Legislature(2007 - 2008)TERRY MILLER GYM
07/09/2008 01:30 PM Senate SENATE SPECIAL COMMITTEE ON ENERGY
| Audio | Topic |
|---|---|
| Start | |
| SB3001|| HB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| = | SB3001 | ||
ALASKA STATE LEGISLATURE
JOINT MEETING
SENATE SPECIAL COMMITTEE ON ENERGY
HOUSE RULES STANDING COMMITTEE
July 9, 2008
1:40 p.m.
MEMBERS PRESENT
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Charlie Huggins, Chair
Senator Bert Stedman, Vice Chair
Senator Kim Elton
Senator Lyda Green
Senator Lyman Hoffman
Senator Lesil McGuire
Senator Donald Olson
Senator Gary Stevens
Senator Joe Thomas
Senator Bill Wielechowski
Senator Fred Dyson
Senator Thomas Wagoner
HOUSE RULES
Representative John Coghill, Chair
Representative Anna Fairclough
Representative Craig Johnson
Representative Ralph Samuels
Representative Beth Kerttula
Representative David Guttenberg
MEMBERS ABSENT
SENATE SPECIAL COMMITTEE ON ENERGY
All members present
HOUSE RULES
Representative John Harris
OTHER LEGISLATORS PRESENT
Senator Con Bunde
Senator John Cowdery
Senator Gene Therriault
Senator Gary Wilken
Representative Bob Buch
Representative Mike Chenault
Representative Sharon Cissna
Representative Harry Crawford
Representative Nancy Dahlstrom
Representative Andrea Doll
Representative Mike Doogan
Representative Richard Foster
Representative Les Gara
Representative Berta Gardner
Representative Carl Gatto
Representative Mike Hawker
Representative Lindsey Holmes
Representative Kyle Johanson
Representative Reggie Joule
Representative Scott Kawasaki
Representative Wes Keller
Representative Mike Kelly
Representative Gabrielle LeDoux
Representative Bob Lynn
Representative Kevin Meyer
Representative Mark Neuman
Representative Kurt Olson
Representative Jay Ramras
Representative Bob Roses
Representative Woodie Salmon
Representative Paul Seaton
Representative Mike Stoltze
COMMITTEE CALENDAR
SENATE BILL NO. 3001
"An Act approving issuance of a license by the commissioner of
revenue and the commissioner of natural resources to TransCanada
Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as
licensee, under the Alaska Gasline Inducement Act; and providing
for an effective date."
HEARD AND HELD
HOUSE BILL NO. 3001
"An Act approving issuance of a license by the commissioner of
revenue and the commissioner of natural resources to TransCanada
Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as
licensee, under the Alaska Gasline Inducement Act; and providing
for an effective date."
HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (S) READ THE FIRST TIME - REFERRALS
06/03/08 (S) ENR
06/03/08 (S) REPORT ON FINDINGS AND DETERMINATION
06/04/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/04/08 (S) Heard & Held
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07/01/08 (S) BILL CARRIES OVER FROM 3RD SPECIAL
SESSION
07/01/08 (S) ENR AT 9:00 AM BARROW
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07/09/08 (S) ENR AT 1:30 PM TERRY MILLER GYM
BILL: HB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (H) READ THE FIRST TIME - REFERRALS
06/03/08 (H) RLS
06/03/08 (H) WRITTEN FINDINGS & DETERMINATION
06/04/08 (H) RLS AT 9:00 AM CAPITOL 120
06/04/08 (H) Heard & Held; Subcommittee Assigned
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06/04/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
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07/02/08 (H) BILL CARRIES OVER TO FOURTH SPECIAL
SESSION
07/08/08 (H) RLS AT 1:00 PM KETCHIKAN
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07/09/08 (H) RLS AT 1:30 PM TERRY MILLER GYM
WITNESS REGISTER
PAT GALVIN, Commissioner, Department of Revenue (DNR)
POSITION STATEMENT: Supported AGIA
GENE DUBAY SR., Chief Operating Officer, Continental Energy
Systems
POSITION STATEMENT: Opposed AGIA
HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas
Development Authority (ANGDA)
POSITION STATEMENT: Presented information about an in-state gas
pipeline project.
DAN DICKINSON, CPA under contract to Legislative Budget and
Audit
POSITION STATEMENT: Supported AGIA
TONY PALMER, Vice President, Alaska Development, TransCanada
POSITION STATEMENT: Supported AGIA
STEVE PORTER, Consultant to Legislative Budget and Audit
POSITION STATEMENT: Presented information & answered questions
about Point Thomson.
BILL WALKER, Project Director, Alaska Gasline Port Authority
POSITION STATEMENT: Opposed AGIA. Presented information about an
in-state gas pipeline project.
RADOSLAV SHIPKOFF, Financial Advisor, Greengate LLC
POSITION STATEMENT: Opposed AGIA. Presented information about
the economics of an in-state gas pipeline project.
ACTION NARRATIVE
CHAIR CHARLIE HUGGINS called the joint meeting of the Senate
Special Committee on Energy and the House Rules Standing
Committee to order at 1:40:39 PM.
SB3001-APPROVING AGIA LICENSE
HB3001-APPROVING AGIA LICENSE
1:41:06 PM
CHAIR HUGGINS welcomed the panel members and thanked members of
the public for their input at these public meetings.
He had before him SCR 22 INSTATE PIPELINE/DISTRIB/SPECIAL
SESSION, which was introduced and passed on March 2, 2008, and
said that the topic of an in-state gasline was a strong common
thread through all of the recent public testimony. Today's
meeting would kick off with discussion of an initiative for a
possible joint venture to produce in-state gas.
1:44:56 PM
CHAIR HUGGINS recognized the panel organizations: Alaska Natural
Gas Pipeline Authority (ANGPA); Alaska Natural Gas Development
Authority (ANGDA); The Alaska Gasline Port Authority (AGPA);
TransCanada Alaska; Enstar; Legislative Budget and Audit (LB&A);
and Commissioner Pat Galvin of the State of Alaska, Department
of Revenue. He announced that Commissioner Galvin would
introduce the initiative he referenced in his opening remarks,
the financial implications of it, and a projected time schedule
to reach a contract.
1:46:00 PM
The panel members introduced themselves:
PAT GALVIN, Commissioner, Department of Revenue (DNR); GENE
DUBAY SR., Chief Operating Officer, Continental Energy Systems;
HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas
Development Authority (ANGDA); TONY PALMER, Vice President,
Alaska Development, TransCanada; BILL WALKER, Project Director,
Alaska Gasline Port Authority (AGPA); RADOSLAV SHIPKOFF,
Financial Advisor, Greengate LLC; DAN DICKINSON, CPA under
contract to Legislative Budget and Audit (LB&A); STEVE PORTER,
Consultant to Legislative Budget and Audit.
CHAIR HUGGINS reminded members that today's meeting would be a
round table discussion of various scenarios related to in-state
gas.
1:47:55 PM
PAT GALVIN, Commissioner, Department of Revenue (DNR) explained
that the state, Enstar and ANGDA were working together to form
the organizing structure for developing an in-state pipeline
that would initially be built from the existing fields in the
Cook Inlet area to Fairbanks with the intent to provide gas to
communities in the interior as soon as possible. It would use
existing Cook Inlet gas reserves and hoped to spur exploration
of new gas reserves. If new reserves could not be found and
additional gas was needed for Fairbanks and South Central, a
line would continue north in order to bring those gas supplies
into the system. They also saw an opportunity to hook this line
into the main line from the North Slope, so gas could move in
either direction.
The announcement was the beginning of the formation of this
partnership. Details were not worked out yet, but they expected
to make an agreement public within a few months, at which time
they would provide more detail about the organizational
structure of the entity and the expected financial involvement
of the players. They intended to provide any necessary
legislative requests at the beginning of the regular session in
January 2009.
1:51:05 PM
CHAIR HUGGINS asked Commissioner Galvin to review what led from
SCR 22 to a news conference announcing this partnership.
COMMISSIONER GALVIN responded that Enstar and ANGDA have been
focused on in-state gas for years. Their activities were
undertaken independent of each other and sometimes in
competition with one another. A combination of recent factors
had changed the landscape surrounding this issue, including the
state's focus on in-state gas and the high price of energy. When
the administration's discussions expanded in the last couple of
months to include Enstar and ANGDA, with the idea of focusing
the first phase on getting Cook Inlet gas into Fairbanks and
moving north from there, it was recognized as an opportunity for
them to work in tandem if an agreement could be reached. The
timing was right to advance the in-state line, to provide a
market for Cook Inlet gas and to get exploration going in Cook
Inlet.
1:55:07 PM
CHAIR HUGGINS asked where they got the 460 mcf/d volume figure
that was mentioned.
COMMISSIONER GALVIN said that was the number Enstar anticipated
to be their volume coming south. The actual flow of the line
would depend upon the market being served and the initial line
north to Fairbanks would not be that capacity because the market
was not sufficient for that volume. The opportunity to expand it
to that size would come with an extension north into the
foothills.
1:56:08 PM
GENE DUBAY SR., Chief Operating Officer, Continental Energy
Systems, the parent company of Enstar, added that they could
meet the communities' needs at fewer than 500 mcf/d.
