Jim Morris, Project Counsel
for the project; Brian Dumfy (ph), Public Affairs for the
project; and Tom Roberts who handles the project's work in
Washington, DC.
1:06:10 PM
MR. PALMER began his PowerPoint presentation, explaining that on
[1/29/10] the Alaska Pipeline Project (APP) went through a
teleconference on the rollout of its Federal Energy Regulatory
Commission (FERC) filing for the project's first open season
(slide 2). All of the information from that filing is available
on both TransCanada's and FERC's websites. In an open season,
the pipeline company provides potential customers with design,
commercial terms, and an estimate of project costs, tariffs, and
timelines. While this is normal in an open season, it is
usually done in private and is confidential between the pipeline
company and its customers. The Alaska Pipeline Project is
unique in that this information has been divulged to the public
and to competitors, which is something that has never occurred
before.
1:08:20 PM
CO-CHAIR NEUMAN said there were several things unique with the
20 "must haves" that were required by Governor Palin during the
time the Alaska Gasline Inducement Act (AGIA) was being
considered. He surmised the $500 million provided in AGIA for
reimbursements was also unique.
MR. PALMER responded yes. When [TransCanada] made its AGIA
application over two years ago, that application and all of its
information became public. Certain rights were obtained under
the AGIA license and certain obligations to the State of Alaska
were encumbered.
CO-CHAIR NEUMAN commented that since those are Alaskans' dollars
it is appropriate they be able to see what is going on.
1:09:12 PM
MR. PALMER resumed his presentation (slide 2). He said the goal
of the open season is executed contracts with potential
customers. This open season will offer service to potential
customers that want service throughout Alaska, as well as
service to the Lower 48 via Alberta, British Columbia, or via
Valdez, Alaska, for liquefied natural gas (LNG) markets in the
U.S. or internationally. A number of parties in Alaska wanted
an LNG alternative to be put forward in addition to a pipeline
through Alberta, which has been done. During the open season,
any customer that wishes to have deliveries within Alaska, or to
Valdez, or to Alberta on the way to the Lower 48 will have an
equal opportunity as APP has comprehensive proposals for both
alternatives in front of the state of Alaska and the FERC.
1:10:27 PM
MR. PALMER stressed that no individual commercial party can make
this project a success (slide 3). Any large pipeline project
goes through a lengthy development stage, and if it is
successful it then moves forward to construction and ultimately
operation. Thus, this project must first succeed in the current
development phase. Prior to open season, APP did a tremendous
amount of work on the materials included in its FERC filing, and
work to advance the material in the filing will continue until
April 2010. Assuming FERC's approval is received on a timely
basis, APP will hold the open season from May through July 31,
2010. Post open season will be from August 2010 through 2014.
All stakeholders in the project have important initiatives
underway to advance the project. In addition to the Alaska
Pipeline Project, these stakeholders include producers/shippers,
governments, and others. All parties must work together and all
must achieve commercial and regulatory breakthroughs for the
project to succeed. This is the nature of every major pipeline
project, not just this one in Alaska.
1:11:56 PM
MR. PALMER, in response to Co-Chair Johnson, stated he will
address [the commercial and regulatory conditions that are
needed to move this project forward] when he gets to slides 14
and 15.
MR. PALMER, in response to Co-Chair Neuman, agreed to provide
another update in April 2010.
1:13:23 PM
MR. PALMER highlighted the achievements to date (slide 4). Over
the decades producers and potential shippers have explored and
developed gas reserves, he said, and that is an advantage for
this project because it is known that there is approximately 36
trillion cubic feet (Tcf) of proven gas. Those parties have
also examined alternatives for transportation routes as well as
potential markets for the natural gas. The State of Alaska
passed AGIA three years ago, establishing the requirements for
this major project and that is a critical factor for any large
pipeline project. It is local opposition or dissention that
often causes large projects to go off track, even if there is
governmental and regulatory approval. There was a comprehensive
review by Alaska's administration and legislature of APP's
license which was granted in fall 2008. He related that the
state is finalizing the royalty regulations as set out in AGIA.
1:15:34 PM
MR. PALMER credited the U.S. government and the FERC for
establishing a legislative and regulatory structure that has an
expedited, single-window structure with specific timeframes to
review the regulatory regime on this project, which is a
tremendous advantage relative to other major projects.
Additionally, a federal loan guarantee of $18 billion plus
inflation has been established, a huge advantage that was not in
place 30 years ago. With the U.S. government, FERC has also set
forward the regulatory process which TransCanada has now
initiated. The Canadian government has established a
legislative and regulatory structure for this project that is
also expedited and single-window. TransCanada has held a
certificate from [Canada's] National Energy Board for this
project for 30 years and has 25 percent of the project in Canada
in the ground and TransCanada has moved gas under that project
for 28 years.
1:17:05 PM
MR. PALMER, in response to Co-Chair Neuman, understood that it
is up to the State of Alaska as to whether its royalty share
will be taken in-kind or in-value. If the state takes its
royalty in-kind, he expects the state would then want to be a
shipper on the project and, as such, would be examining the
terms that APP has just put forward to determine whether it
wishes to be a customer. If the state takes its royalty in-
value, he expects the state would rely on the leaseholders to
ship the state's gas. In further response to Co-Chair Neuman,
Mr. Palmer assured members that APP will be providing the
opportunity during the open season for Alaska customers to
nominate gas, whether that is the State of Alaska, or utilities,
or industrials, or other parties.
1:19:34 PM
MR. PALMER continued his presentation, noting that TransCanada
has held a right-of-way through the Yukon since 1983 (slide 4).
