Legislature(2009 - 2010)Anch LIO Rm 220
06/23/2009 09:00 AM House RESOURCES
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| Start | |
| Overview(s): Transcanada and Exxonmobil Partnership Regarding the Agia Natural Gas Pipeline | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
JOINT MEETING
HOUSE RESOURCES STANDING COMMITTEE
HOUSE SPECIAL COMMITTEE ON ENERGY
Anchorage, Alaska
June 23, 2009
9:02 a.m.
MEMBERS PRESENT
HOUSE RESOURCES
Representative Craig Johnson, Co-Chair
Representative Bryce Edgmon
Representative Kurt Olson
Representative Paul Seaton (via teleconference)
Representative David Guttenberg (via teleconference)
Representative Scott Kawasaki
Representative Chris Tuck (via teleconference)
HOUSE SPECIAL COMMITTEE ON ENERGY
Representative Bryce Edgmon, Co-Chair
Representative Charisse Millett, Co-Chair
Representative Nancy Dahlstrom
Representative Jay Ramras
Representative Pete Petersen
Representative Chris Tuck (via teleconference)
MEMBERS ABSENT
HOUSE RESOURCES
Representative Mark Neuman, Co-Chair
Representative Peggy Wilson
HOUSE SPECIAL COMMITTEE ON ENERGY
Representative Kyle Johansen
OTHER LEGISLATORS PRESENT
Representative John Coghill
Representative Mike Chenault
Representative Lindsey Holmes
Representative Harry Crawford
Representative Bob Buch
Representative Bob Herron
Representative Mike Kelly (via teleconference)
Representative Mike Hawker
Representative Bob Lynn
COMMITTEE CALENDAR
OVERVIEW(S): TRANSCANADA AND EXXONMOBIL PARTNERSHIP REGARDING
THE AGIA NATURAL GAS PIPELINE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
TONY PALMER, Vice President
Alaska Business Development
TransCanada Alaska Company, LLC (TransCanada)
Calgary, Alberta Canada
POSITION STATEMENT: Testified as one of the presenters of the
overview regarding the natural gas pipeline under the Alaska Gas
Inducement Act (AGIA).
MARTIN MASSEY, U.S. Joint Interest Manager
ExxonMobil Production Company (ExxonMobil)
Houston, Texas
POSITION STATEMENT: Testified as one of the presenters of the
overview regarding the natural gas pipeline under the AGIA.
PAT GALVIN, Commissioner
Department of Revenue (DOR)
Juneau, Alaska
POSITION STATEMENT: Provided testimony and answered questions
on the Denali Alaska Gas Pipeline project on behalf of DOR.
MARTY RUTHERFORD, Deputy Commissioner
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Provided testimony and answered questions
on the Denali Alaska Gas Pipeline project on behalf of DOR.
BUD FACKRELL, President
Denali-The Alaska Gas Pipeline (Denali)
Anchorage, Alaska
POSITION STATEMENT: Testified and answered questions on the
Denali Alaska Gas Pipeline project.
CLAIRE FITZPATRICK, Senior Vice President, Chief Financial
Officer
BP Exploration (Alaska) Inc. (BP)
Anchorage, Alaska
POSITION STATEMENT: Provided testimony and answered questions.
WENDY KING, Director of External Strategies
ANS Gas Development Team
ConocoPhillips Alaska, Inc.
Anchorage, Alaska
POSITION STATEMENT: Provided testimony and answered questions.
ACTION NARRATIVE
9:02:56 AM
CO-CHAIR CRAIG JOHNSON called the joint meeting of the House
Resources Standing Committee and the House Special Committee on
Energy to order at 9:02 a.m. Present at the call to order from
the House Resources Standing Committee were Representatives
Johnson, Olson, Seaton (via teleconference), Edgmon, and
Kawasaki; Representatives Guttenberg (via teleconference) and
Tuck (via teleconference) arrived as the meeting was in
progress. Present from the House Special Committee on Energy
were Representatives Edgmon, Millet, Dahlstrom, and Peterson;
Representatives Ramras and Tuck (via teleconference) arrived as
the meeting was in progress. Representatives Coghill, Chenault,
Holmes, Crawford, Buch, Herron, Lynn, Kelly (via
teleconference), and Hawker were also in attendance.
^Overview(s): TransCanada and ExxonMobil Partnership Regarding
the AGIA Natural Gas Pipeline
9:03:28 AM
CO-CHAIR JOHNSON announced that the only order of business is a
presentation regarding the TransCanada and ExxonMobil
partnership as it relates to the Alaska Gasline Inducement Act
(AGIA) natural gas pipeline.
CO-CHAIR JOHNSON noted that the presenters have confidentiality,
proprietary, and regulatory constraints, and asked members to
respect those constraints.
9:06:30 AM
TONY PALMER, Vice President, Alaska Business Development,
TransCanada Alaska Company, LLC (TransCanada), began his
PowerPoint presentation by explaining that ExxonMobil Production
Company (ExxonMobil) is actively participating in the joint AGIA
project; that the joint project team is separate from and
independent of ExxonMobil's producing and marketing interests;
and that the lead manager for the project, an ExxonMobil
employee, will report directly to the management committee,
which he himself will chair.
9:08:11 AM
MR. PALMER stated that TransCanada and ExxonMobil have reached
agreement to work together on TransCanada's Alaska Pipeline
Project [slide 2]. There is already immediate ExxonMobil
participation and project support via integrated teams working
to advance the project. Both companies will jointly advance all
aspects of the project - technical, commercial, regulatory,
financial, and so forth. ExxonMobil is contributing prior study
results and existing right-of-way (ROW) data, thus eliminating
the need for TransCanada to reproduce that work. He also said
that TransCanada and Foothills Pipe Lines Ltd. remain the Alaska
Gasline Inducement Act (AGIA) licensees; that the rights and
obligations under the AGIA are unchanged and remain with the
licensees; that ExxonMobil is ready to work with the State of
Alaska to enable full participation in the AGIA license; and
that the project schedule is unchanged; for example, the initial
open season is still targeted for completion by July 2010.
9:10:25 AM
MR. PALMER said the AGIA project scope is unchanged and includes
a gas treatment plant (GTP) and a pipeline from Prudhoe Bay to
Alaska delivery points [slide 3]. Liquefied natural gas (LNG)
will be provided to Lower 48 or Asian markets via Valdez, or to
Lower 48 markets via the Alberta Hub. Furthermore, outside of
the AGIA project and thus ineligible for AGIA reimbursement will
be the advancement by TransCanada and ExxonMobil of an upstream
gas transmission pipeline from Point Thomson to the GTP; that
section of pipe will be offered for service to potential
customers during the open season.
9:11:26 AM
[Not on the official recording, but reconstructed from an
alternate recording, was the following short bracketed
statement]:
MR. PALMER said:
[The current alignment between TransCanada and
ExxonMobil] is not contingent on any commitments by
the state, and we can progress the project
independently, if we so elect, using all jointly-
developed assets and information. Clearly it's our
goal, over time, to develop this project jointly with
ExxonMobil to successful completion. In the event
that we come apart for any reason, the jointly-
developed assets will be on our hands, and we'll be in
a position to use them to complete the project.
9:11:51 AM
MR. PALMER, on the issue of legislation and regulation, said
TransCanada will use the 2004 Alaska Natural Gas Pipeline Act
(ANGPA) in Alaska and the Northern Pipeline Act in Canada [slide
4]. TransCanada has increased the up-front spending to $150
million, and this additional front-end spending reflects
increased emphasis on early execution and construction planning,
additional efforts in regulatory, environmental, and land areas,
as well as the size, complexity, and execution challenges of the
gas treatment plant (GTP). The legislature has appropriated
about $45 million to date for this project, and TransCanada's
expectation is that this amount will be sufficient to cover
Alaska's share of the project through [this interim]. The
development costs will be shared between TransCanada and
ExxonMobil, and the two companies will retain the majority
interest, with the state's total reimbursement contribution of
up to $500 million to remain unchanged.
9:13:12 AM
MR. PALMER explained that subsequent to the legislature's
approval of issuing the AGIA license to TransCanada, ExxonMobil
commenced the discussions and negotiations between Fall 2008 and
May 2009 [slide 5]. These negotiations resulted in an agreement
between the two corporations. TransCanada advised the state
administration of these actions, but did not divulge the nature
or details of the negotiations, he said. However, at the point
TransCanada met with its board, TransCanada, under AGIA, had an
obligation to share the information with the state, and did so
in early May, including sharing the details of the structure of
the arrangement between TransCanada and ExxonMobil. However,
TransCanada did not believe this constituted a project change,
which would have required approval by the state's
administration. He emphasized that TransCanada did not find the
negotiations to constitute a contract change. Subsequently,
after six weeks of review the state ultimately agreed that no
action was necessary. He recapped the "Bottom Line" on slide 5,
such that TransCanada believes that real progress has been made
to align the all parties for a successful project. He opined
that the combination of these companies brings unrivaled
expertise and experience to the project, and all share a common
goal, which is realization of an Alaskan pipeline project.
MR. PALMER offered to proceed to the more complex topic of the
structure of the arrangement between TransCanada and ExxonMobil.
9:15:47 AM
CO-CHAIR JOHNSON asked about the assets that ExxonMobil brings
to the project, particularly the right-of-way of the Trans-
Alaska Pipeline System (TAPS) information, and if the right-of-
way costs will be a reimbursable expense. He said he thought
the TAPS reimbursable expense has already been paid through
tariffs. Thus, he surmised the information is owned by several
companies and asked for the arrangement of how that would be
shared. Further, he asked for clarification of how the
producers could share something that technically belongs to a
third party, which is TAPS. He said he did not expect an
immediate answer to these questions.
MR. PALMER offered to begin to answer the questions, but added
that Mr. Massey, ExxonMobil, could also expand on his answer.
He explained that the assets would not be reimbursable expenses,
but would be contributed to the project. Thus, the Alaska North
Slope (ANS) producer's study that ExxonMobil brings to the table
will not be reimbursable by AGIA participants. He reminded
members that only expenditures after December 5, 2008, are
reimbursable under AGIA. He restated that none of the costs
that TransCanada has incurred prior to December 5, 2008, are
reimbursable. Further, the TAPS information is not reimbursable
under the $500 million AGIA legislation.
CO-CHAIR JOHNSON acknowledged the distinction for what is
reimbursable, but related his understanding that the assets
would be an expense to TransCanada. He said he anticipated that
these costs would be rolled into the tariffs, which for a
project of its size, the $100 million is not significant.
However, he understood that the TAPS information has already
been paid for in tariffs. He asked whether it would constitute
a duplicate cost if the TAPS information is also rolled into the
gas tariffs. He realized the administration may need to answer
this question as, from inception, the legislature has been
advised to contain costs for the pipeline.
9:18:32 AM
MARTIN MASSEY, U.S. Joint Interest Manager, ExxonMobil
Production Company (ExxonMobil) replied that clearly the TAPS
information expense is not reimbursable under AGIA provision.
However, the question of whether TAPS information will be valued
in the tariff is a question that ExxonMobil cannot yet answer.