1:56:54 PM
REPRESENTATIVE GUTTENBERG was pleased with the concern for
exploration and new reserves in Cook Inlet, but wondered what
efforts had been made to encourage exploration in the Nenana
Basin, which is only 20 miles from the Railbelt. He was told
that the Basin was comparable to Cook Inlet and had not been
tapped yet, and thought development there could save quite a bit
of pipeline and time.
COMMISSIONER GALVIN answered that he was absolutely right; when
he talked about phase one connecting the Cook Inlet area to
Fairbanks, one issue was whether gas would be found along the
route, and that would include the Nenana Basin. The Nenana Basin
was close enough to the Fairbanks area that its gas could be
linked into the Fairbanks system. He added that both Cook Inlet
and the Nenana Basin had fairly limited markets, so there was
not much incentive to finance exploration. The new pipeline
would spur interest in exploring both areas.
1:58:58 PM
REPRESENTATIVE GUTTENBERG asked if they had initiated
discussions with Doyon Limited on the Nenana Basin, or Atna
Resources Ltd. in the Glennallen area yet.
COMMISSIONER GALVIN replied that the new venture had not reached
the point of formal discussions. However, the state as a
resource owner had many discussions over the years with both
Doyon and Atna about where the gas would go and the need for a
pipeline to get it to market.
2:01:25 PM
REPRESENTATIVE HAWKER was gratified to hear of the collaboration
between Enstar, the state and ANGDA. He wondered how long the
administration had been in negotiations with Enstar over
bringing this together, and how far those negotiations had
really progressed. The press release sounded as if a deal had
been cut and he was interested to hear some more background.
2:02:35 PM
COMMISSIONER GALVIN responded that discussions had been going on
separately for quite a while, but joint discussions began only
recently. The administration chose to wait to announce it
publicly until they had a commitment from both parties to work
together toward one project. All parties had committed to work
diligently to reach agreement on a binding contract to bring to
the legislature with a clear statement of what the state's role
in it would be.
2:04:47 PM
REPRESENTATIVE HAWKER said the press release was the only
information he had received. He asked Commissioner Galvin to
comment on the public statement made by a senior member at ANGDA
that "It is a bit of a shotgun wedding..." and they were thrown
together very abruptly. He was put off by the use of that
expression by one of the partners to this collaboration.
COMMISSIONER GALVIN did not know who made that statement or what
the context was.
CHAIR HUGGINS referred to Commissioner Galvin's statement that
the parties had been working together for "some time" and asked
Mr. Heinze to clarify how long "some time" meant.
2:05:48 PM
HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas
Development Authority (ANGDA), explained that they were
contacted two weeks ago Monday to meet with the administration,
and met with Enstar for the first time the Wednesday after that
[July 2, 2008]. From ANGDA's point of view it was very early in
the process, but that did not mean they didn't have a strong
commitment to it.
CHAIR HUGGINS asked if Mr. Heinze or Mr. Dubay could address the
specific comment about a shotgun wedding.
2:07:17 PM
MR. DUBAY confirmed that the timeline was as Mr. Heinze
described. However, they had been working with the legislature
and the administration for a while regarding development of
their project and their supply requirements for the community.
2:07:47 PM
CHAIR HUGGINS said he understood that there were two proposed
routes, one along the Parks Highway and the other the Glennallen
spur route. He asked if that was still true or if Enstar was
considering other routes.
MR. DUBAY replied they had been working on a project along the
Parks Highway and had engineers in the field to better define
the cost, the time line, permitting, and the environmental
issues on that route.
MR. HEINZE interjected that the legislature needed to put all of
this in context. Because of Department of Energy studies that
had been ongoing for over 3 years, Enstar and ANGDA had both
participated in and evaluated projects that would use the Parks
Highway and the Glenn Highway/Richardson route. Those studies
were performed by very competent contractors and made part of
the public record. What changed a week ago was that they were no
longer talking just about a project; they were talking about a
business structure that they would be involved in and committed
to in a financial sense and in other ways. That would take time.
2:10:32 PM
REPRESENTATIVE GARA said he had heard many times since coming to
the legislature that Cook Inlet would be out of gas soon, so he
was surprised to hear about a proposal that would take gas from
Cook Inlet north. He asked Mr. Dubay how that jibed with the
presentations of the past few years that we were running out of
gas in Cook Inlet, and with the fact that about 40 percent of
Cook Inlet gas was being exported to Asia.
2:11:39 PM
MR. DUBAY advised that Enstar was not in the exploration and
production business and could only supply the community with gas
purchased under contract. So while they agreed that there might
be a lot more gas in the Inlet, they could only get the supply
they needed under contract through the end of 2013, and only had
all the deliverability they needed through the end of 2010. That
was why they'd discussed accessing additional gas with a line
into the community to serve their customers.
MR. HEINZE added that ANGDA would describe the issue as
deliverability, how much gas could be made available on a daily
basis on a cold day in the middle of winter, and he believed it
was awfully close the previous winter. He noted that the
administration was part of an agreement related to extending the
export license and had negotiated with Conoco Phillips and
Marathon to drill five wells each; he hoped those wells would
improve deliverability and be part of the solution.
With regard to the possibility of sending gas north, they had
looked at the volumes involved and, as he had stated in previous
presentations about the volumes of in-state gas, the heating
load was about 100 mcf/d; about 115 mcf/d was required for
electrical, and 250 mcf/d for industrial use, which was very
close to the 460 mcf/d number Commissioner Galvin mentioned.
More importantly, looking ahead, if they fed Golden Valley
Electric, the refinery, and Fairbanks Natural Gas, it would
require less than 50 mcf/d, a fraction of what was used in Cook
Inlet. He summarized that some improvement in the Cook Inlet
situation might make a difference in supplying gas to Fairbanks.
2:14:52 PM
REPRESENTATIVE GARA saw this as a concept plan rather than a
proposal and did not see what the legislature could accomplish
during this special session. He asked if someone was going to
assure them that the investment in a bullet line to serve the
Railbelt would be more cost effective than other options, such
as hydro power from Lake Chakachamna or geo-thermal power from
Mount Spur or more wind power.
COMMISSIONER GALVIN replied that they would expect to provide
information about the economics of this project in comparison to
other options that might be available when they brought them a
proposal asking for state participation. To preview that
discussion however, he anticipated that a line with this
particular design would incorporate a combination of things. Its
initial intent would be to provide gas to Alaskans, but also to
provide the opportunity for Cook Inlet gas and gas along the
route to ultimately reach a market. When they looked at the Cook
Inlet current reserves, they were in the neighborhood of 1.5 to
1.7 tcf. Given current consumption, that represented a 9 or 10
year supply. The very conservative estimates coming out of the
Alaska Division of Geological & Geophysical Surveys (DGGS) of
technically recoverable, economic resources that would likely be
found if the investment in exploration were made, were in the
neighborhood of 3 to 5 tcf. From the state's perspective he saw
two competing interests: 1) getting gas to Alaskans as quickly
as possible and at an affordable price, and 2) trying to
maximize development of Alaska's resources. This line was
intended to serve both of those functions.
2:18:22 PM
MR. HEINZE illustrated the conceptual nature of that by saying
the governor had not asked the organizations involved to stop
what they were doing. ANGDA was continuing to do wetlands
determination for a 300 mile spur line to Delta Junction. He
said what they might do as a result of conversations and in
order to meet Fairbanks' needs more quickly, was to continue
their wetlands work all the way up to Fairbanks along the
TransAlaska pipeline. If they could pre-build the spur line to
Delta Junction with a pipe that would hook into a big project at
some time in the future, perhaps running a high-density plastic
pipe for 80 miles, it might solve both problems without
incurring a lot of additional cost.
CHAIR HUGGINS asked Mr. Dubay to reflect, based on his
experience, on what impediments existed to delivering gas to
Alaskans.
MR. DUBAY replied that they were working on the engineering for
a line from Anchorage to the foothills area through Fairbanks.
As they were going ahead with the engineering work, Anadarko was
proceeding with exploration in the foothills area and Doyon was
working on exploration in the Nenana Basin; so they were trying
to identify the gas that would be available on that line. He
believed they had the customer demand from various sources
including utilities; Agrium, which he felt would commit to bring
the plant back up if Anadarko or Doyon made a commitment to
deliver gas; and a robust market in fertilizer and LNG.
He said that ANGDA also had contracts before the regulatory
commission for the additional supply they needed for 2009
through 2013 and that was a hurdle. If they were unable to
secure approved contracts for supply in the short term, he did
not see how they could have certainty with regard to a longer
term commitment either for space in a line, or for a commitment
to purchase gas from a producer. He stressed that they all
needed to work together; they needed to get an agreement and a
structure together as soon as possible.
2:22:44 PM
MR. HEINZE said, in addition to the Regulatory Commission of
Alaska (RCA) and the importance of approved supply contracts,
two other hurdles for an in-state pipeline were:
1) Project permitting including right-of-ways, U.S.
Army Corps of Engineers permitting, Environmental
Impact Statements (EIS) and other permissions; and
certification from the RCA as a pipeline. He explained
that these generally required 1 to 2 years of field
work.
2) An in-state open season involving North Slope gas
would utilize a portion of the statute that had never
been used by the RCA. They would recommend some
changes to it that would give the RCA greater
flexibility in how it would deal with those issues.
2:23:40 PM
CHAIR HUGGINS opined that it was incumbent upon the legislature
to make the RCA effective, efficient, and timely in the long-
term.