He next addressed what the Alaska Pipeline Project itself has
done (slide 5). For the past five years, APP has said that the
best and most effective way to develop this project is an
alignment of five parties: the State of Alaska, the three North
Slope producers, and TransCanada. Today there is an alignment
of TransCanada and the state via the AGIA license that was
granted in 2008. In June 2009, TransCanada and ExxonMobil
aligned as well. The Alaska Pipeline Project has offered and
continues to offer equity participation to "BP" and
"ConocoPhillips." Both TransCanada and ExxonMobil would like to
see such an alignment, but to date no concrete negotiations have
taken place with the other two parties.
1:21:19 PM
MR. PALMER, in response to Co-Chair Johnson, explained that APP
has dealt with the corporate offices of ConocoPhillips and BP,
as opposed to offices at Denali - The Alaska Gas Pipeline.
1:22:01 PM
MR. PALMER, in response to Co-Chair Neuman regarding export from
Valdez, said that at this point for both the Alberta route
option and the Valdez route option, APP does not yet know who
would specifically be customers. The large producers could
decide to put their gas in either direction. They are very
sophisticated players in the Lower 48 market as well as the LNG
game, and they may decide to put their gas to the LNG option, in
which case they are clearly capable of constructing a
liquefaction facility [in Valdez] and making arrangements to
take their gas to market. If a non-major producer came forward
and decided to make a very large commitment to the pipeline, APP
would be happy to have discussions with that party as well.
1:23:33 PM
MR. PALMER resumed his presentation, noting that APP initiated
its pre-filing with FERC last year (slide 5). At FERC's
request, this pre-filing was earlier than had been anticipated.
The project is continuing to move forward with the Northern
Pipeline agency (NPA) in Canada. Alaska Pipeline Project has
initiated negotiations with the First Nation parties in Canada
that have been ready to have discussions, and has commenced
interfaces with Alaska Native groups and communities along the
project corridor. All of the previous claims on previous
projects have been removed at no cost to TransCanada and the
original partnership from 30 years ago has been dissolved.
1:24:48 PM
MR. PALMER, in response to Representative Seaton regarding APP's
earlier fear of loss of control in the FERC filing process,
stated there were extensive discussions with FERC staff and
other representatives of FERC prior to the pre-filing, and an
amicable settlement was reached that resolved APP's concerns and
met the needs of FERC. In his view, it has been positive for
both sides. In further response to Representative Seaton, he
said this resulted in a modest incremental cost to the project.
1:26:40 PM
MR. PALMER returned to his presentation (slide 5). He said APP
has developed comprehensive Alberta and LNG alternatives and has
complete technical, cost estimates, and schedules for both
alternatives in front of the public. Alaska Pipeline Project
filed its open season plan with FERC on [1/29/10]. As required
by FERC, APP also completed an in-state gas study which was done
under contract by Northern Economics, Institute of Social and
Economic Research (ISER), and Science Applications International
Corporation (SAIC). The study is on the FERC website as well as
APP's website. Northern Economics and its colleagues will be
conducting a technical conference on the study in Anchorage on
February 4, 2010, at 2:00 p.m. The study results will indicate
offtake points on the pipeline for deliveries to Alaska as well
as appropriate tariffs for in-state deliveries. The final
results for these will come out in the open season.
CO-CHAIR NEUMAN interjected that his staff will get copies of
that to committee members.
1:28:52 PM
MR. PALMER reviewed the open season timeline (slide 6). He said
the filing begins a 60-day FERC review for the U.S. section.
The public comments and FERC's review are primarily procedural
and are in regard to whether APP has met the 21 requirements.
It is hoped that FERC will approve the plan by the end of March
[2010] so the project can move forward in April to prepare the
final items. The open season would then commence in May and
conclude at the end of July [2010].
MR. PALMER, in response to Co-Chair Johnson, understood that
FERC is expected to respond within 60 days and has not indicated
a longer response time.
1:31:24 PM
MR. PALMER resumed his presentation (slide 6), noting that the
FERC application is for the U.S. portion of the project and for
the Alberta option there will be concurrent Canadian open
seasons. He explained that there are three possible outcomes to
any open season: no bids, unconditional bids for the full
volume, and conditioned bids. It is the norm in major pipeline
projects to get conditioned bids and he expects there will be
conditioned bids this time. If conditioned bids are received,
APP will work with those customers to resolve their conditions,
and the target for that is year-end 2010.
MR. PALMER addressed conjecture that not having the final open
season results until year-end 2010 is related to the political
schedule. He pointed out that in its AGIA application,
[TransCanada] stated that it expected to conclude its open
season by September 2009 and that conditions would be negotiated
with customers over the following 100 business days, which would
have been February 2010. This schedule was based on the desire
and hope that the license would be received by April 2008.
However, the administration's and legislature's reviews took
longer than that and the schedule was therefore moved back. The
100 business days is still exactly the same as it was in the
AGIA application. It is the norm to take several months to
resolve conditions on a major project of this scale.
1:34:27 PM
MR. PALMER, in response to Representative P. Wilson, explained
that Canada has open seasons like in the U.S., except there is
currently no filing required with the National Energy Board of
Canada to get approval for the open season process. Thus, the
FERC stage that was initiated on [1/29/10] is not required in
Canada. Assuming the project receives FERC approval on the
timing he described, APP will be conducting concurrent open
seasons in Canada for the Canadian portion of the project, if
parties wish that. TransCanada's own system within Alberta will
be conducting an open season, as well, for customers that want
to get right to the Alberta Hub.
1:35:40 PM
CO-CHAIR JOHNSON noted it is currently a 50/50 split on the $500
million incentive. He asked at what point it will become 90/10.
MR. PALMER explained that APP must expend the monies first. The
state then reviews those costs to determine whether they are in
compliance and, if so, reimbursement is at 50 percent of the
expended costs incurred up to July 31, 2010, the end of open
season. Post that stage, the state will reimburse up to 90
percent until the $500 million is reached, at which point the
state's contribution is capped but TransCanada's and
ExxonMobil's contributions are not.