ExxonMobil will make the case, if there is a case to be made,
that TAPS information should be valued. Further, the Federal
Energy Regulatory Commission (FERC) will ultimately decide if it
is a legitimate expense, and whether the TAPS information has
been already been paid. He added that all expenses included in
the tariff will need to be qualified by FERC. However, this
will be a future decision and the parties have not, as part of
this agreement, made any consideration that the TAPS information
is a value that must be included in the tariffs.
9:19:46 AM
REPRESENTATIVE PETERSEN recalled testimony that TransCanada
plans to build a pipeline from Point Thomson to the gas
treatment plant (GTP). He asked if the route and pipeline size
have been identified.
MR. PALMER answered that work is currently underway and will be
completed when the rest of the design work is done and that this
information will be available for parties next year. While the
initial assessment has been done and the route and pipeline size
is generally known, it has not specifically been determined.
CO-CHAIR MILLETT asked whether the line from Point Thomson to
connect to the pipeline is a reimbursable cost through the AGIA
process.
MR. PALMER answered no. He related that the line was not part
of the application process under AGIA so it will not qualify as
expenditures and is not reimbursable.
CO-CHAIR JOHNSON recalled testimony that the producers would
have an option to use the pipeline or the GTP. If producers do
not choose to do so, what other options would be available to
them.
MR. PALMER clarified that he was referring to not currently
knowing the location of gas sources from producers or any
potential customers. He pointed out that some parties might
have a gas source at Point Thomson while others may solely have
a supply at Prudhoe Bay. If the gas source is at Point Thomson,
and the producers chose to use the main pipeline and the GTP,
they would likely select usage of the pipeline. Otherwise,
these producers would be in a position to build their own line,
he added.
CO-CHAIR JOHNSON stated that the line does not concern him since
it is a relatively small cost, but the gas- to-liquids (GTL)
option does. He inquired as to whether the producers would also
have an option to build their own GTL plant.
MR. PALMER answered that the pipeline will require pipeline
quality gas. Thus, if the gas comes from Prudhoe Bay, it will
be necessary to remove the carbon dioxide. In the event the
producers elect not to use the plant, the gas would need to be
gas that does not require treatment or they must seek an
alternative to the proposed GTP, which is always an option for
potential customers. In further response to Co-Chair Johnson,
Mr. Palmer clarified producers would need to use the proposed
GTP plant, build another GTP plant, or transport gas that is
pipeline quality gas.
9:22:30 AM
MR. PALMER continued. He detailed the "Project Framework"
between the two companies listed on slide 6 of his presentation.
He stated the objectives are clear - to perform the necessary
work to facilitate completion by TransCanada licensees of open
seasons in Canada and the U.S. by the July 2010 target date.
Additionally, another objective is to continue to pursue the
regulatory authorization for pipeline construction. He offered
to walk members through the flowchart beginning at the right
side [of slide 6]. He stated that TransCanada and ExxonMobil
have reached an Interim Project Agreement (IPA) to complete the
project work and transfer that project work to the AGIA
licensees, which is depicted by an arrow. The AGIA licensees
will transfer back the parties' non-voting interest. Thus,
TransCanada would retain 100 percent of the voting interest as
the AGIA licensee. However, TransCanada's subsidiaries, as well
as ExxonMobil, will be earning nonvoting interest. In the event
ExxonMobil resolves all issues with the state and ExxonMobil
becomes a full participant, the nonvoting interests will be
converted into voting interest, and ExxonMobil would become a
full participant, or basically a common shareholder of the AGIA
licensee.
9:24:47 AM
REPRESENTATIVE RAMRAS asked when questions could be directed to
the leaseholder.
MR. MASSEY explained that the structure is under discussion.
Once that is completed, the leaseholder will be better able to
answer questions. After the structure discussion, he planned to
leave in order to allow TransCanada to provide an update on the
specific TransCanada project. Since ExxonMobil is currently
becoming a shipper/producer, in that status he is not entitled
to any special preference. Thus, ExxonMobil will be party to
information at the same time as any other shipper or producer.
He offered to answer questions after Mr. Palmer has completed
his discussion on the project framework.
CO-CHAIR JOHNSON noted that the FERC requirements were discussed
and agreed this is an area that will require care be taken.
9:26:10 AM
MR. PALMER went on to explain that those AGIA licensees will
then determine and submit any qualified expenditures for
reimbursement. Once reviewed and approved by the state,
reimbursements will be made to the AGIA licensees and will flow
through to the ExxonMobil entity. Thus, as the TransCanada and
ExxonMobil entities incur the costs, the reimbursement will be
shared by the parties.
9:27:03 AM
MR. PALMER elaborated that the IPA establishes the basis under
which TransCanada and ExxonMobil work together [slide 7]. He
identified that the Project Funding Agreements (PFAs) are
companion agreements to IPA, and are executed simultaneously
with IPA, with a separate PFA for the U.S. and Canada since they
are separate licensees. He noted that the PFAs provide a bridge
between the TransCanada licensees and IPA parties. The
TransCanada licensees maintain the interface with the state and
retain AGIA obligations, while the TransCanada licensees
maintain sole discretion over the request for reimbursement for
qualified expenditures.
MR. PALMER related that he already addressed the first bullet on
the top of slide 8, a continuation of the project framework,
such that TransCanada's licensees will have the right to all
work provided to them by IPA parties for purposes of meeting the
TransCanada obligation under the AGIA license. He highlighted
that this is critical, not only for the project completion, but
also under AGIA, and under certain circumstances the state would
have the right to take over and will need to have those assets.
MR. PALMER continued. He said that all major project
components, including regulatory filings and open season
contracts will be made or entered into in the name of and on
behalf of the AGIA licensees. The AGIA licensees have the
right, at all times, to progress the project alone, if they so
choose. He added that clearly that is not TransCanada's intent,
but they do have a right to all the jointly-developed assets and
both parties will retain rights to the project information. The
parties have agreed to a reasonable transition period to sole
management by TransCanada in the event of a termination. Thus,
ExxonMobil could not pull up stakes if it terminated its
affiliation, but would need to provide a reasonable transition
period for an orderly management of the project. The parties
will earn nonvoting interests in the TransCanada licensees upon
transfer of the work product, he stated.
MR. PALMER continued with the project framework [slide 9]. Once
ExxonMobil is a participant in the TransCanada's license,
nonvoting interests will convert automatically to voting
interests in the licensees. State reimbursements will be
distributed in proportion to their participating interests in
the IPA. The IPA includes the typical joint venture terms, and
in terms of the structure of the management of the project,
TransCanada and ExxonMobil have fully integrated teams engaged
on the project.
9:29:32 AM
CO-CHAIR MILLETT asked for clarification of what it means to
have ExxonMobil become a participant in the TransCanada license.
MR. PALMER explained that as the legislature is aware,
ExxonMobil must resolve some issues with the state before it
becomes a full participating party in the AGIA licensees. He
stressed that if ExxonMobil resolves its issues, then ExxonMobil
will become a voting shareholder in TransCanada's licensees.
While ExxonMobil does not currently hold that status, ExxonMobil
is earning nonvoting interest which is, in effect, a financial
interest rather than a voting interest. However, once the
issues are resolved ExxonMobil will convert to a full common
shareholder with financial voting interest.
9:30:38 AM
CO-CHAIR MILLETT asked for clarification of unresolved issues.
MR. MASSEY explained that, first, it is important to note that
TransCanada's obligations under AGIA are unchanged with this new
relationship. He stated TransCanada is fully committed to meet
its AGIA obligations. Secondly, ExxonMobil has come to
understand that the state has approved AGIA, that the
administration and the legislature represent the preferred
process for an Alaskan pipeline project. In order to be
successful in the project ExxonMobil must work within that
framework. He emphasized that ExxonMobil needs to have
predictable and durable fiscal terms as a condition of any
project in the world of this magnitude. He restated that
ExxonMobil realizes that working through AGIA is the means to
achieve the project. The good news is that ExxonMobil is
working with TransCanada to progress the project and is willing
to work parallel to the state to address the fiscal terms. He
offered his hope that ExxonMobil achieves confidence with the
technical work done during the open season, and if so, the only
remaining issue will be to assess predictable and durable fiscal
terms.
9:32:14 AM
MR. MASSEY, in response to Co-Chair Millett, reiterated that no
conditions were necessary in order to join TransCanada.
However, ExxonMobil hopes that by working with TransCanada and
the AGIA process, it can address durable and predictable terms,
he said. He defined durable and predictable terms as everything
in AGIA or not in AGIA that relates to understanding whether the
project will be a viable project. In other words, he asked
whether ExxonMobil could predict reasonably well what the taxes
and the state take will be such that ExxonMobil can make a
determination about the viability of the project. He related
that if it is in the AGIA and relates to the overall state take
and how the state's return might be influenced over time then
yes that would be something to discuss with the state.
CO-CHAIR MILLETT clarified her interest is in knowing if other
issues within the AGIA framework should be addressed for
ExxonMobil as a producer or shipper.
MR. MASSEY responded that ExxonMobil appreciates what the state
would like to achieve under the AGIA process. He opined that
working with TransCanada, ExxonMobil can meet the state's goals
under AGIA as well as TransCanada and ExxonMobil's needs. He
said, "That is our hope and that's what we're going to try to
work toward in achieving with our discussions with the state."
9:34:34 AM
REPRESENTATIVE RAMRAS remarked that he is glad ExxonMobil is at
the table. He questioned whether ten years [of unchanged state
taxes in AGIA] would qualify as a definition for durable.
MR. MASSEY answered that there is a moral obligation for the ten
years in AGIA. He interpreted the AGIA statutes to mean that
the state will make an effort to avoid changing the terms within
the ten years, but not a guarantee since nothing in AGIA
prevents the state from changing the terms within the ten year
period. He stated that he likes the dictionary definition of
durable, which is lasting and enduring, but whether that
translates to ten years, or to a longer period is a matter that
ExxonMobil will need to discuss with the state.
REPRESENTATIVE RAMRAS surmised that ten years is not good
enough, but also that the state may extend terms for a longer
period. He related his understanding that ExxonMobil "Mid-
stream Gas Investments LLC" is interested in the GTP, while the
larger ExxonMobil entity would be willing to talk to the state
about the ten-year term contained in AGIA, with perhaps some
implied notion that the terms would be extended for a longer
period.
MR. MASSEY clarified that he was referring to the
producer/shipper who would commit the gas to the project. With
respect to the issue of the pipeline, he said ExxonMobil and
TransCanada hold the same view: that this issue needs to be
worked on between the state and the shippers to insure a
successful open season. He offered his belief that the 10 year
period is not sufficient, but the 35 years previously agreed to
was enough. The question remains as to what the terms will be
for this pipeline, but the open dialogue continues.
9:37:52 AM
REPRESENTATIVE DAHLSTROM asked whether ExxonMobil will have
equal voting rights with TransCanada.
MR. PALMER explained that in the event ExxonMobil resolves its
issues with the state and converts from nonvoting to voting,
TransCanada will retain the majority, and ExxonMobil will hold a
minority voting interest.
9:38:28 AM
CO-CHAIR JOHNSON related his understanding that TransCanada
either pre-filed or would ask to pre-file with FERC. He asked
whether FERC will require TransCanada to modify its application.