2:24:06 PM
REPRESENTATIVE CHENAULT said he ought to be happy to hear talk
of revitalizing the Agrium plant, which employed 300 people over
time; and he was please that they seemed to have a lot more gas
in Cook Inlet than he had realized. He questioned Commissioner
Galvin's statement that the administration was not asking for
anything at that time, because he had a request for $25 million
from the administration for engineering, permitting, planning
and design of this project, which he believed would end up in
the capital project summary.
He also said, while he would love to see more gas in Cook Inlet,
or gas from the North Slope to Cook Inlet or the Railbelt area
for use by individuals, they continued to talk about keeping the
Agrium plant in business. In reality, whether Agrium or the LNG
plant could continue to operate would depend on the price of
that gas. If the gas price was too high it wouldn't matter how
much there was, because they would not be able to compete in the
world market. He was concerned about investing a lot of money to
send gas north, spurring investment in the Cook Inlet for only a
short time, and felt they needed to do a lot more talking about
it.
2:26:33 PM
CHAIR HUGGINS said he saw the $25 million also.
2:26:43 PM
MR. HEINZE responded that the $25 million was a request to cover
work on the right-of-way, preliminary engineering, permitting,
planning, and design of a 370 mile spur line from Delta Junction
to Beluga. That line would be a continuation of the project that
the legislature had already been funding and which he felt was
in the best interests of Alaskans. He said they were on a very
aggressive time-line and, if they were to maintain that schedule
to reach open season at the same time as the AGIA licensee, it
would require the $25 million.
2:28:19 PM
DAN DICKINSON, CPA under contract to Legislative Budget and
Audit (LB&A), said his question revolved around whether the
parties would seek to have this pipeline regulated by the RCA,
to have the initial certification done by the legislature or by
some other process.
A lot of this had been adjudicated in a small sense already.
Fairbanks Natural Gas was taking gas from Cook Inlet, extracting
the liquids and trucking them up to Fairbanks where it had
industrial customers. As it began to have supply issues, it had
some adjudication before the RCA and he believed it was
extended, allowed a short-term contract, and asked to find other
solutions. He thought that, earlier in the year, the solution
they came up with was a supply contract with Exxon for the North
Slope, where a small amount of liquids could be extracted and
trucked south to Fairbanks. So the RCA had already looked at the
issues of supply and demand there and whether it made sense to
take liquids up to Fairbanks. It had come up with the more
traditional view, which was that exploration would have to keep
going to make the gas that would be used in 2013 and beyond as
contracts expired.
2:30:04 PM
REPRESENTATIVE FAIRCLOUGH noted that a major concern raised in
discussion over the previous 30 days was triggering the treble
damages in the AGIA clause while providing for in-state gas.
Specific to that, 500 mcf/d would be the trigger point for those
treble damages if no in-state line existed and the big line had
not been built. With that said, she asked Commissioner Galvin
and Tony Palmer if she was correct in her understanding that
TransCanada wanted to provide the gas line itself for Alaska.
COMMISSIONER GALVIN asked which gas line she was referring to.
REPRESENTATIVE FAIRCLOUGH replied that she meant the in-state
gas line. She said that in previous hearings TransCanada offered
to facilitate building the in state portion of the line.
TONY PALMER, Vice President, Alaska Development, TransCanada,
corrected that TransCanada's proposal had been to build the main
line from Prudhoe Bay to Alberta and if sufficient gas volumes
were nominated to Valdez, they would build the line to Valdez.
They had never proposed building a "bullet line" to Anchorage,
although they had proposed to provide off-takes off the main
line, which would be available along the route to Delta Junction
or, if a line were built to Valdez, along that route as well.
2:32:25 PM
REPRESENTATIVE FAIRCLOUGH addressed Commissioner Galvin saying
that the administration told the legislators 30 days ago that
half a bcf was sufficient off-take for the big line, but the
proposal before them was already at 460 mcf/d; she wondered how
they were supposed to balance that. If, within a private sector
development, they had 460 mcf/d proposed to provide gas to just
the Anchorage or Railbelt area, she wondered how they could
reconcile that with his statements that .5 bcf/d would handle
the entire in-state load until the big line was built.
COMMISSIONER GALVIN replied that the 460 mcf/d was Enstar's size
going from the foothills south; that had to do as much with
supply and the amount of throughput they anticipated as it did
with the expected demand in the Cook Inlet market. What the
administration provided information on was just the demand side,
that is how much demand they expected to have for Alaska during
the time in which the treble damages clause would be a factor.
The 500 mcf/d would be more than sufficient given that they also
had Cook Inlet supplies to meet the demand during that time.
He continued to say that on this particular project, the line
would go from south to north to pick up the additional needs of
folks along that line. He added that it was difficult to balance
these things because they were comparing apples to oranges, and
the question came down to why one would build a pipeline
designed with a throughput of greater than 500 mcf/d. In state
demand could not reasonably be expected to exceed 500 mcf/d in
that time frame, so the only reason would be to improve the
economics of the line. From the administration's perspective,
the 460 mcf figure provided corroboration of the upper limit of
demand during the period to which treble damages would apply.
2:35:49 PM
MR. DUBAY confirmed that 500 mcf/d should meet the demands of
the community based on historical load profiles.
REPRESENTATIVE FAIRCLOUGH said she was not convinced that .5
bcf/d was going to sustain the state until 2017, which was the
earliest they could reasonably expect to see gas flow on the big
line. She also questioned whether the state was being a good
partner to TransCanada by supporting another line that would
pull customers away from them.
2:37:07 PM
MR. HEINZE said a reasonable projection for heat and light to
Alaskans would be 250 mcf per day. In addition, Fairbanks might
take 50 mcf per day for the refinery. He hoped to have
industrial customers as well, but at open season the applicants
would have to come forward with more than an expression of
interest. He estimated the total commitment for utilities in the
State of Alaska would be about $10 billion, but they had not yet
found anyone willing to even talk in that scale of numbers, so
he felt they could count on only the residential utility
business.
With regard to the relationship with TransCanada, he said
whether the pipe was Denali or TC Alaska, they were customers of
that pipeline and intended to ship their gas in the first 540
miles of it. He saw no way in which that would be in competition
with their purpose.
2:39:00 PM
REPRESENTATIVE FAIRCLOUGH asked TransCanada if Alaska was being
a good partner right now.
MR. PALMER answered that based on his understanding, the
proposal as currently structured would be within the bounds of
AGIA and would not breach in any way the state's obligations to
TransCanada. As long as the state stayed within those boundaries
he saw no problem.
REPRESENTATIVE FAIRCLOUGH queried very specifically whether a 20
inch pipe that was proposed to carry 460 mcf and that could be
expanded to over 500 mcf would cause TransCanada to attempt to
recover damages based on the treble damages clause in AGIA.
MR. PALMER replied that a 20 inch line designed to flow less
than 500 mcf/d and actually flowing less than 500 mcf/d until
the big line was in service, would not trigger treble damages
under AGIA.
REPRESENTATIVE FAIRCLOUGH asserted that the line would
accommodate up to 700 mcf/d and wanted to be clear that it would
not kick off the treble damages.
MR. PALMER responded that the 700 mcf/d was a new number to him;
his understanding was that the project would be designed to flow
less than 500 mcf/d. By that he meant that it would have the
facilities installed to flow less than 500 mcf/d. He gave an
illustration: If someone constructed a 48 inch pipeline,
dribbled through 460 mcf a day and took a subsidy from the
state, it would clearly be a breach. But if the facilities were
designed and installed to flow less than 500 mcf a day, it would
not trigger treble damages.
2:43:15 PM
STEVE PORTER, Consultant to Legislative Budget and Audit, said
he thought that the clause was intended to look at a 500 million
a day project that was in competition to TransCanada, and gas
coming from Cook Inlet and going to Fairbanks would have nothing
to do with that clause so it was nothing to worry about. What
they might need to worry about would be competing against North
Slope gas.
2:43:50 PM
MR. PALMER read the portion of the clause that dealt with this
and summarized that, if over 500 mcf of Cook Inlet gas were
going north it clearly would not be in competition.
REPRESENTATIVE FAIRCLOUGH pointed out that they had been told
they could not "flag" Alaska's molecules [of gas] and, if
Fairbanks were a consumer, it would put TransCanada in a
position to argue that it was a competing line because it took
away part of the market.
2:44:41 PM
MR. HEINZE said there was also the technical part of the
question, which was that a 20 inch pipe had a varying capacity
to carry gas, depending on how many compressor stations might be
installed. He asserted that, with a 20 inch pipeline and the
volumes needed in Alaska, they would only need one compressor
station located in Glennallen to bring the gas in. That project
would clearly be under 500 mcf/d. If someone wanted to move more
gas through that pipeline at some future time, the RCA would
require the addition of other compressor station/s to
accommodate greater throughput. The upper end number was a
reasonable estimate of what you could get on that project if you
built it out all the way.
2:45:43 PM
MR. PORTER agreed with Representative Fairclough that, if there
were a Fairbanks market for over 500 mcf/d and that took away
somehow from the trunk line, it might be a problem; but
Fairbanks would need only about 50 mcf. He cautioned that they
needed to focus on the business plan and decide now whether they
wanted to build the pipe of a size to take advantage of North
Slope gas coming south in the future. That would be the only
reason for the size of the pipe. He also opined that this was an
opportunity for creativity regarding how to maximize local
hiring and training, and recommended they build this pipe before
the big one got underway as there would not be enough workers to
build both at the same time.