1:36:58 PM
Mr. Palmer, in further response to Co-Chair Johnson, explained
that APP has so far received $1.1 million in reimbursement for
expenses incurred in first quarter 2009. Processing of the
reimbursement was slower than was hoped due to the state and APP
trying to resolve technical issues in transferring the
information on a computer basis. Last week APP submitted for
second quarter [2009] and will shortly be submitting for third
and fourth quarters [2009]. As of the end of December 2009, APP
has spent about $60 million. Thus, subject to the state's
review, reimbursement would be for the state's portion of $60
million. As APP has worked through the process with the state,
it has found some issues that are very challenging from an
administrative standpoint. Alaska Pipeline Project is not being
charged for items such as him, and therefore the state is not
reimbursing any of his costs for this project. This same
decision has been made for employee expenses to date because the
administrative burden was too great. Thus, the state's
reimbursement is actually less than 50 percent of APP's
expenditures; however, APP does expect the state will hit the
$500 million cap as the project moves forward.
1:39:21 PM
CO-CHAIR NEUMAN understood that the state's share of
reimbursement to APP is $30 million to date, after the contract
was signed between TransCanada and the State of Alaska, of which
APP has received only $1.1 million.
MR. PALMER replied yes, but he believes the state's
reimbursement will ultimately be less than 50 percent of $30
million because of the aforementioned items.
1:40:45 PM
CO-CHAIR JOHNSON inquired whether the state is on budget and has
enough to cover this cost.
PAT GALVIN, Commissioner, Department of Revenue (DOR), nodded
yes. In further response, he said the state is pretty close to
right on budget. He related that on [1/29/10], the Department
of Revenue distributed a report on the reimbursement fund with a
detailed list of the items that are part of the reimbursement.
He offered to answer follow-up questions after members have
looked at the report.
MR. PALMER added that the Alaska Pipeline Project has been very
pleased with its relationship with the administration while
trying to resolve how computers can talk to each other.
1:42:23 PM
MR. PALMER turned to slide 7 of his presentation regarding the
open season plan. Alaska Pipeline Project believes its
[1/29/10] FERC application offers a comprehensive, highly
credible, and competitive open season plan, he said. The
project believes TransCanada and ExxonMobil have unparalleled
expertise and experience in inter-state and inter-provincial gas
pipelines and gas treatment plants. In 2008 TransCanada stated
that it did not wish to construct the gas treatment plant
because that is not its area of expertise, he related. However,
it was a requirement of the AGIA application, and TransCanada
indicated it would proceed with the project even if it could not
find someone else to do the plant. Therefore, he is pleased to
tell members that ExxonMobil, the global leader in gas treatment
plants in TransCanada's opinion, is now a partner and the leader
in that side of the project. He further offered his belief that
TransCanada is the leading pipeline company in North America.
TransCanada moves 20 percent of the natural gas across the
continent every day and it has $17 billion-worth of pipelines
under construction now in Canada, the U.S., and Mexico.
TransCanada knows how to do the engineering and how to get the
regulatory approvals to proceed. A critical part of the
credibility of what the project is putting forward to members is
that customers are needed and regulatory approvals are needed.
When ExxonMobil joined the project it shared the producer study
from 2001, which is being used for the project. As a team,
TransCanada and ExxonMobil have done over one-quarter million
hours of engineering, regulatory, technical, environmental,
commercial, legal, and project management work to complete the
[1/29/10] FERC filing. This joint project work has provided
improved understanding of scope, costs, complexities, and risk
for this large, complex project.
1:45:17 PM
CO-CHAIR JOHNSON recalled that the 2001 study was a joint study
by all the producers. He asked whether the approximate $200
million for that study has been, or will be, submitted for
reimbursement.
MR. PALMER answered, "No, it will not; and no, it has not." He
recalled that the cost of the study was $125 million. Those
costs were incurred by ExxonMobil and other parties prior to the
license, he continued, and reimbursement is not being sought.
As well, TransCanada is not seeking reimbursement for the costs
it incurred under AGIA prior to the license. In further
response, he reiterated there will be no AGIA reimbursement for
the aforementioned $125 million study.
1:46:37 PM
REPRESENTATIVE SEATON, in regard to conditioned bids, noted that
the one condition being talked about is tax rates. He inquired
as to what conditions are generally received for large
pipelines.
MR. PALMER quipped that some of the project's potential
customers are in the room and he does not want to give them new
ideas. However, he said he is happy to outline those conditions
that are fairly standard during open seasons. First, customers
often want assurance that the pipeline company has all the
regulatory approvals for conducting business. That condition,
however, cannot be satisfied at the time where precedent
agreements are concluded because this project will have a FERC
filing in 2012 with a hoped-for approval by 2014. A second
standard condition is potential customers requesting that the
pipeline company improve the offer in some fashion. Sometimes
this can be done, and sometimes not; the project has done this
already. Another standard condition is that customers want to
be ensured their commitment is subject to the pipeline company
receiving sufficient volumes in total to make the project
economic. Lastly, it is standard for customers to want a
commitment that the pipeline will be in service by a particular
date or not before a particular date.
1:49:45 PM
REPRESENTATIVE TUCK recalled that Denali - The Alaska Gas
Pipeline provided its FERC pre-filing about a year ago and that
it was a new type of filing rather than a full filing. He asked
how the Alaska Pipeline Project's [1/29/10] filing compares to
Denali's.
MR. PALMER responded that Representative Tuck is right, Denali's
filing was very, very brief, just a few pages of documentation,
as was the case for APP's pre-filing a few months later. The
pre-filings kicked off the process where FERC assigned staff to
the project. However, the project's [1/29/10] FERC filing is
several hundred pages and comprehensively indicates the
project's capital costs, tariffs, commercial terms, terms and
conditions, design and engineering work, and so forth. All of
this information is also available to the public and it will be
used as the project goes forward in the open season. The
precedent agreements - the potential customer contracts - are
included in the filing, and that is a unique process that is not
normally shared at this stage with the public as it is normally
strictly between a pipeline company and its potential customers;
generally precedent agreements are not filed with FERC until
they are executed.