MR. PALMER explained that TransCanada pre-filed with FERC at the
end of April 2009. That pre-file application was made under
TransCanada's name, which is the entity that will move forward,
although ExxonMobil will contribute to the work jointly with
TransCanada. He said that TransCanada licensees will still
pursue all the regulatory applications and contracts with
customers in their own name. He clarified that applications and
contracts would be pursued in the name of the AGIA licensees and
no issue has arisen with the FERC.
MR. PALMER continued. He stated that approximately 70 people
are currently working on fully integrated teams staffed by
TransCanada and ExxonMobil, with ExxonMobil as the IPA lead and
TransCanada as the sub-IPA lead for the Canadian portion of the
project. He related that TransCanada is primarily responsible
through the open season for the overall pipeline and compression
work, while ExxonMobil will be responsible for the GTP. Thus,
the bulk of TransCanada's employees will work on the pipeline,
but will be supplemented with ExxonMobil, and conversely
ExxonMobil employees will primarily handle the GTP, supplemented
by TransCanada's staff. He identified Paul Pike as the IPA lead
who will report to the management committee, currently chaired
by him. The management committee will have representatives from
ExxonMobil and TransCanada, and project costs will be jointly
funded based on the parties' proportionate shares.
9:40:56 AM
MR. PALMER, stated that TransCanada believes this addition
represents real progress to align all essential parties for a
successful project [slide 10]. Last summer TransCanada was
successful in obtaining the legislature's approval for the
license issued on December 5, 2008. He recalled that ExxonMobil
testified that joining TransCanada supports the progress of the
project under AGIA and their willingness to become a full
participant in those licensees. He remarked that in the event
discussions occur between ExxonMobil and the state, that
TransCanada will not be a party to the discussions, but will
remain an interested observer.
9:41:53 AM
CO-CHAIR MILLETT recalled that immediately after the AGIA
license was signed, TransCanada's chief executive officer (CEO)
stated that nothing moves forward unless ExxonMobil is happy.
She asked for clarification of what that statement would mean.
MR. PALMER interpreted that what TransCanada's CEO meant by the
statement is that during any major pipeline project some
alignment must occur between the principal producers in the
basin. Potential shippers must be aligned in some fashion or
there will not be a successful project. He recalled his
frequent testimony that TransCanada needs customer contracts and
regulatory approval. Thus, what TransCanada's CEO recognized in
his statement is that ExxonMobil is the largest holder of
discovered reserves on the North Slope of Alaska. Therefore,
TransCanada needs alignment with ExxonMobil, as well as with the
other two producers. TransCanada seeks that approval. He
stated that while he would not speak to what brought ExxonMobil
to the table, TransCanada is very pleased. TransCanada is in
the position of providing a credible cost estimate for third
party producers because of its alignment with ExxonMobil. He
noted that TransCanada does not profess to be an expert with
GTPs. However, with ExxonMobil on board, TransCanada has the
strongest player in the GTP business worldwide, which adds to
the project. Further, with ExxonMobil jointly working on the
pipeline, TransCanada hopes that the revised cost estimate will
also satisfy other similarly situated producers. He suggested
that Mr. Massey may wish to address the committee on the matter,
but from the TransCanada perspective the alignment with
ExxonMobil is satisfactory.
9:44:15 AM
MR. MASSEY related that ExxonMobil evaluated the full range of
options of how to progress the projects, which included
consideration of joining Denali, joining TransCanada,
considering itself alone, or postponing and showing up during an
open season. ExxonMobil analyzed what could move the project
forward and the success in bringing all the parties together
pointed to TransCanada via AGIA as the best opportunity for
success.
9:45:33 AM
CO-CHAIR JOHNSON asked about the statement that TransCanada
would not be involved in the negotiation of physical terms. He
opined that one major hurdle remaining is the type of structure
with the state that will insure durable fiscal policy. He asked
how TransCanada's stockholders could allow TransCanada to "sit
on the sideline" during that process.
MR. PALMER answered that TransCanada's stockholders expect
TransCanada to keep its word. Further, TransCanada has agreed
with the state to remain outside negotiations. He said that
TransCanada's CEO has repeated this agreement on numerous
occasions, most recently to the governor of Alaska the day prior
to the announcement of the transaction.
9:46:27 AM
MR. PALMER outlined the benefits of alignment with ExxonMobil
[slide 10]. He related that TransCanada has over 2,000 pipeline
employees and currently transports 20 percent of North American
gas daily. He detailed recent TransCanada activities, including
that TransCanada is a 100 percent owner of a $12 billion
Keystone Project underway that will take 4.5 years from
announcement to completion, will span 4,000 miles, and traverse
13 states. Secondly, TransCanada is involved in building a $2
billion project, to move gas from western Alberta to eastern
Alberta, at the existing Meikle River Compressor Station. The
North Central Corridor Project, comprised of a 42-inch pipeline,
is currently under construction, with the first phase completed
last winter and the second phase next winter. Another project,
Bison, will move gas out of the Rockies connecting to
TransCanada's pipeline in the Midwest. Additionally,
TransCanada was awarded the right to build the Guadalajara
Pipeline in Mexico.
MR. PALMER described further benefits of alignment with
ExxonMobil [slide 11]. He related that the financial and
project management strengths of ExxonMobil are generally
recognized. ExxonMobil is the recognized industry leader in
execution of large complex projects, has substantial financial
resources, and is the largest holder of discovered Alaska North
Slope natural gas resources. Further, ExxonMobil has the
expertise and technology for GTPs as well as pipeline systems,
has been in Alaska for decades, brings to the project previously
described assets, as well as the commitment to the timely
development of Alaska's gas resources. This combination brings
unparalleled experience in project execution. ExxonMobil's
focus is on costs and schedule. TransCanada and ExxonMobil
share a common philosophy in that they are jointly committed to
advance the project, need the full support of the state, the
U.S. and Canada government, North Slope producers, and other
interested parties to fulfill the project. Yet, TransCanada
recognizes that to succeed in a project of this scale requires
alignment with government. He highlighted TransCanada has
previously succeeded in these types of projects. However,
commercial ventures cannot succeed alone; they require
alignment. TransCanada is ready to move forward with other
parties when they are ready to do so
MR. PALMER stated that Mr. Massey will excuse himself at this
time if there are no further questions for him.
9:50:47 AM
CO-CHAIR JOHNSON recalled prior testimony that ExxonMobil is the
largest holder of gas reserves on the North Slope, which he
assumes also include Point Thomson. With respect to Point
Thomson, he asked whether it was part of the discussion during
ExxonMobil's negotiations and whether the state was involved in
discussions regarding the settlement of Point Thomson. He asked
Mr. Massey to state the facts for the record.
MR. MASSEY answered there were no commitments from the state to
sell Point Thomson in order for ExxonMobil to join TransCanada.
He related that with respect to Point Thomson, the state
continues to have technical questions about the proposed
project. The state is currently going through its due diligence
process, is reviewing work that has been accomplished, which has
led ExxonMobil to believe that Point Thomson is the right
project to propose. He said he hopes the state will conclude
and agree that ExxonMobil has taken the right approach. Once
that process is completed, ExxonMobil can hold good settlement
discussions that will result in an outcome that both parties are
comfortable with to allow them to move together on Point
Thomson. Point Thomson as critically important to the gas
pipeline as it represents 25 percent of the gas resource. Thus,
he offered his belief that it is important to resolve this
matter and move forward.
CO-CHAIR JOHNSON asked if it would be a fair statement to say
that without Point Thomson the probability of a pipeline is
diminished considerably.
MR. MASSEY answered yes. He reiterated that Point Thomson
represents 25 percent of the gas resource, and said that it
would be a much different project without Point Thomson.
However, that does not necessarily mean that Point Thomson must
be available on the "first" day because it is possible to "flow"
Prudhoe Bay harder and bring Point Thomson in later. Many
permutations can be considered for the overall project success.
Ultimately, Point Thomson gas is needed in order for the
pipeline to be a go, he said.
9:53:38 AM
MR. MASSEY, in response to Co-Chair Johnson, responded that if
Prudhoe Bay is the only field the risk is higher, but if Point
Thomson is available then two fields are involved, and it would
reduce the risk of the big financial commitment to underpin the
pipeline project. Thus, it is important for ExxonMobil to know
of the gas commitment. In further response to Co-Chair Johnson,
Mr. Massey stated that ExxonMobil is optimistic the issues
related to Point Thomson will be resolved before the initial
open season. However, if that is not the case, then ExxonMobil
will reevaluate the project at that time. He opined that it is
difficult to speculate any outcome at this time.
9:55:22 AM
MR. MASSEY, in response to Representative Olson, confirmed that
the state did not make any assurances related to Point Thomson
in order for ExxonMobil to join TransCanada. He reaffirmed
there were no linkages of any kind.
CO-CHAIR JOHNSON asked whether ExxonMobil would still be
involved in the pipeline project had it not obtained the leases
back.
MR. MASSEY answered yes.
9:57:20 AM
MR. PALMER highlighted the alternatives between delivery points
in Alaska, and Alberta Hub enroute the Lower 48 [maps on slide
12]. He reviewed the project schedule [slide 13], pointing out
that the FERC pre-filing request was met at the end of April,
some two years earlier than originally contemplated in the AGIA
schedule. The FERC indicated it preferred TransCanada to pre-
file, TransCanada held comprehensive discussions with FERC,
reached an agreement, and the pre-filed application was accepted
on May 1, 2009. He noted the only other change to the timeline
shown is the addition of a Canadian timeline. In response to
Representative Ramras, said that TransCanada's preference and
goal is for customers to commit gas in the initial open season.
However, it would not be unusual for potential customers to
condition their bid, which he characterized as often the norm.
While is possible that fiscal issues may remain an issue for
ExxonMobil or other potential shippers, and may be set out in
their conditions, this is clearly nothing that TransCanada can
resolve. He related that if a resolution was not forthcoming
after July 2010, TransCanada still has an obligation to continue
to solicit the market every two years.
MR. PALMER recalled past testimony and then addressed one of the
strengths of the AGIA process. He indicated that TransCanada
was initially not amenable to continue regulatory approval
subsequent to a failed open season, that TransCanada agreed it
would continue to seek customers, but would not spend the
hundreds of millions of dollars for regulatory approval without
committed customers. However, AGIA was passed with the
obligation to continue regulatory approval and the state agreed
to a financial contribution to the regulatory costs and so will
share those costs.
MR. PALMER addressed the timing of the project, such that in the
event of an unsuccessful open season in the summer of 2010, that
TransCanada will continue to pursue customers and the regulatory
approvals as it is required to do under AGIA. If resolution is
reached on fiscal matters in 2011 and customers are willing to
commit, then TransCanada would not need to wait two years and a
delay would not jeopardize the schedule. However, the schedule
would be jeopardized if regulatory approval is given, but
customers have not committed since regulatory approvals and
customers are both required.
10:02:20 AM
MR. PALMER, in response to Co-Chair Millet, explained that
TransCanada reached an agreement with FERC on the information
that must be submitted as part of the FERC pre-file, as well as
the timing of submittal of additional information. This became
necessary since TransCanada would normally pre-file post open
season and would have more information to submit to FERC. He
restated that TransCanada and FERC agreed on the timing of
submitting information to FERC.