2:47:34 PM
MR. PALMER clarified that he was the author of "you can't flag
your molecules" and that was true once they were comingled in
the pipeline. However, they would know the source of those
molecules and the intention was clear that if there were more
than 500 mcf per day coming from the North Slope it would
trigger damages.
2:48:05 PM
COMMISSIONER GALVIN wanted to clear up a misconception regarding
the issue of competing gas. He said the competition was for the
gas, not for the market, not for the sale. The question was
whether they were trying to move North Slope gas off the North
Slope at greater than 500 mcf/d. The reason this discussion was
relevant was due to the possibility of phase two of the project.
If they planned to build from Fairbanks north to the foothills,
that area was considered under the definition of AGIA to contain
North Slope gas. If they simply built phase one from Cook Inlet
to Fairbanks and sufficient supplies were discovered either in
Cook Inlet or along the route so they never had to build phase
two, it would have absolutely no implications for AGIA
regardless of the size or the design. He emphasized that when
they talked about 460 mcf/d they were talking about the
potential for a line going up to the foothills and bringing gas
down. So phase one would have no implications under AGIA; it
would only be an issue if they had to build the second phase and
bring North Slope gas down into the rest of the state.
2:49:34 PM
CHAIR HUGGINS said he shared Representative Fairclough's
concern; the legislature wanted to get gas to Alaskans and did
not want any impediment to that.
2:49:51 PM
REPRESENTATIVE DOOGAN said that as he understood it, the
difference between today and the day before the press conference
was that there had been the announcement of a partnership that
had yet to be formed, to ship gas that had yet to be discovered,
in what seemed to most people to be the wrong direction, in a
pipeline that had yet to be built and details would follow. He
asked if he had gotten the gist of it.
2:50:54 PM
COMMISSIONER GALVIN conceded Representative Doogan's
characterization of the situation, but noted that the
administration deemed it a significant advancement to have
Enstar and ANGDA working together to advance this project. He
agreed that, before asking for anything associated with the
project, the state would have to provide much more information
than they had done to date; but they were not at that point.
Going back to the question about the appropriation however, he
said that money was being requested to get the route moving
because it would satisfy either outcome, a spur line or this
particular project.
2:52:12 PM
CHAIR HUGGINS requested a tentative time-line to reach a
contract. He also asked that the energy coordinator be
introduced to the committee and made available for questions.
2:53:00 PM
REPRESENTATIVE SALMON indicated on the map that the pipeline
proposed to cross the Tanana and Yukon Rivers. He said there was
another route that ran from Nenana up and down the Yukon River,
which should also be considered. He pointed out that there had
been little discussion about which route would be used, or about
the possibility of barging gas to river villages.
2:54:52 PM
COMMISSIONER GALVIN referred Representative Salmon's concern to
Mr. Heinze.
MR. HEINZE responded that ANGDA recognized at least one third of
the population could not be reached by pipeline. Fortunately
North Slope gas is extraordinarily rich in propane; their
estimate was that over 50,000 barrels of propane a day could be
carried down a big mainline pipe. With that in mind, they looked
at what it would take to separate propane at the Yukon River,
for instance, and move it up and down the river system. They
believed that had a lot of potential and were working with the
City of Tanana on a demonstration project to understand how they
would use propane in that community, which they felt was the key
question. He had also hired a propane coordinator who was under
contract to develop a commercial wholesale propane facility
within one year, with the cooperation of the producers. He added
that it might also be of value to truck propane to Fairbanks, as
it was not uncommon in the gas industry to feed a distribution
system with a propane/air mixture.
2:56:42 PM
REPRESENTATIVE SALMON said it seemed as if private industry was
again dictating to the state what it could and could not do,
when the state should have been telling them what it wanted. He
asserted that the state had an infrastructure already in place
off Nenana and they should use it.
2:57:18 PM
MR. HEINZE reminded him that the legislature funded both of the
programs he had been talking about.
2:57:33 PM
REPRESENTATIVE RAMRAS applauded Mr. Galvin and the
administration for moving so aggressively to facilitate an
agreement between ANGDA and Enstar. He asked if he could have a
list of the meetings the administration had had with Enstar
specific to this issue. He also reminded Senator Stedman that
they were only seven days away from voting on AGIA, and
reiterated his request for a list of meetings between the
administration and the producers with regard to getting gas into
the line.
CHAIR HUGGINS said he would provide both of Representative
Ramras' requests to the administration in writing.
2:59:34 PM
SENATOR WIELECHOWSKI said he had heard in at least a dozen
presentations that they were running out of gas in Cook Inlet,
so he was surprised to see a proposal to send gas north. He had
also heard that the cost of building a bullet line from the
North Slope down to Anchorage would be about $3 billion; the
cost to import LNG for natural gas would be about $3 billion;
and the cost of exploration to get more gas out of Cook Inlet
would be about $3 billion. When the legislature took up the
issue of an in-state gas line in the special session, the
administration was violently opposed to it and said Alaska was
better off building the big line and using economies of scale to
keep the tariffs low. He wondered what had happened to change
their opinion.
3:00:35 PM
COMMISSIONER GALVIN disagreed with the Senator's
characterization that they were "violently opposed" to the
resolution. The issue at the time was the timing of the
resolution and the purpose of the issue coming up at that
particular moment. Regarding economies of scale, that was a
recognition that in the long term, the focus was on getting gas
off the North Slope, getting it to market, and providing both
revenue to the state and the opportunity for off-take of that
gas for Alaskans. They acknowledged, within that same time
frame, that a bullet line was part of the discussion. The
economics of a bullet line remained in question, but they had
said consistently that the state's involvement in either a
bullet line or a spur line was a factor in those economics. It
was a question of what would give the state the best bang for
the buck.
They talked about Cook Inlet running out of gas because the
known supplies of gas were being depleted and they had not
discovered any new gas fields, although a number of studies
indicated that they should be out there. The evolution of the
discussion, which spurred the group to come together, was the
administration's suggestion that they combine the issues of
giving Cook Inlet gas the opportunity to reach bigger markets
and spurring interest in exploration, while also meeting the
short-term need to get gas to Alaskans as soon as possible.
With the formation of this idea to go from Cook Inlet north and
then build off from there if necessary, the economic discussion
changed; they were no longer looking simply at the most cost
effective way of delivering gas to Alaskans, but also at getting
Cook Inlet gas to market. In that context the analysis changed
and the opportunity presented itself for the state to do more
than just fulfill the needs of the households along the way.
3:04:34 PM
CHAIR HUGGINS asked what the difficulty was with the timing of
the resolution.
COMMISSIONER GALVIN could not recall and thought it might have
been because they were near the end of the session.
CHAIR HUGGINS pointed out it was only half way through the
session and said he took exception to the commissioner's
comments as he had offered that resolution.
3:05:15 PM
REPRESENTATIVE HAWKER asked Mr. Dubay about the impediments he
saw to expanding their ability to deliver gas to Alaskans,
particularly the RCA regulatory hurdle they were facing with
their existing contracts. He commented that he had read a
newspaper article recently that said Chugach Electric filed as
an "intervener" in their regulatory proceedings, and questioned
whether Chugach's counsel was also under contract to the
administration. He was also interested in the issue of expansion
permitting in Cook Inlet.
3:06:43 PM
MR. DUBAY clarified that when he spoke of "impediments" he was
not referring to construction, engineering, or licensing, which
he considered tasks rather than impediments. He acceded that
Chugach was an intervener in their gas contracts case and that
two of the experts Chugach was using were Litsinger and Hosie
[Spencer Hosie, Hosie/Rice LLP], who had represented the state
on royalty issues. The experts took the position that the
producers were obligated under royalty agreements to develop and
produce the reserves, so Enstar didn't really need to meet a
market price. That position conflicted with Enstar's, which was
that they wanted to see the producers continue to develop
reserves in the inlet and were looking for ways to promote that
interest.
Enstar supported relicensing the LNG plant because they felt it
was an important anchor as a customer off a new line, and that a
longer license period would give the producers more incentive to
develop production within the inlet, off the foothills, in the
Nenana Basin or anyplace where they had access to a line. That
license was extended through 2011.
3:10:33 PM
REPRESENTATIVE HAWKER thanked Mr. Dubay for his testimony and
commented that he would feel much better if he could hear
additional details from Chugach to better understand the
foundation of the regulatory dispute.
3:11:16 PM
CHAIR HUGGINS asked the commissioner if he had any comments.
COMMISSIONER GALVIN said he had nothing to add.
CHAIR HUGGINS encouraged each member of the Judiciary Committee
to look at the propriety of having legal experts being paid to
look at both sides of the issue.
3:11:28 PM
SENATOR DYSON said he knew of no Cook Inlet geologist who did
not think there was a lot more gas in Cook Inlet. USGS testified
only a week or so before that there was a reasonable expectation
of 17 tcf/d in Cook Inlet. Senator Wagoner, Representative
Keller and he wrote to the president asking for permission to
explore in the Eastern part of the Cook Inlet basin under the
federal lands and, thanks to Senator Steven's efforts they
received some interesting contact from the Department of the
Interior about that. He stressed however, that in order to get
the explorers to spend money on Cook Inlet exploration there
would have to be a market for more gas, and that meant the
industrial users.