1:51:32 PM
REPRESENTATIVE TUCK inquired whether there is anything more that
TransCanada needs to do to meet the FERC filing requirements.
MR. PALMER replied that APP thinks it has met all the conditions
and therefore it is waiting to hear from FERC in 60 days. Mr.
Pike and his team have met with FERC staff a couple of times,
and while that does not predispose a final decision, APP
believes all the conditions have been satisfied.
1:52:18 PM
CO-CHAIR JOHNSON, in regard to the two kinds of open season -
binding and conditional - asked whether during this first open
season, a potential customer is bound to ship its gas if all of
its conditions are met.
MR. PALMER answered that this is a binding open season and
customers that commit their gas will take on significant
obligations to share development costs with the pipeline
company, provided the precedent agreement is resolved. However,
as is the case in almost every major pipeline project, the
customers preserve the right at final investment decision to
withdraw from the project, at significant financial cost to the
customer for doing so. This is laid out in the precedent
agreements that have been filed and this is the norm.
1:54:16 PM
CO-CHAIR JOHNSON surmised the conditions that will be received
will be very specific, so in a few months all the cards will be
on the table.
MR. PALMER presumed the co-chair is discussing a potential
condition with regard to upstream fiscal taxation.
CO-CHAIR JOHNSON said yes.
MR. PALMER said he cannot presume exactly what language a
particular customer will use if that is one of the customer's
conditions. The customer might say satisfactory to it as
opposed to a specific set of numbers. It is in the customer's
hands, not his, as to how the customer drafts its response to
the pipeline company. Alaska Pipeline Project, as per the
legislature's request, will not be engaged in those issues.
1:55:13 PM
CO-CHAIR JOHNSON stated that if the conditions are so vague, it
cannot be a terribly binding commitment for gas.
MR. PALMER responded that there will be some conditions the
pipeline company can resolve and those were described to
Representative Seaton. There will also be some the pipeline
company cannot resolve and in that circumstance then, yes, the
pipeline company will have to examine how it goes forward if
there is a request that that issue be resolved. If it is not
resolved the company has an obligation under AGIA to continue
for FERC application. So, the pipeline company may or may not
have binding obligations to customers if there is an outstanding
item that the company does not control.
MR. PALMER, in further response to Co-Chair Johnson, said Alaska
Pipeline Project is going through a binding open season and the
co-chair is describing a particular condition that a customer
may indicate in response to that open season. If the customer
wants a fiscal structure satisfactory to it, and if that has not
been resolved by the end of 2010, then clearly that is something
APP cannot resolve; APP will still proceed with the project, but
that commercial breakthrough will not have been achieved from
APP's standpoint. However, he is not suggesting that that is
the only condition that will be received in the initial open
season and this is why he is reluctant to say it is not a
binding open season; in many cases it will be a binding open
season, but in the particular case described, it may not be.
1:57:24 PM
CO-CHAIR JOHNSON inquired whether Mr. Palmer would consider it a
failed or a successful open season should the pipeline company
receive a conditioned bid for long-range tax concessions for
fiscal certainty so that there is not something the company can
take to the bank for financing.
MR. PALMER allowed that if that is the case at the end of the
period that is defined to resolve items, then it certainly is
not a completely successful open season. Alaska Pipeline
Project will have to determine at that time whether it is a
failed open season. If the state and producers are within a
short period of time of resolving it and have said so, then he
will not call it a failed open season. If, however, there has
been no progress and there is no hope on the horizon, then
perhaps it will be a failed open season.
1:58:28 PM
CO-CHAIR JOHNSON asked whether this means the legislature would
need to hold a special session given the timing of the open
season's closure.
MR. PALMER replied that the open season will conclude in July
2010, and if conditioned bids are received APP expects it would
take through the end of 2010 to resolve the conditions that are
in control of APP. However, the circumstance being described by
the co-chair is something APP clearly cannot control. If that
is a condition and the other items have been resolved, then APP
is in the state's and producers' hands as to when or if that is
ever resolved.
CO-CHAIR NEUMAN stated that at a later date the committee will
be hearing a presentation reviewing how open seasons work.
1:59:49 PM
REPRESENTATIVE GUTTENBERG inquired whether the FERC filing is
black and white in regard to the project's filing being either
approved or disapproved, or can FERC come back with something
that is conditional on terms that have yet to be done.
MR. PALMER said he thinks it is relatively black and white
because there are 21 conditions, which makes it relatively
procedural and straightforward. Perhaps FERC could come back
saying there is one condition that needs to be changed, but FERC
is not at this point commenting on the quality of APP's
commercial terms or capital estimate. Alaska Pipeline Project
thinks it will get approval in 60 days or shortly thereafter and
the open season conducted on the May-July schedule as described.
It will be during the 2012 filing for the certificate that FERC
will comprehensively review all items for the in-depth content
that is behind all of the materials, he added. During that
process it is not unusual for FERC to come back with conditions
that must be resolved to receive the certificate.
2:02:13 PM
REPRESENTATIVE GUTTENBERG noted that APP's slippage on the
projected open season coincides with the legislature's longer
period of time to approve the contract.
MR. PALMER answered yes; it was the administration and the
legislature. When the filing was made at the end of November
2007 the basis of the schedule was that the license would be
issued in April [2008]. The administration's recommendation
came in May 2008 and the legislature's review took nearly two
months. There were not enough votes in the legislature to
expedite that licensing process, so there was an additional lag
of 90 days. Thus, the license was received in December [2008].