10:03:32 AM
MR. PALMER, in response to Co-Chair Johnson, responded that to
determine whether it is considered a failed open season or not
would depend upon the conditions set by potential shippers
during the open season. It is not unusual for customers to have
conditions for regulatory approvals and sometimes for fiscal
resolution, but those types of conditions cannot be resolved by
TransCanada. Thus, the outcome would depend on what conditions
potential shippers required. TransCanada would consider it a
failed open season if, after the July 2010 date, it cannot
readily resolve any of the conditions set. In further response
to Co-Chair Johnson, Mr. Palmer answered that so long as the
standard terms are met, and the only condition that customers
place on their commitment of gas is FERC approval, TransCanada
would determine it to be a successful open season.
CO-CHAIR JOHNSON clarified that he was referring to the state
fiscal concerns.
MR. PALMER agreed that at some point unresolved fiscal concerns
would result in an unsuccessful open season.
MR. PALMER, in response to Co-Chair Johnson, outlined that in
the event the state fiscal issues are not resolved, TransCanada
would take the same actions to prepare its October 2012 FERC
filing. However, he emphasized that TransCanada would have a
much stronger FERC filing if it has full gas commitments without
state fiscal concerns by October 2012. TransCanada will pursue
FERC regulatory approvals whether it has succeeded or not during
the initial open season. However, the application would be
commercially weaker if it does not have customer commitments.
He reiterated that if customers are ready to commit before 2012,
"great." TransCanada will also hold a second solicitation
during the summer of 2012. He said he hopes whatever issues
potential customers may have would be resolved by then. Again,
TransCanada is not in control of those issues, he stated.
10:07:22 AM
MR. PALMER addressed matters that arose during his testimony in
2008. He reminded members that last year TransCanada started a
ten-year schedule; thus, TransCanada is one year into that
process. He highlighted accomplishments since June 2008 [slides
14 and 15]: TransCanada's application was reviewed, the AGIA
license was approved by the legislature, the AGIA license was
issued on December 5, 2008, and an AGIA coordinator was
appointed. TransCanada has achieved real progress toward a
broader alignment with ExxonMobil. TransCanada has performed
engineering, environmental, and limited field work towards the
capital cost estimate with significant Alaskan participation.
The addition of ExxonMobil's personnel broadens the expertise
and experience of TransCanada's project team, and enhances
credibility with potential customers and the likelihood of
success. TransCanada is currently holding discussions with
potential customers for deliveries in Alaska and to Lower 48
markets via the Alberta Hub, and is drafting commercial terms
for the initial open season.
MR. PALMER, in regard to the liquefied natural gas (LNG) project
component, stated that TransCanada has moved forward with cost
estimation and drafting of commercial terms, has been holding
discussions with potential customers which resulted in
modifications to a 3.0 billion cubic feet per day (Bcf/d)
design. Potential customers can now select Valdez as delivery
point in an initial open season. He opined that TransCanada
does not believe sufficient gas will be committed in the initial
open season for 4.5 Bcf/d to the Alberta Hub and 3.0 Bcf/d to
Valdez. It will be either one or the other, but not both, he
said.
MR. PALMER continued with the project accomplishments. He
addressed the Canadian regulatory accomplishments listed on
slide 16, including that ExxonMobil reviewed and endorsed the
Northern Pipeline Agency (NPA) as the Canadian regulatory model
for the project, re-staffing of the NPA is underway, the NPA is
coordinating the project within the Canadian government with
Canadian provinces, and multi-department meetings have been held
with federal agencies, the British Columbia and Yukon
governments. He restated that on the U.S. regulatory side,
TransCanada pre-filed with FERC two years earlier than the
approved AGIA schedule, is progressing communications with FERC
project staff, has held multi-agency meetings, and continues to
hold ongoing discussions with federal and state coordinating
agencies.
10:11:42 AM
MR. PALMER, in response to Co-Chair Johnson, answered that
TransCanada will bear the full cost of the NPA, that the re-
staffing will end up as part of the tariff, which is the usual
and customary process. If there is an unsuccessful project,
TransCanada's shareholders would bear the costs. In further
response to Co-Chair Johnson, Mr. Palmer responded that specific
legislation is limited to this project and not for any other
project. He added that the pre-build costs are charged to the
western Canadian producers, but for the northern section the
costs are as previously described. He elaborated that there is
not any current activity with the NPA since they are not
approving facilities, but in the event that the NPA approves
facilities the pre-build costs would be charged.
10:13:48 AM
MR. PALMER continued his review of project accomplishments
[slide 17]. TransCanada has contacted all Canadian right-of-way
First Nations and offered to negotiate first participation
agreements, he said. Five of eight Yukon First Nations parties
are currently ready to hold discussions, and TransCanada has
held negotiations with some parties. In response to, Co-Chair
Johnson, Mr. Palmer acknowledged that negotiations have been
held with more than one party, and while he is not certain
whether that number has now increased to two or three, it is not
as high as five.
MR. PALMER, in response to Representative Olson, answered that
with respect to British Columbia's First Nations, TransCanada
has made the same offer. He related that Fort Nelson on south
is an active project area and is being processed on an
integrated basis as TransCanada proposes pipelines into those
sections of British Columbia.
10:16:07 AM
MR. PALMER updated the committee on the partnership with other
subsidiaries of TransCanada, stating that Alaska Northwest
Natural Gas Transportation Company (ANNGTC) might cause delays.
There are partnership agreements related to efforts in the late
1970s and 1980s to build a gas pipeline from the North Slope to
markets in the Lower 48. He recalled extensive testimony last
year that ANNGTC would not be an issue, but since some parties
expressed concern, TransCanada took additional actions: The
ANNGTC partnership is currently in dissolution, and the
conditional FERC certificate, federal right-of-way, and water
permits have all been returned. He advised that TransCanada did
not own six withdrawn partners, but has in hand full releases
from all but one of the six withdrawn partners. In response to
Co-Chair Johnson, Mr. Palmer emphasized that all of the parties
were substantial and significant commercial parties. He said he
is not at liberty to disclose any names due to ongoing
negotiations.
10:17:46 AM
MR. PALMER recalled identifying a significant upside by
commercially aligning the section of the project from Fort
Nelson to the Alberta border with TransCanada's Alberta Hub
system. He elaborated that it would physically be the same
pipeline, but commercially, it would be averaged with the
Alberta system. This pipeline represents about a 200 mile
section of pipeline and, if successful, would result in an 18
cent per thousand thousand British thermal units (MMBTUs)
benefit to the Alaska customers or about $300 million per year.
This project still requires regulatory approval, but TransCanada
has made significant progress. He pointed out that the Alberta
section of the pipeline system has been provincially regulated
for 50 years and prohibited from physically or commercially
crossing any borders. One significant TransCanada
accomplishment is an application a year ago with the National
Energy Board (NEB) and the Canadian government, with Canadian
approval for TransCanada's Alberta System. Additionally,
TransCanada has proposed two small pipelines into northern
British Columbia - Groundbirch and Horn River - to move shale
gas. If successful, it will be excellent precedent for the
Alaska project, he predicted.
10:21:10 AM
MR. PALMER, in response to Representative Ramras, related that
TransCanada's Anchorage office answered his letter on June 17,
2009. He recalled the questions about the differences between
the proven reserves and total reserves. He explained that Horn
River is in the early stages of development as are many other
shale reserves in North America, but proven reserves are not
clearly defined today. He acknowledged differences in Canadian
and U.S. terminology for "gas in place". Canada's "gas in
place" implies the total reserves including proven, probable,
potential, and speculative. He estimated a range of 100 - 400
trillion cubic feet (tcf) for Horn River reserves. The
recoverable resource is expected to be 20 - 50 tcf, which
includes proven, probable, and potential, but not speculative
gas reserves. It is probable that the 20 - 50 tcf will be
recovered, but the speculative reserve will not likely happen,
although it is too soon to know. He estimated that 20 to 50 tcf
of gas will likely be produced over the life of the basin. In
response to Co-Chair Johnson, Mr. Palmer clarified the effect of
these basins on TransCanada's proposed Alaska pipeline under
AGIA. If 20 to 50 tcf is produced overall, Western Canada's
production, which has recently declined, would be enhanced He
emphasized that these projects must compete in the marketplace,
which helps illustrate why TransCanada is so focused on cost and
schedule. The proposed AGIA pipeline project will be a
competitive project if TransCanada can contain its production
costs to below $3. He underscored that every project estimate
he has reviewed shows that ten years from now the projected cost
of the proposed pipeline will be at $6 - $8 or higher. Thus, if
costs can be held to $3, TransCanada's AGIA pipeline project
will certainly be competitive. However, dramatic cost increases
or significant price reductions will impact this project. It
does not change TransCanada's commitment, but reinforces that
costs must be controlled.
10:25:09 AM
MR. PALMER pointed out that developing a pipeline is very
different from developing shale gas since the bulk of the cost
is for exploration and development, which has always been the
case for Alberta gas, relative to Lower 48 gas, since its gas is
farthest from market. Thus, TransCanada has had to focus on
keeping pipeline costs low. Alaska is no different except it is
even farther from the markets. If Alaska gas can be held to a
$3 range in 9 years time then it will be competitive with other
sources of gas. He said he would be surprised if shale gas
price stays at $2 forever, but shale gas prices affect the
economics of every project, including the proposed TransCanada
AGIA pipeline project. Current total gas produced in North
America is about 75 Bcf per day. He conveyed that without
drilling any wells in North America the natural depletion is
still 10 to 15 Bcf per day, which is huge. Producers will drill
when it is profitable to do so and producers believe that over a
sustained period they can make a profit, they will continue to
drill either to maintain or grow production. He reiterated that
he did not believe that $2 or $3 is sustainable, unless a
massive amount of gas is discovered. He pointed out the
discrepancy between oil prices in Alaska in the $60 - $70 range
and the world market. If natural gas prices in North America
are vastly different on a worldwide scale, he predicted that
parties are likely to commit to the proposed TransCanada AGIA
project. He doubted that over time the gas to oil ratio of 17,
18, or 20, similar to today's ratio will be maintained.
However, if the gas to oil ratio does prevail, producers can
make significant money shipping gas off this continent to other
countries.
MR. PALMER, in response to Representative Ramras, indicated that
TransCanada currently employs two Alaskans. More importantly,
TransCanada employed 84 Alaskans last year, which continues to
ramp up. TransCanada will leverage TransCanada and ExxonMobil
employees' skills and power to contain costs and advance the
project competitively worldwide. In further response to
Representative Ramras, Mr. Palmer explained that it is not
relevant as to the duties of the two employees, but TransCanada
plans to ramp up the number of Alaskan employees as the project
advances. TransCanada currently provides lower project costs by
using in-house expertise.
REPRESENTATIVE RAMRAS pressed for the duties of TransCanada's
Alaska employees.
MR. PALMER replied that TransCanada currently has an office
manager and an external affairs position in Alaska. TransCanada
normally hires contract employees during the development stage
of the project.
MR. PALMER, in response to Co-Chair Millett, answered that
subsequent to the AGIA application, TransCanada has not been
inactive in Washington, D.C., that TransCanada provided comments
to the U.S. Senate Energy committee when it considered loan
guarantees being increased. He acknowledged that during the
U.S. national elections and transition period, TransCanada has
been inactive and will have to reassess with ExxonMobil how the
structure will move forward.