He felt they had done a good job of providing tax advantages for
Cook Inlet explorers, and the administration gave the LNG export
license some teeth for replacing if not increasing the reserves;
but people who knew Cook Inlet economics had been saying for
years that they needed to build a spur line or bullet line to
connect with the main line and give them a decades-long market
to all of North America.
CHAIR HUGGINS paused to recognize Representative Richard Foster.
3:14:47 PM
SENATOR THOMAS said he had been looking at the Econ One demand
study published in 2002, which combined the residential,
commercial and industrial historical use figures and projected
them out to 2020. They also calculated a petrochemical plant,
doubled Agrium, put server barns in place in Alaska, converted
every coal burning generator and plant to gas and even put gas
in places for which there was no transportation. He believed
that is where people were getting the figure of half a bcf per
day of gas in 2020. He wondered what would drive the drilling
operation in Cook Inlet to get things moving if Agrium was out
of business and they couldn't supply Fairbanks with natural gas.
What could they do to get exploration moving?
MR. DUBAY ventured that to invest in exploration a producer
would want to understand where they could sell what was produced
and what they would be paid for it. He pointed out that there
was some uncertainty with regard to the market. Agrium could
take gas if it was in sufficient quantity to keep the plant
going, but there had been some uncertainty because their LNG
plant license was scheduled to expire in 2009. There was also
uncertainty with regard to the price, because their last supply
contract with Marathon was rejected by the RCA.
3:18:41 PM
MR. HEINZE added that to the extent oil prices were
significantly above what they had been one year before, anyone
in the exploration/production business had tremendous incentive
to find places to increase their production of both oil and gas,
and they were doing that. He felt there should be some price
effect in Cook Inlet as well, but they may not have been seeing
the full price effect on the supply side. The other part of it
was the uses of gas in Alaska; fertilizer, LNG delivered across
the Pacific Rim, all of those commodity prices were up so
significantly that the economics of those activities were very
attractive, yet they were not seeing a lot of people respond.
3:19:58 PM
SENATOR THOMAS opined that building the line north sooner rather
than later seemed like a wise idea.
3:20:14 PM
SENATOR COWDERY asked Mr. Palmer what would have to happen for
the state to incur treble damages. He also questioned whether
the price of Cook Inlet gas going south would be the same price
as that going north.
3:21:17 PM
MR. PALMER said the statute set the responsibilities of the
state out quite clearly with regard to what would incur treble
damages. If the state granted TransCanada a license and then
breached the statute by providing financial incentives to a
competing project of over .5 bcf/d it would be obliged to pay
treble damages.
He could not answer Senator Cowdery's question regarding the
price of gas coming south from Prudhoe Bay. If Fairbanks gas
were connected to the overall marketplace in North America, it
would be a fairly straightforward calculation, not specifically,
but a basis differential between transportation points along the
pipeline would be relatively straightforward to understand. If
there were no liquid market in Fairbanks and the large pipeline
was in place, you could get a proxy of what the price would be
by looking at the first liquid market, which would be Alberta,
and deducting the transportation costs. It might not always
trade in Fairbanks at that exact cost differential, but it would
often trade in that range. If Fairbanks was not connected to the
North American market and you were strictly moving gas from Cook
Inlet north, you'd have to look at a test case of how Cook Inlet
gas was being priced. He suggested that Mr. Dubay might be able
to add something.
3:23:42 PM
MR. DUBAY said they had gas under contract using both a Henry
Hub price and an oil index price. Under proposed contracts, they
had a number of different delivery points for Conoco and
Marathon. He emphasized that they had not negotiated contracts
beyond 2014, so he did not want to guess what that price would
be, but said that usually where there was more production than
demand, there was a discount to the index. Where there was less
production than demand, there was some kind of premium to the
index. They were hoping to have more production available into
Cook Inlet than they had demand. If what happened in other
producing areas was an indicator, they should end up with a
discount and a better price.
3:26:39 PM
REPRESENTATIVE SAMUELS asked if his business model was to become
the local distributing company (LDC) in Fairbanks.
3:27:15 PM
MR. DUBAY replied not at this point.
REPRESENTATIVE SAMUELS asked if Enstar would need strong
assurances that they would have more exploration, more gas and a
big pipeline before they would put their shareholders' money in
the south to north project.
MR. DUBAY replied not necessarily. They had been working for the
past several months toward developing a line along the Parks
Highway route from Anchorage to the Foothills. When they looked
at the business model for that pipeline, they looked at
Fairbanks being part of that load, but saw them as a "city gate
customer." That is, they would not have all the residential
users; they would be delivering gas to Fairbanks and the
industries around Fairbanks, but it wouldn't be their
distribution system. He clarified that when he talked about "the
customer group" he was talking about Agrium, the Flint Hills
Refinery and that type of customer. Production would be from
Anadarko and Conoco Phillips in the foothills and Doyon if they
found gas in the Nenana Basin. If they started south to north
and a lot of gas became available in the Cook Inlet, he could
see how they might continue past Fairbanks.
3:30:22 PM
REPRESENTATIVE SAMUELS submitted that it would not be in
Enstar's business model to put their capital at risk before gas
was committed to the pipeline. He asked how the timing would
work.
3:30:56 PM
MR. DUBAY replied that they were trying to get the engineering
done in early 2009 and were scheduled to meet with Anadarko the
following week with regard to their drilling and exploration
activity. He expected them to commit to having two rigs in the
foothills for the next drilling season. They had a lot of
permitting and environmental work to do between spring of 2009
and 2010, but he believed that they would be ready to dig a
trench in 2010 that would give them lot more data about the gas
available to the line before they committed hundreds of millions
of dollars. Overall he felt the timing should work out pretty
well for gas delivery in Cook Inlet in 2014.
REPRESENTATIVE SAMUELS questioned, since Anadarko had no way of
knowing when the big line would be built, when they would start
spending exploration capital.
MR. DUBAY said he was reassured by the fact that Anadarko was
already spending significant dollars on its exploration effort.
He reiterated that he was confident by the time they were ready
to lay pipe next year, Anadarko would have the confidence they
needed that the line would be built, and Enstar would have the
confidence they needed that they'd have supply to go into the
line.
3:34:34 PM
MR. HEINZE added that the question Representative Samuels raised
of whether you drill wells before there is a pipeline, or build
a pipeline before you drill wells, was a fairly common one in
the industry. In Wyoming, the Wyoming Natural Gas Development
Authority played a major role in standing between the pipeline
builders and the explorers and giving both the confidence to
move forward. The result was the timely building of a pipeline
to tap into the drilling of exploration wells. He suggested the
state consider some way to encourage both activities to occur
and lessen risk for the capital investment involved.
3:35:25 PM
MR. PORTER went back to Senator Cowdery's question about treble
damages and whether changing the production tax would trigger
them. The production tax discussions occurred before, during and
after AGIA; there was a plan to deal with the gas tax issue and
it was not intended to be in conflict. The statute itself said
"if the state extends to another person preferential royalty or
tax treatment..." so changing the gas tax equally for all
parties without regard to a specific project would not trigger
damages. He cautioned however, that extending TransCanada's
benefits, such as fiscal certainty at open season for their
shippers, to other parties would be in violation.
3:36:50 PM
CHAIR HUGGINS announced a break at 3:36:58 PM.
CHAIR HUGGINS called the meeting back to order at 3:57:39 PM.
BILL WALKER, Project Director, Alaska Gasline Port Authority
(AGPA), said this had been a helpful discussion and he
appreciated the opportunity to comment. They were surprised to
read about this association in the media and would like to have
had the opportunity to learn about it and see where they could
add value to it; but their calls to Enstar attempting to set up
a meeting were not returned.
He was concerned to know how they could work within the confines
of the exclusive license without triggering the treble damages.
Looking at life after AGIA, he wondered whether they could
continue to work on the project they had been pursuing for 10
years, a line from Prudhoe Bay to Valdez, without in some way
violating AGIA.
He stated that their project remained the same, an "all Alaska"
line from Prudhoe Bay to Valdez. They had always believed the
most economic gas would come off a large line, so their project
called for a 48 inch pipe to Delta and a 42 inch pipe to Valdez,
with a spur line off at Delta.
He introduced Radoslav Shipkoff to respond to questions
regarding the financial aspects of their LNG project.
4:01:36 PM
REPRESENTATIVE CRAWFORD noted that when they were talking about
the liquifaction facility, the administration provided numbers
that were much higher than what the Port Authority had come up
with. He wondered if the time frame in which they were generated
could account for the difference between their numbers.
4:02:25 PM
RADOSLAV SHIPKOFF, Financial Advisor, Greengate LLC, agreed that
the LNG plant was one of the principal areas of discrepancy
between their assumptions and the assumptions used by the
administration in their evaluation of the relative economics of
the two projects. The Port Authority's estimate was developed by
Bechtel on the basis of an extensive technical study, which
involved a large team of highly qualified engineers who had
extensive experience in implementing large liquifaction projects
of this type. Their understanding of the administration's
analysis based on the materials that were made public was that,
rather than creating a bottom-up evaluation of the cost of the
plant taking into account the specifics of the proposed project,
they implemented a top-down approach, which had taken a wide
database of projects implemented world-wide and looked at the
variability of costs per ton of capacity. They then translated
that into what, in the view of that analysis, the cost per ton
of capacity would be for the Valdez Project and translated that
cost per ton into the figure for the total plant based on the
capacity AGPA was proposing.