The 100 business days is exactly the same as what was included
in the AGIA application. So, while this now happens to run
through the political timeframe, it had nothing to do with
[TransCanada's] plan in any fashion.
2:04:54 PM
REPRESENTATIVE OLSON surmised that on a project of this
magnitude and complexity, it is not unheard of to have two or
three failed open seasons before the kinks are all worked out.
MR. PALMER responded yes, as major projects are developed a re-
wind will occasionally happen. The magnitude of work that has
gone into the material that was just filed with FERC is unusual
at this stage; however, that does not mean APP will be
successful. Alaska Pipeline Project will go through the process
with a credible and competitive proposal and will do its best to
make it succeed, but it clearly takes two parties to make this
succeed - the pipeline company and potential customers.
2:06:09 PM
REPRESENTATIVE OLSON asked what the timeline would be for a
second open season if the first open season is a failure.
MR. PALMER replied that under AGIA the obligation is to go to
the market every two years to see if there are requirements for
gas service. However, if it is the situation described earlier
by Co-Chair Johnson, and all other issues have been resolved but
the fiscal issue, and then, for example, that fiscal issue is
resolved by the state and the customers in six months, the
pipeline company could act quickly and hold another open season
without waiting for two years.
REPRESENTATIVE OLSON presumed the 800-pound gorilla is the
fiscal terms.
MR. PALMER said that is clearly an issue that potential
customers have indicated publicly that needs resolution.
2:08:14 PM
REPRESENTATIVE P. WILSON inquired how substantial the penalty is
when a customer withdraws its bid from a project.
MR. PALMER explained that if a customer committed in the initial
open season, executed a precedent agreement with the pipeline
company, and then decided in 2014 to withdraw, the customer
would be obliged under the precedent agreement to reimburse the
company for the full development costs of the project. However,
if it is the pipeline company that decides to withdraw, there is
a sharing mechanism. So, the precedent agreement is truly
binding, and everyone involved in it, including the state, makes
a significant financial commitment.
REPRESENTATIVE SEATON stated that during the presentation on how
open seasons work, he would like to hear about the relationship
between the benefits of bidding at the initial open season and
at what point the advantages of bidding in the initial open
season get withdrawn from the parties.
2:11:18 PM
MR. PALMER continued his presentation (slide 8), stating that
the Alaska Pipeline Project is offering better commercial terms
and access than those included in the AGIA application. These
benefits are available to shippers that commit in the initial
open season because APP recognizes that it is facing a highly
competitive environment not just to move Alaska gas to market,
but also from other sources of gas that are competing both in
the Lower 48 and in global markets. He said comprehensive
Alberta and Valdez options are being offered that are responsive
to shipper discussions. Potential customers at Valdez requested
a 48 inch, 3.0 billion cubic feet per day (Bcf/d) pipeline to
Valdez, which is provided in APP's FERC application. Potential
customers requested access to other pipelines upstream of the
Alberta Hub rather than strictly going into TransCanada's system
at the Alberta Hub. Thus, while he believes that customers will
want to go into the Albert Hub, they will have the option to not
do this and to sell their gas in other markets through existing
infrastructure. A 25-year minimum contract term was included in
the AGIA application and that has now been reduced to 20 years.
Thus, a customer can select terms from 20 years to 35 years.
The project is also offering potential customers the enhancement
of short-term interruptible, overrun, and park-and-loan services
within Alaska or downstream. Additionally, APP is sharing
development costs in circumstances where APP terminates.
2:14:09 PM
MR. PALMER further pointed out that APP is offering better
commercial terms by $500 million per year. He put this into
context by explaining that the State of Alaska's total financial
commitment under AGIA is $500 million. These better commercial
terms reduce the tolls by $500 million per year over a 25-year
life. This is being done by reducing the return on equity (ROE)
to 12 percent. Also, through depreciation, APP will only
recover 80 percent of its initial capital through those initial
contract terms.
MR. PALMER, in response to Co-Chair Neuman, stated that in its
AGIA application, [TransCanada] provided a formulaic approach
that would have yielded a 14 percent ROE, and for capital
recovery had anticipated recovering 100 percent of the capital
over the initial contract term. Thus, the changes shift risk
away from the customers to the pipeline sponsors. Lastly, in
its AGIA application [TransCanada] had indicated that expansions
should be funded with 60 percent debt and 40 percent equity, and
30 percent equity is now being proposed. He explained that
equity yields a higher cost and higher income tax for customers
than debt, so a reduction in the amount of equity is a benefit
to customers and Alaskans and a detriment to the pipeline
owners.
CO-CHAIR NEUMAN remarked that competition is a good thing.
2:16:43 PM
CO-CHAIR JOHNSON asked what the life of the pipeline is
anticipated to be.
MR. PALMER answered it depends upon whether it is the physical
life or the economic life that is being described.
CO-CHAIR JOHNSON asked what happens after 20 years.
MR. PALMER said it depends. Physically, this pipeline will last
many decades. TransCanada has pipelines that have been in
service for 50 years and some in the Lower 48 that have been in
service for 60 years. In the event there is no more gas after
20 years, the pipeline would be retired and APP would not have
earned as much money as it had hoped. If there is lots more gas
in Alaska, which is what APP is hoping for, then either new
contracts or contract extensions would be obtained, in which
case APP will have the opportunity to receive a 12 percent
return.
2:18:03 PM
CO-CHAIR JOHNSON said that if APP is negotiating terms from a
pipeline that is already built, APP is holding all the cards.
Therefore, he is unsure that APP is mitigating risk as much as
it is shifting risk into year 2021. At that point, APP will be
the only game in town and in control of the math. He inquired
whether there will be an option that says the 12 percent ROE
will remain the same in the future.