CO-CHAIR MILLETT asked for a summary of TransCanada's comments
before the U.S. Senate Energy Committee.
MR. PALMER answered that TransCanada supported the proposal to
increase the loan guarantee from $18 billion to $30 billion, and
to provide access to the federal financing bank. If access was
in place, it would potentially lower the cost of borrowing for
the project. He noted a 1 percent change in the interest rate
would lower the toll by $.09, or $150 million per year for the
project. He said he was not necessarily suggesting the change
would be 1 percent, but used it to provide a point of reference.
It is also an indication of why the loan guarantee is important
for TransCanada's AGIA pipeline project and why TransCanada
supports any moves by Congress to enhance it. In further
response to Co-Chair Millett, Mr. Palmer related that
TransCanada supported the initiative when it passed from the
U.S. Senate Energy Committee, that the proposal must still go to
the full Senate, and if it does pass, that it will substantially
enhance the loan guarantee.
10:33:36 AM
MR. PALMER, continuing with TransCanada's accomplishments,
turned to slide 18, and explained that FERC also requires an in-
state gas study, which was awarded to Northern Economics, and
whose subcontractor is the Institute of Social and Economic
Research (ISER). This work is underway and will assist to
identify the in-state offtake locations. TransCanada's
Anchorage office opened in early 2009, some 18 months in advance
of its schedule, with a planned expansion later this summer as
the project ramps up.
MR. PALMER, in response to Co-Chair Johnson, offered his
understanding that the in-state gas study would be filed with
FERC and thus be made public.
MR. PALMER reviewed the next steps through open season to July
2010 [slide 19]. He stated that this period, TransCanada will:
complete the capital cost estimate by the end of the first
quarter (Q1) 2010, including engineering, environmental, and
field work; finalize commercial terms and precedent agreements;
advance Canadian First Nations participation agreements, as well
as the Fort Nelson issue. TransCanada will complete the in-
state gas study later this year and will continue to have
ongoing discussions with potential customers. TransCanada
prefers a dialogue between the state and ExxonMobil to achieve a
successful initial open season. Additionally, TransCanada will
file an open season package with FERC and hope to obtain
approval. He concluded his presentation by stating that
TransCanada will conduct the open season and hope for success
during the 13 month period.
10:36:35 AM
MR. PALMER, in response to Co-Chair Johnson, answered that the
TAPS study will not shorten TransCanada's timeframe to complete
the open season. He explained that TransCanada's other critical
path items need completion prior to the open season due to the
advances necessary in many areas. He pointed out that the open
season packet submission date is the end of January 2010,
leaving the company with seven months to complete all the
necessary work. In further response to Co-Chair Johnson, Mr.
Palmer related that time is money but work is also money, too.
While the study will reduce the amount of work, it will not
shorten the timeframe to conclude the open season. He offered
that two components are replacement of work and delay. To date,
TransCanada and ExxonMobil have not put a value on the TAPS
study, nor sought reimbursement, although TransCanada will
ultimately need to provide a value for FERC, who will judge the
value.
10:39:27 AM
CO-CHAIR MILLETT asked whether TransCanada sees the link between
fiscal stability, the gas tax regime in the state, to a
successful open season.
MR. PALMER responded that in the past few years potential
customers related that they perceive a link and would need
resolution on the fiscal stability issues. However, he is not
familiar with the details and the discussions are between the
producers, the administration, and the legislature. In further
response to Co-Chair Millett, Mr. Palmer answered that pipeline
companies seek successful open seasons and will control what
they can to meet their goals of holding them. In the event that
potential customers have other issues to resolve with government
entities, pipeline companies have no area of influence, but will
work to encourage resolution of the issues.
10:41:15 AM
CO-CHAIR EDGMON recalled the AGIA vote, and an understanding
that AGIA was awarded to an independent third party. Today, the
context is different, in terms of alignment between the
independent third party and one of the leaseholders. He then
posed a scenario in which ExxonMobil would earn full voting
rights with TransCanada and resolve its issues with the state.
He presumed in the scenario that ExxonMobil would then seek
different fiscal terms from the legislature than the AGIA
license envisioned, as well as changes to the rolled in rates
and expansion terms. He inquired as to whether any scenario
exists in which the $500 million state contribution would be
negotiable as part of the tax regime discussions, since
TransCanada's partner is the largest corporation in the world.
10:44:01 AM
MR. PALMER answered that the AGIA terms were established for any
party to bid, with terms similar to those that an independent
pipeline would supply to potential customers. At that time the
state did not know the identity of the bidders, and whether a
bidder would be TransCanada or perhaps all three major
producers. The terms were set to satisfy the state regardless
of the owner's identity. The outcome: TransCanada prevailed in
the AGIA award. He offered that TransCanada committed to the
AGIA terms, which have been reaffirmed during its alignment with
ExxonMobil. He pointed out that part of the difficulty within
TransCanada during the AGIA process was the obligation to go
beyond an unsuccessful open season. However, the state's
financial contribution of $500 million helped resolve that issue
for TransCanada. He recapped that the contribution is excluded
from the rate base, will lower the state's tolls, will result in
a higher netback to the state, and will increase state revenues
so long as the project succeeds. He acknowledged that while the
state risks its $500 million, TransCanada's shareholders also
face risks. In the event that TransCanada has a successful open
season and has rock solid commitments for 4.5 Bcf per day, there
is no question the value of the state's $500 million investment
would decrease. However, TransCanada has not changed its
commitment to the project since AGIA. The AGIA obligation rests
with TransCanada, and he surmised that AGIA contemplated that at
some point TransCanada would be successful in attracting
customers. Currently, TransCanada continues to seek customers.
He recalled testimony last year by producers that indicated
TransCanada's cost estimate would not be credible. He opined
that it will be difficult to argue that when TransCanada is
working with ExxonMobil. He acknowledged TransCanada does not
yet have gas commitments. If TransCanada attains them in 12 or
13 months, the state's investment has less value to the
pipeline, but it absolutely has value to TransCanada today, he
said.
MR. PALMER summarized his response, which is that he cannot give
a definitive answer except to restate TransCanada remains
committed to its AGIA obligations, the AGIA obligations
contemplated terms that are similar to those for an independent
pipeline, the winner happened to be TransCanada, and TransCanada
will provide the service it is obliged to provide.
10:48:06 AM
CO-CHAIR JOHNSON summarized Mr. Palmer's response, such that
TransCanada is committed to the terms of the AGIA agreement and
expects the same commitment from the legislature. Thus, he
suggested that the answer to Representative Edgmon's question is
that the state's $500 million is not on the table, will still be
available even if the initial open season is successful, and is
committed regardless of who partners with TransCanada. He asked
Mr. Palmer if he had any issues with the response.
MR. PALMER answered no.
The committee took an at-ease from 10:49 a.m. to 11:00 a.m.
11:01:05 AM
PAT GALVIN, Commissioner, Department of Revenue (DOR), explained
that the state's role was to review the agreement between
TransCanada and ExxonMobil and determine if the new relationship
required additional approval under AGIA, specifically with
respect to Section 210 of the Act, which pertains to
modifications of the AGIA license. The state team was provided
with all the documents associated with this new relationship,
including the interim project agreement (IPA), the project
funding agreement (PFA), and all the ancillary documents. The
DOR brought together members of the state team, and also outside
consultants to review the commercial, technical, and legal
aspects of the proposed project in order to provide guidance to
determine if this relationship modifies the state's interest
under the AGIA license. Through that process the DOR sought and
received oral and written clarifications from TransCanada and
ExxonMobil with respect to the agreements to better understand
the relationship. Ultimately, DOR determined that there was no
diminishment of the state's rights under the AGIA license as a
result of the new relationship with ExxonMobil, and that
TransCanada retains all the obligations under the AGIA license
and has structured this agreement with ExxonMobil to preserve
its opportunity and right to respond to the state's requirements
under AGIA.
COMMISSIONER GALVIN related that the state's final conclusion is
that no action is necessary by the state regarding the alignment
with respect to AGIA. He offered that the state is excited
about this development, that alignment is precisely what AGIA
intended to provide and facilitate, and that ExxonMobil brings
tremendous value to this project. The administration has
concluded that from the state's perspective this alignment is
very good for the project, and the administration looks forward
to further alignments as the project proceeds.
11:05:10 AM
COMMISSIONER GALVIN, in response to Representative Kawasaki,
answered that no discussions were held with TransCanada to
change AGIA. In further response to Representative Kawasaki, he
stated that the administration also did not hold discussions
about making changes to AGIA in the upcoming legislative
session. He related that the representations made throughout
the state's discussions are embodied in TransCanada's testimony.
Further, the state will continue to pursue a durable system.
However, the state holds firm to its position which is that the
state currently provides a durable and economic fiscal system.
Inducements in AGIA allow the shippers to take advantage of the
ten year period, with respect to taxes. The royalty provisions
provided within AGIA would extend the length of the leases,
which are not limited to ten years. Again, there were not any
overtures or discussions held during this period with regard to
changes to AGIA.
11:07:53 AM
REPRESENTATIVE RAMRAS asked what the administration is doing to
modify royalties to satisfy ExxonMobil's concern about a
financial stable tax regime.
COMMISSIONER GALVIN replied it would be an overstatement to say
that the administration intends to satisfy ExxonMobil's demands
via royalties. The administration is holding discussions with
regard to establishing the upstream royalty provisions available
under AGIA. The state is implementing the terms of AGIA in
order to put in place an opportunity for shippers that make a
commitment at the initial open season to enjoy a more favorable
methodology with regard to valuing the gas, as well as enjoy
modifications to the state's rights to switch between "royalty-
in-value royalty-in-kind options." Those terms are not viewed
as a vehicle for satisfying the producers' desires, but rather
are seen as clarification and implementation of the terms of
AGIA, and to establish the methodology legislation process.
11:10:02 AM
REPRESENTATIVE RAMRAS described royalty-in-kind (RIK) or
royalty-in-value (RIV) and suggested Commissioner Galvin
elaborate on the definitions. He asked if the administration is
contemplating relaxing the royalties' regime.
11:11:10 AM
COMMISSIONER GALVIN explained the oil and gas royalty revenue
process. The royalty revenue the state receives represents the
state's benefit for owning the resource and leasing the right to
explore and develop it to companies. The terms of these leases
establish contractual relationships between the parties and the
state with respect to the state's royalty share of the gas.
This is how any other owners of oil and gas resources would
establish their royalty rights, and the state has done so with
its leases. In most instances in the North Slope, a 12.5
percent rate is the norm; a 12.5 percent ownership of the oil
and gas that is produced. The state has the option to either
take possession of the oil and gas at the wellhead or be
responsible for the delivery and sale at the market. Or the
state can allow the producer to bring the oil and gas to market
and the state receives its share via that transaction. The AGIA
provides an opportunity to clarify within the royalty structure
the determination of the value of the gas. For example, under
the oil system, the lease establishes a value, referred to as
the higher up, that the state is not bound by the best price a
leaseholder may achieve in the market. Instead, the leaseholder
remits the royalty based on the highest value that is received
by any of the leaseholders within a particular pool; the state
receives the highest value among any of its competitors. Thus,
the state wants to protect value, and when the state receives a
royalty payment, it verifies the payment everyone else received
and performs a "true-up" at the end, such that if someone else
received more, the state can collect the value from the
leaseholders. Companies do not like that as it provides
uncertainty; they make a good faith sale, and after the fact
must pay the state additional money as the result of someone
else receiving a better price.