MR. SHIPKOFF pointed out several problems with that methodology.
The commercial and technical literature frequently cited dollars
per ton for the cost of LNG plants, but not all LNG plants were
the same. One would have to take into consideration the scope of
the project, the specific technical parameters involved with
that scope, and the location.
He explained that the location-specific factors would make it
very difficult to compare a project in one location with a
project in another location. For example, many LNG projects
involved an integrated gas monetization solution which had an
upstream component and, tied to the upstream component, the
liquifaction onshore aspect. The LNG plant in itself frequently
included gas treatment facilities including liquid sludge
removal, condensate stabilization, acid gas removal,
dehydration, and mercury removal. All of those components would
be included in the figure cited as dollars per ton. In the case
of this project, that function would be performed on the North
Slope.
A second technical aspect that did not appear to have been taken
into account by the administration was the high pressure of the
feed gas fed into the Valdez plant from Prudhoe Bay. A
significant amount of cost which would otherwise be installed in
the plant for compression could be saved because the gas would
arrive at high pressure. The ambient conditions should also have
been taken into account as the colder climate in Valdez would
create additional savings. Bechtel advised that the combination
of high pressure feed gas and the ambient conditions alone would
result in cost savings of between 35 and 40 percent.
Site preparation would also vary greatly from one location to
another, as would the cost of marine terminal facilities.
Bechtel's estimate was based specifically on the Anderson Bay
location, which had very favorable conditions with regard to the
costs associated with the marine terminal.
Additionally, one would not generally know what comprised the
figures that were put out in the public domain or whether they
were inflated. So when you put all of those variables together,
this methodology would not result in a probability distribution
of the capital cost of the LNG plant, which was supposed to
reflect the risk profile of the LNG plant in Valdez. It would
really reflect the distribution and the variability of the
various factors that were location specific.
4:08:00 PM
He pointed out that the probability distribution presented by
the administration with respect to the LNG plant had a p25 to
p75 variability, which was $6 to $8 billion compared to the p25,
p75 variability of the pipeline, which was only $2 billion. The
engineers who looked at cost risks associated with the pipeline
and the LNG plant told them that the cost variability associated
with the pipeline was significantly larger than that of the LNG
plant, because the unknowns associated with the pipeline were
significantly greater. While they would certainly expect some
unknowns with an LNG plant, they used a fairly well established,
proven design.
4:09:50 PM
CHAIR HUGGINS asked if he agreed or disagreed with the
administration's analysis.
MR. SHIPKOFF replied that they disagreed with the
administration's estimate of the cost of the LNG plant because
they did not believe it took into account factors specific to
the location. He said they did agree with some of the
assumptions regarding prices in various potential markets for
the LNG project; so if he used the LNG plant cost assumption
developed by Bechtel and a range of assumptions for prices
developed by both the administration and the legislative
consultant, a strong case could be made that, under a wide range
of price scenarios, the economic proposition to the producers in
terms of netback price per Mmbt on the North Slope was the most
attractive for the LNG project.
4:11:04 PM
REPRESENTATIVE GATTO said he was confused by the assertion that
costs could be reduced 40 percent due to environmental
conditions affecting the gas. He asked if Mr. Shipkoff was
mixing operational costs with construction costs.
MR. SHIPKOFF answered that temperature and pressure would
directly influence capital costs because they determine the
amount of compression necessary to liquefy the gas, which would
be installed as part of the capital costs.
REPRESENTATIVE GATTO asked if he was saying the administration
failed to include those factors in their analysis.
MR. SHIPKOFF said he had seen only the materials the
administration made public and had tried to determine their
methodology from that. Based on their description, it appeared
that they had derived their cost per ton estimate based on a
database of projects worldwide, most of which had conditions
that differed significantly from the unique conditions of this
project.
4:13:09 PM
REPRESENTATIVE SEATON said that Cook Inlet had been a stranded
gas basin with no external market other than limited industrial
capacities and questioned what the price scenario would be if it
were connected into a large pipeline. He wondered if the RCA
would consider Cook Inlet gas the same price as Alberta gas
since it was indirectly connected to that market, and how that
would affect the project going forward.
4:14:17 PM
COMMISSIONER GALVIN replied they could not project what the
price would be, but could discuss the relative price between
different options. He observed that what they had right now was
the Cook Inlet, South Central area transitioning from a fairly
low cost to produce gas, to a price that would be high enough to
incentivize development costs for new gas. If they projected
that out in isolation from the rest of the system, either they
would transition out of gas or continue to increase the price to
the point that it would encourage enough exploration to meet
their demand.
He elaborated, if they factored in the option of connecting Cook
Inlet to a larger market by a spur line or hooking into the main
line, it would end up connecting Cook Inlet to the North
American market in general. At that point pricing would be a
combination of the cost to produce in the local area and the
availability of other gas on the system, and that system would
include North Slope gas with gas from other basins along the
route. So the price would be a combination of that integrated
market. He considered the relative advantage of that versus not
having the connection and, based on their projection of what the
North American market would bear, the price would probably be
below the expected cost to develop the resource independently,
so in that way the consumer would end up in a better position.
In response to the second part of Representative Seaton's
question, how that would affect the economics of the line, he
felt that was what they needed to be looking at as they
developed the project plan. They needed to determine if the
price was going to be such that it could cover the cost of
transporting the gas through the system, or if there would have
to be other state involvement to make the price reasonable and
bring that transportation cost down.
REPRESENTATIVE SEATON referred to Mr. Dubay's comment that he
hoped to have more production in Cook Inlet than they had demand
in order to keep the price down. He asked if tying that gas into
the large line going through Canada would equalize prices, and
whether he anticipated that the price of gas throughout the
system would be basically Alberta hub minus location sensitive
charges.
4:18:45 PM
MR. DUBAY replied yes, if you could take Cook Inlet gas
someplace else without permitting impediments, then you would be
able to get that price less the transportation. He added that it
seemed like that might be a ceiling as opposed to a floor; but
he thought local use could get it at that price or below the
delivered price minus transportation into the larger market.
4:19:43 PM
REPRESENTATIVE SEATON commented that, if the gas were connected
into the Alberta hub there would be a very definite impetus to
base the gas price throughout Alaska on the Henry hub or Alberta
pricing.
MR. HEINZE interjected that one of the reasons ANGDA had been so
enthusiastic about a spur line was that it offered a
deliverability; pipeline rates could be varied for free. He also
noted that utilities in Cook Inlet were very economical because
they had bought gas in the ground a long time ago; that could
happen again if Cook Inlet were hooked into gas on the North
Slope.
4:21:49 PM
REPRESENTATIVE SEATON questioned Enstar's commitment to local
service. He said that the North Fork unit about ten miles north
of Homer, had one well and recently Homer Electric Association
(HEA) and Enstar competitively sought RCA approval to service
the Homer area with a couple of conditions: 1) that a second
well be produced and 2) that eight miles of pipe be laid to
Anchor Point. The second well was being spudded in at that time,
but he had heard that Enstar might decide not to service the
local area and would instead go north through a connection to
Kenai-Kachemack pipeline for either LNG export or to the
Fairbanks area. He wanted to know how committed they were to
fulfilling their obligation for distribution in the local areas.
MR. DUBAY said he believed they still had an agreement in place
to service Homer if the gas was developed in that area and if
they got commitments from at least 2,000 customers to use gas as
a heating source. He added that if their contracts were
approved, they had the gas under contract through 2014 and would
not be able to take the Armstrong gas into the Inlet for their
local customer needs until 2014. Their intention would be to get
a commitment from the citizens of Homer to take the gas if it
were developed by Armstrong.
4:24:47 PM
SENATOR FRENCH said he heard that there was no cost estimate for
this pipeline and he found that frustrating. He felt inclined to
associate himself with the remarks that Senator Wielechowski and
Chair Huggins made regarding the resolution of the Senate back
in March to add in-state gas to the call of this session. He
brought that up because they still had no cost estimate for the
project when they were being asked to write individual checks to
Alaskans to help them with the high cost of energy. He felt they
should be working with the administration on this and making
some investments to get it going.
4:26:46 PM
MR. HEINZE interrupted that cost estimates had been put on the
table.
SENATOR FRENCH returned that the question was more specific to
the legal issues that surround [the project]. He acknowledged
that they could not sell royalty gas below market and wondered,
as they considered some other state involvement in
infrastructure in a pipeline, what legal impediments might arise
and what that would mean to citizens who did not participate in
the benefits of the gas pipeline. He also wondered if they would
run into a constitutional prohibition if they tried to bring the
price of gas down too far.
4:27:53 PM
COMMISSIONER GALVIN replied that the constitutionality of the
price of the state's royalty gas would not be impacted by
participation in a pipeline. The pipeline participation would
simply be an infrastructure project on the transportation of
that gas, not on the actual price at the wellhead. He did not
believe there would be any legal impediment to the state
participation in an infrastructure project that benefited only
one portion of the state, and pointed out that they did it all
the time.