MR. PALMER responded that the co-chair is doing exactly what he
would expect a sophisticated customer to do. Because APP has
already contemplated this, the 12 percent ROE and other terms
being offered will be available to customers for a renewal
period as well.
2:19:41 PM
CO-CHAIR JOHNSON argued that if there is gas after 20 years, APP
is not really mitigating the risk, it is shifting the risk.
MR. PALMER replied that with 10 years before in-service and 20
years later, there is huge risk as to whether the gas will be
available, the project economic, and that APP has completed the
capital cost with a reasonable amount of credibility. If APP
has not, the customers will have to pay the costs for that for
20 years. If APP has very high costs, then it would not likely
be competitive and the customers would be unlikely to renew.
Therefore, it is exactly opposite of the co-chair's description.
Alaska Pipeline Project is taking on that risk and he believes
the customers will look at that as a very attractive option
being put forward. He said he would be pleased to be on the
other side where it is the customers that are taking the risk,
which is what APP's original proposal was. Thirty years in time
may be quite different than today, he continued. For example,
35 years ago the price of gas in the Lower 48 was 44 cents per
million British Thermal Units (MMBtu). So, yes, he thinks APP
is taking on a lot of risk.
2:22:08 PM
CO-CHAIR JOHNSON asked what an 80 percent capital recovery will
do to Mr. Palmer's company if there is no gas in 20 years.
MR. PALMER answered that both companies, as well as any other
sponsors, will have repaid the debt to the banks and will have
received a much lower return than 12 percent.
CO-CHAIR NEUMAN recalled there are several off-ramps for
TransCanada Alaska, LLC. Everyone must work together to make
this happen, he said.
MR. PALMER clarified that if the project goes in service as he
has described, the sponsor's are taking the risk that in 20
years there will be additional gas and there will be customers
that will enable the sponsors to earn this 12 percent return,
otherwise that return will not happen.
2:23:40 PM
MR. PALMER returned to his presentation (slide 9), noting there
are two [48-inch] pipeline options [from Alaska's North Slope].
The [Alberta] option would deliver 4.5 Bcf/d of gas through a
1,700-mile-long pipeline to the Alberta Hub and pipeline systems
that serve the North American market. The Valdez option would
deliver 3.0 Bcf/d of gas through an 800-mile-long pipeline for
conversion to liquefied natural gas (LNG) at a plant to be built
by others and delivered [by ship] to U.S. or international
markets. Both options include: an opportunity for Alaska
communities to acquire natural gas from the pipeline via at
least five offtakes in Alaska, a huge world-class natural gas
treatment plant (GTP) for removing carbon dioxide and other
impurities located at Prudhoe Bay adjacent to existing
facilities, and an approximately 58-mile-long transmission
pipeline connecting the Point Thomson field to the plant.
2:26:07 PM
MR. PALMER, in response to Co-Chair Neuman, said there is no
question the $500 million cap from the state will be hit long
before APP is finished spending money on the development stage
to get to final investment decision. In further response, Mr.
Palmer said the project's expenditures will soon be seen in the
state's reimbursement document mentioned by Commissioner Galvin.
2:27:41 PM
MR. PALMER returned to his presentation and reviewed project
cost estimates and indicative tolls for the Alberta option
(slide 10). He noted that all of the costs he is presenting are
in 2009 dollars. The capital cost range is $32-$41 billion and
the target in-service for the project is 2020. He pointed out
that the gas treatment plant is the time-critical component of
this project as it is the sealifts that determine the ultimate
in-service date for this project, not the pipeline. The tariff
range, including fuel, is $2.80-$3.50 per MMBtu from the GTP to
the Alberta Hub. The Alberta Hub gas price, as forecasted in
December 2009 by the U.S. Department of Energy in its Annual
Energy Outlook, is $6.25-$7.65 MMBtu for the years 2020-2030.
Thus, the margin is about $3.00-$4.00 per MMBtu in netback,
which APP believes makes the project both technically and
commercially viable.
2:29:53 PM
MR. PALMER, in response to Representative Olson, said that 18
months ago the cost was $26 billion in 2007 dollars. In further
response, he explained that from 2007-2009, the cost of oil and
gas projects went up due to inflation in the industry. Also,
the U.S. dollar has deflated relative to other foreign
currencies, including the Canadian dollar. The majority of
costs will be in Canadian dollars, and when this is converted to
U.S. dollars it results in higher costs. While it was stated in
the filing that TransCanada did not plan to build a gas
treatment plant, a conceptual cost estimate was supplied that
was based on a two sealift season. However, after bringing in
an experienced partner in the gas treatment plant, it was
learned that three sealifts will be required, which
significantly increases the gas treatment plant cost.
Additionally, there is a modest other cost increase in the
pipeline. In further response, he assured Representative Olson
that Alaska will be getting a very high quality system, both in
the gas treatment plant as well as the pipeline.
2:32:32 PM
CO-CHAIR JOHNSON inquired what the tariff would be if all the
customers selected a 20-year contract as opposed to a 25-year
contract.
MR. PALMER estimated the tariffs for this shorter time period
would be approximately 15-20 cents higher for a 20-year
contract, but cautioned he is calculating this in his head.
CO-CHAIR JOHNSON asked whether this pipeline can be built
without gas from Point Thomson.
MR. PALMER responded that the pipeline company seeks to have
available to it all possible gas from existing fields as well as
to-be-found fields. However, APP is not in the position of
stipulating how much or whether gas will be available from any
particular field; that is the responsibility of the state, the
producers, and the Alaska Oil and Gas Conservation Commission
(AOGCC). He said the numbers seen here are calculated based on
4.5 Bcf/d of initial capacity and 4.5 Bcf/d for 25 years.
2:34:55 PM
MR. PALMER, in response to further questions from Co-Chair
Johnson, said Point Thomson gas would add 15-20 cents per MMBtu
to the numbers he has cited, given that gas from Point Thomson
adds an extra 58 miles as opposed to the customers coming on at
Prudhoe Bay. He said there will be no reimbursement from the
state's AGIA fund for the Point Thomson line because it was not
included in the AGIA application. It is known that there may be
gas available from Point Thomson and APP wants to attract that
gas. So, APP is offering service in the open season for that
piece of pipe for customers that have gas at Point Thomson.