COMMISSIONER GALVIN noted that with the gas market, the state
will offer in AGIA to create some methodology to establish the
value different from the "higher up" process. Under AGIA, the
state will create a formula based upon prices that will provide
greater predictability for the companies in terms of what the
royalties will be based upon. The state views these changes as
a value to the producers; as an inducement to producers to
commit their gas to the open season. Additionally, the state
can provide more predictability to producers with respect to the
RIK and RIV. In most instances the state has the right to
switch between with a relatively short notice of six months, or
so, but this unpredictability has been problematic for
producers, who must take firm commitments. Thus, one time the
shipper may ship a volume of gas and the state request that they
ship more gas, or the state may inform the shipper that six
months from now, the state will ship some of the gas and the
shipper will have less. Thus, the state shrinking its options
with respect to switching and providing more certainty
represents value to shippers. He recapped that those are the
two things on the table in terms of the state evaluating
royalties on gas as the open season approaches: what is the
methodology for establishing the value under royalties and what
is the methodology for switching between RIK and RIV.
11:15:56 AM
COMMISSIONER GALVIN, in response to Representative Ramras
explained that the state considers its current tax system
sufficient to provide an economic project for all participants.
If the producers provide the state with information that
demonstrates changes are necessary, then the state would be
willing to consider changes. He characterized the premise of
the state attempting to satisfy producers through royalties as a
faulty premise. He suggested that the state fiscal system,
royalty and tax, is sufficient at this time; that the durability
is sufficient for this project in AGIA. He noted that Mr.
Massey expressed some concern over the lack of contractual
stability to the ten year tax commitment. He recalled that the
administration's original AGIA proposal contained contractual
gas tax certainty provisions, subsequently removed by the
legislature, which the administration believes should be
considered collectively by the state. The current package is a
reasonable proposal, and the state's system is adequate. He
restated that the DOR is willing to address producers' concerns
over time as the project moves forward. The AGIA process will
continue to move forward; Mr. Palmer agreed that the AGIA
process will continue through an open season to the FERC
certificate.
11:20:00 AM
CO-CHAIR JOHNSON asked whether the changes would be in statute
or regulation.
COMMISSIONER GALVIN answered that in order to make changes to
address concerns, the producers would require statutory changes;
whether or not that is ultimately needed is yet to be
determined. He clarified that the revenue Representative Ramras
brought up earlier points to the necessity of some regulatory
aspects of AGIA not yet resolved; the state has an obligation to
put regulations in place that clarify the royalty aspects of the
upstream inducements. He reiterated that issues related to
durability and fiscal issues would require statutory changes.
11:21:44 AM
REPRESENTATIVE RAMRAS asked whether the administration will
offer the largest tax concession in the history of Alaska in
order to invite ExxonMobil into AGIA.
COMMISSIONER GALVIN said no.
11:22:08 AM
CO-CHAIR MILLETT asked if the administration is waiting for the
producers or the legislature to propose changes to the fiscal
tax regime. She remarked that the number one impediment to the
gas pipeline is fiscal stability.
COMMISSIONER GALVIN recalled earlier discussions, then stated
that the DOR considers significant distinctions between what the
producers want, voice, and ultimately need to commit their gas
to the AGIA project. The question is whether the state needs to
do anything to arrive at what producers need. He said AGIA was
designed to move the project forward as the discussion ensues.
Thus, time and goal are not lost, which is first gas under the
timeline of AGIA framework. The state considers it a
significant downside for the state to become desperate to
resolve fiscal terms at an early juncture. He characterized the
previous administration's agreement as ill-advised because it
gave up considerably more than necessary in exchange for very
little in return. The AGIA process provides for forward
movement; the costs, economics, and the fundamental
underpinnings of this project become clearer as the date
approaches. The state's fiscal issues are only one component of
the process, and it is not in the state's interest to feel
compelled to satisfy the fiscal component before an open season.
He recalled Mr. Palmer's testimony that regardless of whether
the state reaches agreement with the producers, the AGIA project
will move forward along the timeline until TransCanada acquires
a FERC certificate, which is a critical component of AGIA, with
respect to the state's interest. It is a critical component
because the administration did not wish the project to stall and
place the state in a leveraged position. He recapped his
answer: the state does not intend to negotiate against itself,
to sabotage itself. The state will not propose a tax change
simply to "throw something more on the table." The analysis
indicates the project is economic under the current system, he
advised. However, the state is willing to listen to any
proposal the producers wish the state to consider. He said, "We
believe the ball is in their court. The state has put together
a fiscal system and a durability package already. We don't need
to negotiate against ourselves; we'll wait to hear what the
producers have to say about that."
11:26:38 AM
COMMISSIONER GALVIN, in response to Co-Chair Johnson, identified
that Marty Rutherford remains the gasline team lead.
Commissioner Irwin retains the prerogatives as it relates to
Department of Natural Resources (DNR) issues, and he retains the
prerogatives for DOR. Thus, the three would respond to any
requests by the producers and are prepared to respond.
CO-CHAIR MILLETT asked if it is in the state's best interest to
hold negotiations on fiscal terms in the event of a failed
initial open season.
COMMISSIONER GALVIN answered no, it is not in the state's best
interest. However, nothing is prohibiting the producers from
clarifying their position with regard to a durable fiscal
system. The state doesn't need to continue to put forward
additional proposals or add more value. The state is not
seeking to postpone the discussion. He suggested that those who
create the perception that the open season is a deadline to
conclude fiscal terms are creating a false deadline. He agreed
alignment and forward progress is in the state's interest, and
whether that happens before or after the open season will not
change the timeline since AGIA is designed to prohibit delays.
He suggested that the state needs to be open and willing to
engage in the fiscal regime discussion, but additional deadlines
or inducements are unnecessary.
11:31:12 AM
COMMISSIONER GALVIN, in response to Co-Chair Millett, answered
that the renegotiation of the state's royalty terms, and the
legislature's statement that it will not change the fiscal
system for ten years is a reasonable starting point and
significant advancement for the state. The question is where
this position is in relationship to ultimately what will be
necessary to have the project move forward. In further response
to Co-Chair Millett, Commissioner Galvin said that the state has
always been willing to talk to producers about the fiscal
regime.
11:32:53 AM
COMMISSIONER GALVIN, in response to Co-Chair Johnson, deferred
to TransCanada and ExxonMobil, with respect to the confidential
information about terms and whether it will be made available
only to the legislature in an executive session. He offered
that the AGIA provisions require confidentiality. However, he
also considered that TransCanada and ExxonMobil would likely
share information. In further response to Co-Chair Johnson,
Commissioner Galvin advised that any confidential information
released to the administration would require specific
authorization from TransCanada and ExxonMobil prior to releasing
it to the legislature. He further explained that under AGIA, a
distinction was made between the protocols of the application
process which had specific provisions for the legislature to
gain access through confidentiality agreements, and the post-
licensure that does not have a similar protocol in place to
share information with the legislature.
11:34:35 AM
COMMISSIONER GALVIN, in response to Co-Chair Johnson,
Commissioner Galvin said the evaluation team included members of
the DOR, DNR, and Department of Law; legal counsel from
Greenberg Taurig, LLP, who provided FERC pipeline expertise;
Gaffney Cline and Associates; Goldman Sachs; C. Scott Hobbs of
Energy Capital Advisors, Inc.; and Patrick Anderson of PINGO
International Inc., a technical contractor on pipeline issues.
CO-CHAIR JOHNSON asked whether the contractors were included in
the AGIA budget or if there will be a request for supplemental
funding.
COMMISSIONER GALVIN offered that with the acceleration of the
schedule, the administration would likely request supplemental
funding next legislative session. In further response to Co-
Chair Johnson, he recalled that leading up to the open season
the figure was $84 million, of which the state would reimburse
half, and the revised amount is $150 million for the same time
frame. The schedule DOR has reviewed exhausts the $42 million
through the first quarter of 2010. Thus, a supplemental is
necessary to reimburse expenditures into the first quarter.
CO-CHAIR JOHNSON inquired as to whether the outside consultants
are being paid by TransCanada or the state.
COMMISSIONER GALVIN answered the outside consultants are paid by
the state.
11:37:47 AM
MARTY RUTHERFORD, Deputy Commissioner, Department of Natural
Resources (DNR), explained that the department requested re-
appropriation of some funding to pull $.7 million from the $5.5
million, which was initially requested for the first year of
AGIA, and the re-appropriation was not made to the team. Thus,
the department would likely request a supplemental
appropriation.
CO-CHAIR JOHNSON recalled that ultimately some producers have
suggested they want to own a portion of the pipeline
commensurate to the amount of gas they commit to the pipeline.
He further recalled that is the case with ExxonMobil, but he was
not certain of other producers. He questioned whether the
current situation creates a producer-owned pipeline.
COMMISSIONER GALVIN answered that AGIA was designed to ensure
that whoever owned the pipeline would act like a third-party
owned pipeline. He asserted that DOR has never deviated from
that stance. He denied the supposition that AGIA was intended
to preclude the producers from owning the licensed project,
pointing out that at least two-thirds of the must-haves in
AGIA's structure anticipate that it will be a producer-owned
pipeline in the sense that contractual agreements are necessary
in order for it to act like a third-party pipeline. If it was
designed to be an independent pipeline, that the contractual
agreements would be unnecessary. Regardless of who owns the
AGIA pipeline, it will act like a third-party pipeline, which is
the intent. Thus, the state can enjoy the values of an
expandable, open-access low-tariff pipeline, regardless of
ownership.
11:42:19 AM
REPRESENTATIVE RAMRAS questioned whether Commissioner Galvin is
emphatically stating that the terms for royalties on North Slope
gas would not change in order to induce the producers to come
together on a pipeline.
CO-CHAIR JOHNSON clarified that the question is whether the
administration will ask the legislature for those changes.
COMMISSIONER GALVIN said he was unaware of any discussion. It
is DNR's purview, not DOR's, he continued, and he is unaware of
any modifications with respect to the AGIA pipeline.
11:45:54 AM
BUD FACKRELL, President, Denali-The Alaska Gas Pipeline
(Denali), began his PowerPoint presentation by stating that
Denali is still moving forward [slide 2]. Denali was created by
BP Exploration (Alaska) Inc. (BP) and ConocoPhillips to build
the Alaska Gas Pipeline (Denali). Denali is uniquely qualified
to build the complex and enormous project, he said. Denali
brings unparalleled North Slope and Arctic experience to the
project, and Denali has worldwide experience in construction and
operation of mega projects by virtue of its two owners.
Additionally, Denali brings a strong balance sheet to the
project. Denali remains on track to conduct an open season in
2010 and is in position to provide a superior commercial
offering, which should be good for the state. Finally, Denali
has not changed its focus, despite the economic turmoil, and
remains focused on the long term view, he stated.
MR. FACKRELL provided an overview of the gas fields located on
the North Slope [slide 3]. He informed members that the Prudhoe
Bay and Point Thomson field contains the majority of the 35 Tcf
in discovered gas resources. According to a 2004 U.S.