With regard to a cost estimate for this project, he said it had
just evolved. There was a cost estimate for the Enstar project
and cost estimates from ANGDA on spur lines, but the idea of
moving gas from Cook Inlet to Fairbanks before the big line,
with state participation in that project, was new. While it was
similar to the bullet line in that it would be a small capacity
line designed primarily to meet in-state demand, it was being
proposed for a different reason. The bullet line was problematic
from the administration's perspective because it had the long-
term impacts associated with potentially discouraging
exploration in Cook Inlet. This project would take the gas
north, meet in-state demand and hopefully spur exploration in
the Cook Inlet, then hook up to the big line, connect to the
main markets and meet both of their goals.
Cost estimates for this particular project were scheduled to be
in place before the legislature in January. He stressed that the
administration wanted to work with the legislature on this
matter to meet the needs of Alaskans.
MR. HEINZE said that during the hearings in Juneau and
Fairbanks, Enstar did present an estimate of about $1 billion
for a pipeline linking Fairbanks and Anchorage, and about $2.3
billion for a line linking the Foothills to Fairbanks. At the
subsequent meeting in Anchorage, he presented tariff estimates
for those based on different assumed flow rates. What they
showed was that there was some rationality for the tariff at
those cost levels for volumes that were based entirely on
utility needs in Alaska. The challenge the government presented
to them on Monday was to find a way to make it work even better
and he had tried to explain how that might be done.
CHAIR HUGGINS commented that Representative Jay Ramras from
Fairbanks voiced the slogan "Gas in 5 years, swinging first to
Fairbanks." He said he would like to see a Cook Inlet
development program that would mature to the extent that they
could get something to Fairbanks within 5 years.
4:34:37 PM
CHAIR HUGGINS continued that he wanted to see what that program
would look like so they [the legislature] could help, because it
had to be a cooperative process. He stressed that they were all
in it together and should not be communicating through news
interviews; the legislators represented the people they were
talking about getting the resources to.
4:35:31 PM
SENATOR STEDMAN said he was puzzled by Enstar's recent decision
to take gas from Cook Inlet and asked Mr. Dubay to explain the
analysis they went through that changed their business model for
the source of the gas.
4:36:49 PM
MR. DUBAY replied that the project they were working on was to
build a line from Anchorage to the Foothills; that was where
they had invested their capital dollars. They had always felt it
would be most logical to build from Anchorage going north to
Fairbanks, because if the opportunity presented itself to gather
gas from Doyon, for instance, they could get gas to Fairbanks
earlier than they might otherwise. While they had not changed
direction, they were committed to sit down with the state and
ANGDA to work on a structure for a partnership and reevaluate
their options to get the best project done for the community.
SENATOR STEDMAN said that during the previous session, Senator
Thomas worked quite a bit on Susitna hydro to broaden the
analysis of how to get energy to Alaska, particularly in the
rail belt. The Senate appropriated funds in the capital budget
for that study, which was still several months from completion.
Then he saw a press release about a business arrangement with
Enstar that came out of the blue eight days into the fiscal
year, and he was concerned about the lack of openness in the
arrangement between the administration and Enstar. He asked
Commissioner Galvin to help him understand what was going on.
4:41:22 PM
COMMISSIONER GALVIN responded that the venture being undertaken
was to put together both a business plan and a proposal to the
legislature with regard to this project. When the proposal came
to them, it would go through the same public process Senator
Stedman described relative to the money that was allocated to
study the Susitna project. In that context, it would have to
justify itself under a number of potential benefits to the state
including opening the Cook Inlet Basin for more exploration, and
getting gas to Alaskans as quickly as possible.
4:44:10 PM
SENATOR STEDMAN was concerned about the state's involvement in a
capital project that seemed to be driven by the marketplace
without state or federal aid.
4:46:17 PM
COMMISSIONER GALVIN assured them that if the state was going to
consider playing a financial role in this project, there would
be a large number of hearings as the process moved forward and
Mr. Dubay would have the opportunity to sit in the same chair
that Mr. Palmer had in terms of answering questions. Other
entities would also have the opportunity to express their
interest in whether or not the state should be involved in the
project.
SENATOR STEDMAN reiterated that he was concerned the state was
interjecting itself too early into this process.
4:49:10 PM
MR. HEINZE emphasized that the state's possible role in
supporting this case was still undefined. He offered the
Gravelly Lake hydro project as an example of how the state might
be involved. The citizens who depended on Gravelly Lake for
their power enjoyed a lower rate because the state stood behind
the project; it did not spend a nickel on the project but it did
stand behind the debt.
4:50:00 PM
REPRESENTATIVE JOULE questioned whether Cook Inlet gas could be
used for those communities up and down the Yukon River.
MR. HEINZE replied that there was no propane in the Cook Inlet
gas, so the option was eliminated technically. He suggested that
as an intermediate step, propane from North Slope gas could be
trucked to the Yukon River giving the rural communities the
opportunity to participate. Ultimately, they would hope that a
large amount of propane could find its way to Tidewater to
service the coastal communities such as Juneau as well.
4:51:33 PM
COMMISSIONER GALVIN added that when they began discussions about
this line, it was basically about a substitution for the idea of
a bullet line from the foothills south. That line was not
intended to carry liquids, and the fuel source was not intended
to provide the opportunity to strip off liquids at the river.
This project would not change the time frame or dynamic of the
opportunities presented by the larger line coming off the North
Slope. He felt it was important for all Alaskans to understand
as they moved forward with these hearings, that although the
hearings might focus on one aspect of the project, they were not
excluding other opportunities. There had been a number of
studies done and it was the objective of the administration and
ANGDA to explore how to maximize the opportunity to make gas and
other similar products available to as many Alaskans as
possible.
4:53:27 PM
SENATOR GREEN commented that she believed anything the state
might do at that time to fit into this project would only serve
to slow it down.
CHAIR HUGGINS shared some of Senator Green's concerns and
reminded Commissioner Galvin that they wanted that chronological
timeline objective for reaching a contract to move them forward.
4:54:37 PM
CHAIR HUGGINS reminded members they would meet again from 6:00
to 8:00 PM for Mr. Porter's presentation on Pt. Thomson, and
that they would begin at 8:00 AM the following morning with the
Denali project; TransCanada workforce issues; TransCanada Exxon
Mobile presentation. The CBI Mediation Group would be presenting
from 6:00 to 8:00 PM.
He adjourned the meeting at 4:55:02 PM.
Note: Due to technical issues, this section of audio was
recompiled from other sources. Recording volume of this segment
is significantly lower than the rest of the meeting.
CHAIR HUGGINS called the meeting back to order at 6:08:13 PM and
introduced Steve. Porter, who would be presenting "The Point
Thomson Dilemma."
6:09:22 PM
STEVE PORTER, Consultant for the Legislative Budget and Audit
Committee, said he wanted to begin by providing context: why
they were where they were; why they might get a gasline; and why
Point Thomson was probably economic. It was all related to gas
price and commercial decisions, not to stranded gas, AGIA or
anything else they might have done.
6:10:30 PM
Slide 2: Plains All American L.P.'s WTI Crude - Posted Price
MR. PORTER said there was a time in about 1999 when the industry
thought they were in a $15 per barrel world in perpetuity. About
that time ARCO liquidated, Pt Thomson did not look economic, and
a gas pipeline was marginal.
Slide 3: U.S. Wellhead Natural Gas Price - In the early years
from 2002-2004 there was the Stranded Gas Act. They were in a
$2.00 world into the late 1990's and 2000. From 2001-2003 prices
were volatile and it was hard to determine where prices would
go. Even when they were negotiating stranded gas, they were
talking about cases of $3.50 to $6.00.
6:11:58 PM
MR. PORTER added that the economists of the world are usually 6
to 12 months behind price in their analysis; but in about 2005
to 2006 they recognized that they were entering a different
world. Assumptions on oil and gas were substantially higher. At
this point they believed that both Point Thomson and the gas
pipeline had become economic due to prices.
6:12:56 PM
Slide 4: Pt. Thomson Unit Status prior to Director's Decision -
Just prior to the director's decision they had 21 [22] plans for
development. The State wanted the producers to drill the wells
necessary to determine whether gas cycling or a blowdown
strategy was appropriate. The producers were unwilling to spend
the money because they wouldn't see a return on it any time
soon, so there was tension between the Department of Natural
Resources (DNR) and the producers prior to the 23rd plan of
development, which resulted in that plan being disapproved.
6:14:13 PM
DNR recognized that they had to either disapprove it or stagnate
indefinitely, and he felt they had made the appropriate
decision.
Slide 5: Director's Decision - Failure to submit an acceptable
plan of development was grounds for termination and that was the
director's decision. The individual lessees with certified wells
were required to commence production by October 2009.
6:15:06 PM
MR. PORTER continued to Slide 6: Commissioner's Decision - As
with any director's decision, they had the opportunity to
escalate it to the commissioner, and the commissioner's decision
changed a few things. The decision did reject the plan of
development because it did not commit to put the unit into
production, but it terminated the Point Thomson Unit as opposed
to saying they had grounds for termination. That was a shift
from the director's decision that the courts would come back to.
It also revoked the certification of Point Thomson wells, where
the director's decision required them to go into production.
Both of these changes showed up later in the December 25th court
decision.
6:16:01 PM
Slide 7: May 1 Decision - The producers went to court to stall
the process. The court said it would let the process move
forward but warned DNR that they had probably failed to follow
their own statutes when they decertified the wells. Mr. Porter
quoted a section from that decision:
"the undisputed fact remains that the Department
certified these wells pursuant to 11 AAC 83.361, and
that as a result of these certifications, the wells
'will be considered capable of producing hydrocarbons
in paying quantities' for purposes of 11 AAC 83.374"
6:16:51 PM
REPRESENTATIVE SAMUELS asked Mr. Porter to clarify whether this
was Judge Gleason's and not Tom Irwin's decision.