Customers do not have to take it and the state will not be
reimbursing any monies for it.
2:36:34 PM
CO-CHAIR JOHNSON inquired whether there would be a tariff for
"ConocoPhillips, British Petroleum, or any of the other
producers" for gas that comes in from other fields at Prudhoe
Bay to this line.
MR. PALMER replied that other customers having gas outside of
Prudhoe Bay and Point Thomson could build a line to Prudhoe Bay
and pay for that line themselves. Or, they could ask APP to
provide that service and APP would consider that request. If
APP built a line for a customer, that customer would pay a
tariff.
MR. PALMER, in response to Co-Chair Johnson, clarified that only
customers moving gas from Point Thomson to Prudhoe Bay would pay
that 15-20 cents; customers having gas at Prudhoe Bay would not
pay that 15-20 cents. Thus, if APP builds a 58-mile pipeline
that moves 1.1 Bcf/d, a Point Thomson customer would pay $2.80-
$3.50, plus 15-20 cents, per MMBtu to move the gas from Point
Thomson to Prudhoe Bay.
2:38:55 PM
MR. PALMER, in further response to Co-Chair Johnson, recalled
that the players at Point Thomson include "ExxonMobil, BP,
Chevron, Conoco," as well as other players. If they choose to
nominate gas from Point Thomson Field and they want to move it
over to Prudhoe Bay to enter this major system, they will have
to pay the 15-20 cents. If they do not wish, or are unable, to
nominate Point Thomson gas, they will not pay the 15-20 cents.
CO-CHAIR JOHNSON asked whether TransCanada is going to build the
line between Point Thomson and Pump Station 1.
MR. PALMER answered yes, if customers nominate it, bid for it in
the open season, and request it. If they do not, then there
would be no customers and APP would not build it.
2:40:12 PM
CO-CHAIR JOHNSON inquired whether part of the partnership with
ExxonMobil is to build the line, given that ExxonMobil is the
driver here.
MR. PALMER responded yes, the Alaska Pipeline Project proposal
is offering service on that piece of pipe from Point Thomson
Field over to Pump Station 1, over to the gas treatment plant.
The two sponsor companies have asked APP to offer that service
not just to ExxonMobil, but to all parties that have gas in the
field.
2:40:51 PM
REPRESENTATIVE OLSON asked whether there will be a decision from
AOGCC by the time the open season is held on what can actually
be taken out of Point Thomson.
MR. PALMER replied he does not have that answer and the question
should be posed to AOGCC. He has no insider information as to
how and when AOGCC will make that decision, given that that is
not something a pipeline would normally be involved with.
However, it is certainly something APP is interested in.
REPRESENTATIVE OLSON commented he is unsure whether there is a
timeline on the AOGCC for that decision.
CO-CHAIR NEUMAN related that Commissioner Galvin is shaking his
head no.
2:41:57 PM
REPRESENTATIVE P. WILSON posed a scenario in which oil is found
at Point Thomson and there is gas, but the gas cannot be taken
until some years later. She asked whether a customer can apply
for open season and specify that the gas would not be available
until a certain later date.
MR. PALMER said the answer is generally yes, but it will have an
impact on the structure of the tolls unless APP has 4.5 Bcf/d
from other locations that can fill the pipe prior to Point
Thomson becoming available. The tariffs would have to be re-
calculated by APP should there be, say, 3.5 Bcf/d for two years
and then 4.5 Bcf/d after that.
2:43:32 PM
MR. PALMER, in response to Co-Chair Neuman, agreed that these
tariffs are based on the liquids contents in the gas after
having had discussions with the field operators. It is the
customers' decision as to where those liquids are removed, and
removal of the liquids at a particular location will have an
impact on the toll because the tolls shown in this presentation
are in a heating content of one million Btu's per day.
2:46:36 PM
REPRESENTATIVE TUCK inquired whether there is a possibility that
a pipeline could be built to Alberta in addition to a pipeline
to Valdez, or must it be one or the other.
MR. PALMER responded that APP has defined a proposal for 4.5
Bcf/d to Alberta and 3.0 Bcf/d to Valdez. Alaska Pipeline
Project does not believe there is 7.5 Bcf/d of gas to be
committed at the end of this open season to allow both pipes to
be constructed immediately; thus, APP thinks it is "either or."
If one alternative succeeds and moves forward, there is always
potential to expand that option or have a Y-line in the future.
At the moment, APP must succeed at getting one of the
alternatives over the finish line so there is a volume that
works to either Valdez or Alberta. Once a pipeline is in
service, it can draw on more exploration and additional gas that
might allow both markets to be served in the future, or it might
allow expansion of the original pipe to the original
destination.
2:48:45 PM
REPRESENTATIVE TUCK posed a scenario of having a total of 5.5
Bcf/d committed, and asked whether a branch of 1.0 Bcf/d could
then go off to Valdez.
MR. PALMER replied that APP is always willing to look at an
option, and 5.5 Bcf/d going to market would be a good option and
a happy outcome. In this case the tolls would be different than
what are currently being described for the two alternatives.
2:50:40 PM
MR. PALMER returned to his presentation and illustrated how gas
price forecasts have changed since the AGIA filing (slide 11).