Geological Survey (USGS) additional 100-200 Tcf in undiscovered
potential resources has been identified, he said. Of the 35
Tcf, BP and ConocoPhillips are 50 percent leaseholders of the
resource. Additionally, BP and ConocoPhillips operate 99
percent of the North Slope production today. He pointed out
that the Oooguruk field, operated by Pioneer Natural Resources
Company, is the only field currently in production not operated
by BP and ConocoPhillips. Thus, Denali producers provide over
30 years of operating expertise on the North Slope. These two
companies built the North Slope infrastructure and the gas
treatment plants along the pipeline corridor, he advised.
MR. FACKRELL reviewed the regulatory framework in the U.S. and
Canada [slide 4]. He explained that the proposed pipeline is
controlled by the federal governments' in the U.S. and Canada.
In the U.S., FERC is responsible for authorizing and regulating
the project. The AGIA is not an exclusive license to build a
pipeline; Denali can proceed outside AGIA, and is doing so.
MR. FACKRELL related that in Canada, Denali is using the
National Energy Board (NEB) process which incorporates all of
the modern environmental regulations and is open to any project
proponent. He remarked that the NEB and FERC have a history of
working together to approve cross-border energy projects.
MR. FACKRELL focused on the Denali Terms of Service summarized
on slide 5 of his PowerPoint presentation. Denali is an open
access pipeline. "That's the law," he said. FERC was here a
year ago and testified to that fact." Denali's offering
includes a gas treatment plant (GTP) and Denali brings unique
expertise to building the GTP. He recognized the importance to
Alaskans for distance sensitive transportation for local use
that Denali will use. He remarked that Denali will use FERC-
mandated rolled-in rates, which is part of the FERC governing
process. The Denali pipeline design will provide for efficient
expandability and will solicit shippers every two years
regarding pipeline expansion. He stressed the importance that
North Slope exploration occurs, that 35 Tcf will not provide
enough gas for a 30-year pipeline, and that additional gas will
be needed. Denali will have at least five offtake points in
Alaska and will provide the necessary offtake points in Canada.
MR. FACKRELL reviewed Denali's progress and key accomplishments
[slide 6]. Denali has spent $100 million in the past year to
move the project forward. Denali has mobilized its project team
and has a core team of 80 to 90 people located primarily in
Anchorage or in its Canadian headquarters. At FERC's
suggestion, Denali pre-filed with FERC over a year ago, and has
forged an extremely beneficial working relationship. Denali
also filed the right-of-way on Alaska lands with the U.S. Bureau
of Land Management (BLM), which represents one-third of the
proposed pipeline route as well as an interactive process with
BLM.
11:52:53 AM
MR. FACKRELL pointed out Denali's successful 2008 summer field
program, which primarily focused on the corridor between Delta
Junction and the Canadian border. Work was performed on
hydrology studies, archeological surveys, and contaminated
sites. Additionally, Denali held extensive outreach programs in
Alaska and Canada. He highlighted workforce development,
including that Denali partnered with the University of Fairbanks
(UAF) on an archeological assistance program. The surveyor
apprentices completing the program can be used by anyone, he
noted. Denali held extensive meetings with Alaskan and Canadian
government officials. Finally, Denali awarded two major
contracts, with Fluor/Worley Parsons for the GTP, and with
Bechtel for the main proposed pipeline to assist with the
engineering cost estimate and the compressor station design.
MR. FACKRELL listed many of the contractor companies supporting
Denali's work [slide 7]. He characterized the Denali team as a
"top-notch, class A team, Alaskans, Arctic experience, Alaska
experience, and two worldwide engineering companies to
supplement that. We're poised for success."
11:54:45 AM
MR. FACKRELL stated that Denali is focused on the initial open
season [slide 8]. Denali's 2009 program is much broader than
its 2008 program, such that Denali will conduct the work
necessary for the 2010 open season. Denali is focused on the
cost estimate, which is a critical component of the project,
since it is vitally important to convey confidence to potential
shippers that Denali understands the costs, given the degree of
definition currently available' and using the assistance of
contractors like Fluor/Worley Parsons and Bechtel. Denali has
ongoing work with agencies such as DNR, FERC, NEB, the Office of
the Federal Coordinator (OFC), and BLM. Denali is actively
working with the FERC on its pre-file application; FERC requires
a third-party environmental contractor, and Denali is actively
working on a contract with Argon National Laboratories, to be
the specified FERC contractor.
MR. FACKRELL offered that Denali has engaged in conversations
with Department of Transportation & Public Facilities (DOT/PF)
because the infrastructure will need to be updated for this
pipeline project, including roads, ports, highways, and the rail
system. Additionally, Denali is involved in a field work
program focused on Canada. He restated efforts taken with the
Alaska Workforce Development. Stakeholder engagement activity
continues in Alaska, and BP and ConocoPhillips have large
operations in Canada, which assists with First Nations and other
aboriginal groups along the proposed corridor.
MR. FACKRELL concluded by reiterating that Denali's focus is on
the initial 2010 open season and the cost estimate that will
provide confidence to shippers [slide 9]. Denali is positioned
for a superior commercial offering, which will benefit the two
owners, the citizens of Alaska, and the state. He emphasized
that Denali does not require outside funding, and Denali's long-
term focus protects it from disruptions by the current economy
and competition.
11:58:33 AM
REPRESENTATIVE DAHLSTROM asked whether satisfactory agreements
have been reached with all of the First Nations groups along the
proposed route.
MR. FACKRELL characterized the work with First Nations parties
as a process. Although Denali has not reached agreements with
all of the parties, it feels good about the progress.
11:59:17 AM
MR. FACKRELL in response to Co-Chair Millett, pointed out that
all pipeline companies have testified to the importance of
fiscal stability; that shippers want to know the fiscal regime.
MR. FACKRELL, in response to Co-Chair Johnson, said that as a
pipeline company, Denali will not be negotiating with the state
on fiscal certainty; that is the role of shippers and producers.
MR. FACKRELL, in response to Representative Ramras, commented
that Denali believes it has a level playing field, and finds DNR
cooperative and the people qualified to review its application.
Although Denali does not currently have a signed reimbursable
services agreement (RSA), Denali is moving forward with the
process, and is continuing to perform field work. Denali does
have an RSA with BLM for the filing on the right-of-way, he
noted.
12:02:27 PM
MR. FACKRELL, in response to Representative Ramras, responded
that there is only enough natural gas available for one gas
pipeline. He said, "Let's make sure we're clear on that. There
will not be two pipelines built." Denali has held conversations
with FERC about the process, and FERC intends to allow two
applications to move forward since producers could commit gas to
two competing gas pipeline companies. However, economics will
win out in the end and once financial commitments are secured,
only one pipeline will go forward.
REPRESENTATIVE RAMRAS pointed out that in Oregon five pipelines
and two LNG facilities have all been permitted, but Oregon
recognizes that only one LNG and one pipeline will be built.
12:03:40 PM
MR. FACKRELL, in response to Co-Chair Johnson, offered to put on
the record Denali's independence from the producers. He
referred back to slide 5, stating that Denali is an open access
pipeline, according to the law. He said:
When the Natural Gas Act for Alaska was passed in
2004, it designated FERC to set up a set of rules to
govern this pipeline and conduct an open season. As
part of that we have to be separate, a distinct
entity. We have to function separately from the
shippers. And that is what we are in the process of
doing right now, making sure we are compliant with
that, and it is our intent when we go to open season
that we will be able to pass the muster on FERC rules,
but FERC is going to be very careful about that
governance piece and ensure that no one has an
opportunity, our two owners don't have an opportunity
on shipping side beyond any potential shipper out
there.
CO-CHAIR JOHNSON stated that Denali has partners that are
producers. TransCanada has a partner that is a producer,
providing information to them on the 2002 study.
12:06:13 PM
MR. FACKRELL, in response to Co-Chair Johnson, responded that in
2001-2002 the producers, ExxonMobil, BP, and ConocoPhillips,
performed a study for about $125 million over an 18-month
period. All three producers have proprietary rights on the
information and can share it. Denali has held that information
since Denali was formed, which is similar to TAPS. Thus, Denali
has used the study for over a year to build its cost estimate
and work program, including updates. In fact, Denali expended
effort to update its cost estimate to give shippers confidence
on the overall project cost. In further response to Co-Chair
Johnson, Mr. Fackrell advised that the original study cost about
$125 million, but he was uncertain of the cost of the TAPS
study.
12:07:32 PM
MR. FACKRELL, in response to Co-Chair Johnson, advised that
every piece of the tariff is subject to FERC's review and
approval; FERC will analyze whether the tariff is being paid
twice.
12:08:47 PM
CLAIRE FITZPATRICK, Senior Vice-President, Chief Financial
Officer, BP Exploration (Alaska) Inc. (BP), stated that she
recently assumed responsibilities for upstream gas activities.
She represents BP as a potential shipper and leaseholder. She
provided a shipper's perspective on regulations, shipping, open
season, and ExxonMobil's joining TransCanada. She stated that
FERC requires separation of interest from pipeline activities,
which means that selling and shipping activities must be
separated from direct or indirect interest in a pipeline. She
cannot discuss Denali as a legal entity, but just matters
related to potential shipper and leaseholder. Her primary
objective is to monetize the gas, which needs to be economic.
Since BP is also an operator at Prudhoe Bay, BP has requirements
and agreements with working interest owners to ensure that as
information is shared with TransCanada, ExxonMobil, or Denali,
that it is shared on an equitable and unbiased basis and the
working interest owners must be made aware of the information,
as well. As a shipper BP continually evaluates opportunities to
monetize gas, and to identify ways to eliminate or decrease
identified risks. The Alaska gas project has many risks and
many will be borne by the shippers. She reviewed four key
risks: actual presence of the gas, market value of gas, costs
associated with the gas in terms of tariff, and fiscal
framework.
MS. FITZPATRICK discussed the actual presence of gas, recalling
that 35 Tcf was previously mentioned, which is not enough to
fill the pipeline for 30 years. She said BP's risk is how much
gas is available, and what commitment BP will make. She related
that BP has observed huge volatility of gas not only in oil
prices but gas prices in the market value of gas. However, BP
must view selling gas in a market of 2020 and beyond in Alaska,
Canada, Lower 48, and possibly broader than that if LNG is also
considered. Thus, the risk analysis is much different when
considering longer term versus shorter term gas sales.
MS. FITZPATRICK, with respect to costs associated with the gas,
stated that these costs pose a large impact, and range from
combined capital and operating costs, which are paid by the
shipper in the form of tariff.
MS. FITZPATRICK, with respect to fiscal framework, stated that
tax and tax stability are important to BP, recalling similar
words expressed by other speakers today as predictability and
durability. BP has not approached the state with what BP would
need to make this project viable, since it is based on ongoing
analysis. All of these risks must be taken under consideration,
and BP must arrive at what is an acceptable risk as a shipper in
order to make the commitment. She restated that BP is
continuing to make those assessments.
12:14:24 PM
CO-CHAIR JOHNSON inquired as to the point at which BP as a
shipper will determine whether the fiscal framework is
appropriate.
MS. FITZPATRICK responded that all scenarios will be reviewed;
that it is a balance between must-haves and need-to-haves. She
related that once BP gets to open season and reviews the initial
package, BP will assess the quality of the engineering and the
risk and variables. If that starts to eliminate a lot of the
risks, then the total acceptable risk begins to change.