The U.S. Department of Energy produces an Annual Energy Outlook
(AEO) every year in December, he explained. When APP made its
filing in November 2007, the AEO 2007 was from December 2006,
which is depicted by the [black] line on the graph. In real
2009 dollars, the gas price forecast for 2020 by AEO 2007 was
about $5.75 per MMBtu and for 2030 the forecast rose to about
$6.60. The AEO 2008 gas price forecast, depicted in blue, was
slightly higher. The AEO 2009 was actually done in April 2009
because the U.S. Department of Energy did not have a lot of
credence in its December 2008 numbers because of the volatility
at that time and decided to do an update. The AEO 2009,
depicted in green, shows a significantly higher forecast of
about $7.20 per MMBtu for 2020 and about $8.60 for 2030. The
AEO 2010, which was completed in December 2009 and is depicted
in red, forecasts a gas price of about $6.25 for 2020 and about
$7.65 for 2030. Thus, the most recent forecast, while down from
2009, is still about 60 cents per MMBtu higher than what was
forecast at the time of the AGIA application, which helps with
the project's viability.
2:53:41 PM
MR. PALMER, in response to Co-Chair Neuman, noted that natural
gas is one of the most volatile commodities, if not the most, in
terms of price, even more so than oil. It is APP's view as the
pipeline sponsor that the project is viable. However, it is up
to the customers to decide their own views in that initial open
season, given that it will be the customers' risk as to the
ultimate commodity price of the gas that will be delivered in
the marketplace.
2:54:35 PM
CO-CHAIR NEUMAN inquired whether there is any way to look at
these graphs with a hedge. He further asked what the general
expectation is for return on equity.
MR. PALMER said that since he is not a producer he will not give
a forecast as to what expected return producers may need. In
regard to the ability to hedge, he understood it is very
difficult to hedge beyond five years out for any significant
volume. Parties committing to this project this year would be
committing to a gas price forecast commencing in 2020 and
continuing for 20-30 years thereafter. Thus, he does not think
they can realistically hedge that risk this year.
MR. PALMER, in further response to Co-Chair Neuman, said that
once the project is near in-service and certainly for the first
few years of operation, customers could, if they wished, hedge
early years of the project, assuming the markets in 10 years
time are just like they are now. However, customers still could
not hedge for a time period as long as 20 years.
2:58:09 PM
REPRESENTATIVE P. WILSON commented that another risk is the
possibility of an alternative energy source coming into use.
MR. PALMER agreed this is another very significant risk. He
noted that the U.S. Department of Energy does try to account for
this in its AEO forecasts. All parties committing to this
project - producers, the state, APP, and others - are taking on
significant risk, but that is the nature of the business. The
flip side is the potential for large reward. If gas prices turn
out to be as forecast, there would be a $3-$4 margin times 25
years, which is about $120-$150 billion in value after paying
for the transportation costs.
MR. PALMER, in further response to Representative P. Wilson,
said the Canadian government also has an energy price forecast,
as do many consultants on a proprietary basis for their clients.
The AEO 2010 forecast is in the range of a lot of forecasts,
although that does not mean there are not differing forecasts
and it does not mean that it is necessarily correct.
3:01:36 PM
REPRESENTATIVE GUTTENBERG requested Mr. Palmer to discuss his
perspective on the [Mackenzie Gas Project that is being proposed
through the Mackenzie Valley of Canada's Northwest Territories].
MR. PALMER noted this is a topic on which he will be careful
with his response. He said it is TransCanada's belief, and
probably ExxonMobil's as well, that both projects are not
restricted by lack of demand, but the flip side is there is no
guaranteed market for either pipeline except local uses. Both
projects will have to compete in the marketplace just like other
sources of gas and they will compete on price given that natural
gas is such a fungible commodity - all gas, regardless of
source, looks and burns the same, so it is the price delivered
in the marketplace where it must compete. The market throughout
North America is highly liquid and once the gas is into major
hubs like Alberta or the Lower 48, it must compete effectively
on cost. The question is whether the gas can be competitive at
the market price that is established since neither project
drives that price. In his view, both the Mackenzie and Alaska
projects will go forward based on regulatory and commercial
breakthroughs for each project. They are on totally independent
tracks and are not linked. One or both can succeed, or one or
both can fail based on how they do on those regulatory and
commercial breakthroughs. The Mackenzie project is at a
different stage than this Alaska project. The Alaska project is
going through Canada under the Northern Pipeline Act, which is
an act specific only to the APP. The Mackenzie project is
through an application to the National Energy Board that was
made in October 2004. At that time the Mackenzie project had
all its customers in hand, but six years later it is still
waiting for regulatory approval which is expected this fall.
Mr. Palmer disclosed that TransCanada has a 5 percent interest
in the Mackenzie project and is also funding the Aboriginal
Pipeline Group, a one-third potential owner in that project.
Thus, TransCanada is highly interested in, but not driving, the
Mackenzie Gas Project.
3:06:04 PM
MR. PALMER, in response to Representative Olson, stated that the
APP has started to have discussions with the British Columbia
First Nations. He said he will not go into the Yukon
circumstance since he has had that discussion with
Representative Olson before. He said British Columbia is what
he would call "traditional pipelining territory" with thousands
of miles of existing pipeline. Currently, TransCanada has
applications to extend its Alberta system into British Columbia
to move British Columbia shale gas over the next several years.
All items are not yet resolved, but he thinks they are
resolvable issues. In further response to Representative Olson,
Mr. Palmer said he does not see much difference for this project
with the First Nations than 18 months ago, but TransCanada's
intention is to construct pipelines into British Columbia in the
next two to five years, something it was not doing a couple of
years ago. Discussions are ongoing with those parties now.
CO-CHAIR NEUMAN said this is a serious issue because Alaska's
future is riding on these folks.
[Mr. Palmer's presentation was continued on 2/3/10.]
3:08:45 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:09 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| TCPalmerHRES_SRES_SENG_HENG_2_1_2010 FINAL V2.ppt |
HRES 2/1/2010 1:00:00 PM |