Currently, BP runs various scenarios to frame up ideas of at
what point does the project break. She speculated that BP would
likely be ready to begin discussions, ahead of receiving the
full initial open season package.
CO-CHAIR JOHNSON asked for clarification of the timeframe for
commitment of gas.
MS. FITZPATRICK FERC answered that FERC will specify the
timetable, but she recalled the preferred timeframe is 90 days.
CO-CHAIR JOHNSON in terms of timing, when the state would hold
discussions on the fiscal stability.
MS. FITZPATRICK related that after BP reviews the open season
packet, and assuming it is acceptable, BP would then indicate
that it was prepared to make a commitment based on certain
conditions, and fiscal stability is likely to be one of those
conditions.
MS. FITZPATRICK, in further response to Co-Chair Johnson,
offered that BP would prefer to have fiscal stability ironed out
prior to committing gas, but she is not sure it is a viable
outcome.
12:19:33 PM
MS. FITZPATRICK described the open season process, such that all
open seasons will be treated equitably, that BP is indifferent
to pipe ownership, but its interest would be to obtain the best
option for BP. The firm transportation commitment decision is
huge since it means that BP will commit a certain volume of gas
for a certain timeframe, on the basis that conditions will be
resolved to everyone's satisfaction. The firm commitment is
made up front, at which time BP accepts identified risks and
parameters, including that BP may commit to unknown gas and
price. During the open season BP will assess the quality of the
work and best estimates will be made and built into the risk
assessment. With respect to the impact of ExxonMobil joining
TransCanada, ExxonMobil brings experience, which suggests that
quality brought to open season will be higher. Furthermore,
competition is good for the shipper since it provides the
shipper with options. Ultimately, BP will make the choice that
is best for its shareholders.
12:22:11 PM
REPRESENTATIVE RAMRAS recalled Mr. Massey's testimony that
ExxonMobil desires ownership in proportion to its volume of gas
and asked if that is a requirement of BP.
MS. FITZPATRICK responded that BP assesses risk and absolutely
wants interest in a pipeline equal to its own interests.
However, BP has instances in which it ships product through
someone else's pipeline. Thus, it really depends on the
circumstances.
12:23:16 PM
REPRESENTATIVE RAMRAS remarked that ExxonMobil is tough in
business and dynamic. He posed a scenario in which ExxonMobil
engages in a discussion regarding durable and predictable terms
and enters AGIA as a builder. In that situation its interest in
achieving a low tariff would be beneficial to other producers.
Thus, if terms are acceptable to ExxonMobil, would BP would be
more or less likely to join the project.
MS. FITZPATRICK answered that BP would perform an independent
assessment of fiscal terms. In the scenario described, she said
she hopes that BP would have been a party to the negotiations
for fiscal terms, and if so, the terms may be favorable to the
company. However, the fact that the terms are good for one
party is not a guarantee that it is good for another, since the
pipeline companies are independent.
REPRESENTATIVE RAMRAS surmised that if BP is successful in
negotiating terms with the Palin Administration, similar to
those negotiated with the Murkowski Administration, that BP
would review the four categories of risk.
MS. FITZPATRICK noted her agreement. While the terms under the
Murkowski Administration were more favorable than the current
terms, BP would still need to evaluate them, she said.
12:26:41 PM
MS. FITZPATRICK, in response to Representative Coghill, answered
that FERC sets out requirements for separation of function to
ensure that shippers without affiliates and pipeline companies
without connections to producers receive fair treatment. In
terms of FERC's assessment of bids, the economics are
considered, but multiple risks are involved and BP performs a
total risk assessment.
REPRESENTATIVE COGHILL recalled the reference by TransCanada,
BP, and Denali about their responsibility to their shareholders.
He stated his interest in knowing the "tipping point," realizing
that both risk and return on investment are considerations.
MS. FITZPATRICK agreed that it is about return on investment,
but she would not be performing her duty if BP shareholders
thought the investment into an affiliate company would not
produce a better return.
CO-CHAIR JOHNSON pointed out that the responsibility to the
stockholder is the same, that it is sometimes difficult to
understand the separation. He remarked that FERC has made the
clear distinction so the stockholders do not need to make the
determination.
12:29:13 PM
MS. FITZPATRICK, in response to Co-Chair Millett, responded that
she cannot comment whether BP is talking to any other pipeline
companies, since she is not a party to the conversations.
However, as a shipper, she said that BP is holding discussions
with TransCanada and Denali and is making it clear that they
each have access to exactly the same information.
12:30:29 PM
REPRESENTATIVE DAHLSTROM asked if ten years of tax stability
would be sufficient.
MS. FITZPATRICK answered that ideally the producer would like
tax stability for the timeframe of the commitment.
12:31:23 PM
REPRESENTATIVE COGHILL surmised that BP holds contracts on North
Slope operations in Prudhoe Bay, and that gas from those fields
will be part of the open season. He asked how BP manages
discussions with respect to competing interests in the unit
agreement.
MS. FITZPATRICK replied that the agreement used is the actual
working interest owner's agreement and the parties must reach
agreement for gas offtake, although multiple scenarios exist to
do so. While it is managed through contractual agreement, the
process can be very complicated.
12:33:28 PM
CO-CHAIR JOHNSON suggested that having ExxonMobil joining the
team must be helpful in terms of confidence of the shipper.
MS. FITZPATRICK agreed.
12:34:21 PM
REPRESENTATIVE RAMRAS asked whether discussions and strategies
are being held with ExxonMobil, the leaseholder, to obtain
fiscal certainty from the state.
MS. FITZPATRICK replied not at the moment. In further response
to Representative Ramras, she said that given the relative
recent announcement of ExxonMobil joining with TransCanada, that
BP has not had a conversation about the matter so she could not
answer.
12:35:52 PM
CO-CHAIR MILLETT asked if BP, the shipper, is holding discussion
with TransCanada about joining the projects together, that
Alaskans would enjoy having one project moving forward.
MR. FACKRELL responded that at this juncture Denali is not
holding discussions with TransCanada. The Denali owners did not
file application under AGIA because they did not agree with the
terms, so to join owners now would be problematic. In further
response to Co-Chair Millett, she said that Denali has not yet
held discussions with ExxonMobil, the shipper, but anticipates
it will do so. Denali wants to insure proper separation, and
plans to hold discussions with all shippers.
12:37:50 PM
WENDY KING, Director of External Strategies, ANS Gas Development
Team, ConocoPhillips Alaska, Inc. began by stating that she is
representing ConocoPhillips as leaseholder and prospective
shipper. ConocoPhillips is a major owner of North Slope oil and
natural gas leases, and is the largest oil producer in the
state, she pointed out. First and foremost, ConocoPhillips will
seek the best solution to transport North Slope gas to market,
and ConocoPhillips will remain engaged and interested in all gas
pipeline projects. She characterized ConocoPhillips as keenly
interested in a gas pipeline project. With a 36 percent
ownership in the Prudhoe Bay unit and an interest in the Point
Thomson field, ConocoPhillips is motivated to monetize the
natural gas in an economically viable way. Additionally,
ConocoPhillips is one of the largest active explorers in the
state. However, it is not just the aspect of ConocoPhillips's
portfolio. Any gas pipeline will have an implication on the
life and viability of all North Slope assets, such that if the
gas pipeline happens and extends the field life, it will
increase the opportunity for more oil to flow down the TAPS
pipeline, and it will impact the economic viability of satellite
fields. It will also incentivize oil and gas exploration.
Thus, as exploration occurs for natural gas, more oil is likely
to be found.
12:40:48 PM
MS. KING discussed a list of economic drivers going into an open
season, beginning with the view of long-term natural gas prices.
Each company will make assessments spanning a 20 to 30 year
timeframe to project natural gas prices for the life of a
potential project. Another economic driver will be to assess
the natural gas that is available to ship, including
deliverability of the gas - the volume, rate, and length of
time. Typically, the nature of the terms of the shipping
commitment are not necessarily a commitment to ship gas, but
merely a commitment to pay a toll, whether or not gas actually
flows, and represents a risk borne by shippers of whether the
gas will be there over the specified timeframe. Additionally,
ConocoPhillips will review the transportation costs for the
actual toll to move gas from the North Slope to the Lower 48.
The fourth economic driver includes all other terms and
transportation fees, including many details. One key detail
will be the term or the length of the long-term shipping
commitment. Other economic drivers include the financial
arrangements, and how that translates into an actual cost of
service; and the receipt and delivery points, and whether
ConocoPhillips obtains the best opportunity to move natural gas
to the Lower 48 markets for the lowest cost possible.
ConocoPhillips will review all tariff terms and conditions, as
well as all state and federal tax and royalty structures. She
noted the potential for changes to the federal tax structures.
Thus, perspective shippers will be engaged in projecting actual
tax and royalty terms that will apply over the period of any
shipping commitment. She offered her belief that the risks of
the project remain high.
12:44:11 PM
MS. KING, in response to Representative Ramras, responded that
ConocoPhillips views ExxonMobil's involvement as a positive
step, and one that will increase the quality of an initial open
season. She differentiated between the diverse interests and
equity between ConocoPhillips and ExxonMobil on the North Slope.
Thus, ConocoPhillips will be actively engaged in the pre and
post-open season process, and will continue to monitor
ExxonMobil and TransCanada in order to ensure shareholder return
as the prospective pipeline project. In further response to
Representative Ramras, she answered that ConocoPhillips has
indicated numerous times its willingness to make changes from
the previous contract under the Murkowski Administration. She
offered that this is not the starting point. Instead,
ConocoPhillips views the current situation as an open discussion
about the terms and conditions today as a prospective shipper.
With anticipated updated cost estimates, ConocoPhillips will
consider the appropriate package that will move the issue
forward, being mindful that there are broader discussions
happening, not just with state taxes and royalties.
12:49:12 PM
REPRESENTATIVE RAMRAS offered his view that ExxonMobil was the
toughest negotiator during the negotiations between the
producers and the state under the Murkowski Administration.
ExxonMobil was the producer that demanded the hardest terms at
the table, while ConocoPhillips exhibited the most flexibility
in revisiting terms. It is interesting to view ExxonMobil on
the inside while BP and ConocoPhillips are on the outside of the
current AGIA pipeline, he said.
12:50:27 PM
CO-CHAIR JOHNSON noted his appreciation for the institutional
knowledge brought forth today, the focus on the future, and how
to bring forth Alaska's natural gas resource into a natural gas
pipeline. He characterized that process as problematic without
everyone on the same page.
12:53:27 PM
ADJOURNMENT
There being no further business before the committees, the joint
meeting of the House Resources Standing Committee and the House
Special Committee on Energy was adjourned at 12:53 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 6.11.09 PR for AGIA.pdf |
HRES 6/23/2009 9:00:00 AM |
|
| Agenda for 6.23.09.pdf |
HRES 6/23/2009 9:00:00 AM |
|
| TC and EM Alignment 6.23.09.pdf |
HRES 6/23/2009 9:00:00 AM |
|
| Alignment Summary TC and EM.pdf |
HRES 6/23/2009 9:00:00 AM |
|
| Denali Testimony June 23 2009 House.pdf |
HRES 6/23/2009 9:00:00 AM |