MR. PORTER answered yes; it was the court's May 1st decision by
the same judge who made the final decision.
REPRESENTATIVE SAMUELS asked how many wells this decision
affected.
MR. PORTER replied that he thought there were 7 certified wells.
6:18:01 PM
SENATOR BUNDE commented that, although they usually thought of
Point Thomson as kind of a monolith, it was actually 46 separate
tracts. He noticed there were test wells drilled in about 15 of
those, so the producers explored a third of what they had under
lease. He wondered how that compared to other leases.
MR. PORTER said the issue was not so much the amount of property
drilled, it was whether they had found out enough about the
reservoir to decide whether to do gas cycling or gas blowdown.
In fact, the records of that court case show that if the
producers had agreed to drill even the single well that DNR
wanted them to, they would have delayed a lot of the other lease
obligations, because DNR recognized that they needed to see what
was going on down below in order to make a decision on how to
move the project forward.
6:19:53 PM
Slide 8: Dec 26 Court Decision - Mr. Porter felt that this was a
very good decision.
6:20:19 PM
He said there were four main issues:
1) Did DNR have the authority to accept or reject the plan of
development? The answer was yes, the law gave DNR very
broad authority to accept or reject the plan of
development. That gave DNR a lot of clout to force a unit
operator to move forward with a project however, if they
rejected a plan of development, the unit was at risk of
being terminated.
2) They found that DNR had the authority to terminate the
unit, but not without a hearing to determine the
appropriate remedy for rejection of the plan of
development.
6:21:36 PM
REPRESENTATIVE HAWKER asked if the May 1st decision was in 2008
th
and the December 26 decision was in 2007.
MR. PORTER replied they were May 1, 2007 and December 26, 2007.
REPRESENTATIVE HAWKER wanted to confirm that DNR had the
authority to terminate, but not without a hearing. He said that
seemed significant. The way he read it, it seemed to say they
could terminate but had to provide some remedies.
MR. PORTER clarified that, to terminate the unit they had to
provide some notice. DNR went back and held hearings and the
commissioner issued another decision. But the court indicated
that there were some standards associated with that review.
3) Termination of unit is only one possible remedy, and a key
phrase was: "consider the import of Section 21 of the Point
Thomson Unit Agreement, as amended in 1985, in determining the
appropriate remedy." That said, there was a higher standard for
unit termination than there was for plan of development
termination.
4) Certified wells: Mr. Porter said he would come back to this
point in a moment.
6:24:14 PM
MR. Porter turned to Slide 9: Point Thomson Unit Agreement -
This addressed Section 21, which specified that authority "shall
not be exercised in a manner that would (i) require any increase
in the rate of prospecting, development, or production in excess
of that required under good faith and diligent oil and gas
engineering practices; ...or (iii) prevent this agreement from
serving its purpose of adequately protecting all parties in
interest hereunder, subject to the application conservation laws
and regulations."
He explained that there was a standard rather like the
reasonably prudent operator standard. If you were going to take
an $80 billion asset away from somebody, you would have to prove
they weren't being a reasonable and prudent operator at the
time. In this case, the court said Exxon lost on the plan of
development; on the unit termination, they said a reasonably
prudent operator would probably have moved this to production
and if they didn't, they would probably lose that too. But they
created a balance. They told the state that if they couldn't
figure out a way to agree with Exxon, they would leave them with
the certified wells. That meant that Exxon would get to keep
those seven leases, which would split the unit between them and
probably result in years of litigation and negotiations.
6:26:29 PM
REPRESENTATIVE SAMUELS asked Mr. Porter if the term "unit
termination" was really a lease revocation, and if the leases
without certified wells would revert to the state.
MR. PORTER replied that unit termination would end up with all
of the uncertified leases going back to state. As far as
certified wells, the court referred the state to their May 1st
comments.
6:27:45 PM
SENATOR STEVENS asked if there were remedies other than
termination or negotiation.
MR. PORTER said the court did not delineate the remedies. Under
the contract, anything that would have moved this forward and
been acceptable to both parties was an option.
6:29:32 PM
REPRESENTATIVE DOOGAN asked if it was when the commissioner made
his decision that the court ruled DNR had failed to follow its
own statutes and regulations when it decertified the wells.
MR. PORTER confirmed that it was at the commissioner's level.
REPRESENTATIVE DOOGAN asked if the court's decision was
absolute, or could the department have gone back and fixed the
defects that the court recognized in its process.
MR. PORTER responded that the commissioner said it was bad
policy to certify wells that had been plugged and abandoned. The
court said whether or not he thought it was bad policy, they
were certified and the commissioner did not have the authority
to overrule his own regulations and statutes. DNR could go back
and fix that problem but they would have to follow a regulatory
process.
He explained that as a rule, a certified well that was good
policy would have pressure to the surface. A certified well that
was bad policy would have a plug below the surface. In Alaska,
unlike the lower 48 however, it might make good safety sense to
plug a certified well if you didn't plan to bring it on line for
8 or 10 years because, due to bad weather and remote locations,
it could be hard to get back on site if there were a problem.
6:32:58 PM
REPRESENTATIVE DOOGAN queried, if it was not possible for the
state to take back leases that had wells on them which could be
producing gas but were not, how was it possible for the state to
enforce that part of the lease that required the lessee to
produce.
MR. PORTER said that was a good question and one he kept coming
back to, because the question was whether they could ever get
the leases back. He said that it was even worse than that
because there was a part of the law that said if you drilled an
exploratory well or two, from a conservation standpoint you
would have to make sure to include all the leases of the
reservoir and develop a unit plan before you started producing
the leases. So from a logical standpoint, for DNR to tell the
lease holders to produce that individual well wouldn't work,
because every time somebody found an exploratory well they'd
have to start producing immediately.
Mr. Porter admitted that he didn't know the answer, but he
understood that if the Point Thomson Unit did get terminated and
they broke it up, they would have to put the unit back together
with those seven certified leases and submit another plan of
development.
REPRESENTATIVE DOOGAN said that from his standpoint, if the
state had laws and regulations that allowed people to find
producible oil and gas and then just camp on it, they needed to
change those laws.
MR. PORTER agreed.
REPRESENTATIVE GATTO recalled the statement from Howard
Johnson's presentation that "every single lease was in default
except for one." He asked if that would mean the unit was
entirely in default.
MR. PORTER replied that he did not say only one lease was in
default; there was only one lease that was in its primary term
so they could still pay rentals on that particular lease, and if
the unit went away it would not be affected. Every other lease
would need a reason to be held out of production. That was why
the certified wells were so important. In his opinion, that was
also why DNR originally decertified the wells; they feared this
exact circumstance would happen. If the wells were certified,
the leases would be held by the certified wells.
6:37:32 PM
REPRESENTATIVE GARA said he believed Mr. Porter had studied the
issue and must have some recommendations to make to them. He was
not particularly interested in the lower court ruling because
the matter would be appealed to the Supreme Court anyway. He
expected them to say that since our partners had already
violated 24 plans of development, we did not have to work with
them any more.
He asked Mr. Porter what he was expected to take from this
discussion. If it was that they should mediate, he knew they
wouldn't get anywhere with that unless both parties had a desire
to do it.
6:39:08 PM
CHAIR HUGGINS pointed out that some of them needed to understand
the process of litigation.
MR. PORTER countered that the producers did not violate 24 plans
of development. In the early years DNR did not put penalties in
their plans of development. When they expanded the unit and DNR
wanted to be sure the producers met the provisions of the
expansion, they started to do that, but the early ones had
little meat to force compliance.
6:41:36 PM
REPRESENTATIVE GARA conceded that they might not have violated
all 22 of the previous plans, but many of those were breached
and every single time the state gave them another chance. As a
result, Point Thomson might not be available as a gas field for
the gas pipeline. He asked why the state would not say it had
given them 22 chances and they still had not produced, so it
wanted a new partner.
MR. PORTER totally agreed with Representative Gara regarding
mediation; as a sovereign state, Alaska should tell Exxon the
rules. In this case, DNR had the right and the responsibility to
tell Exxon what it would and would not accept.
With regard to the delay, he opined that the reason the
producers were finally moving the project was that if they
started now it would take 6 years to go to development; they
would have to cycle the gas for at least 5 years, so they would
be ready to push gas into the pipeline in about 11 years. The
pipeline was scheduled to be done in 11 years, so they would be
ready to put gas in the line either at the beginning of the line
or within a few years. If this were to go to litigation, it
would take another 10 years.
REPRESENTATIVE GARA said that in his experience, after a
superior court ruling, the Alaska Supreme Court decides within
about a year and a half. He asked Mr. Porter what the basis was
for his statement that it would take 10 years.
6:44:55 PM
Slide 12: Probable Outcome
MR. PORTER explained that this case alone might take only a year
and a half or 2 years; then they would have to litigate the
certified well issue if the state wanted all of the leases,
which would take another 3 years to go through superior court
and Supreme Court. Once DNR had the leases back they would have
to go through a "best interest" finding, which would take at
least a year, and then they would get sued on best interest
finding. It would take another six months to a year before the
courts would allow them to hold a lease sale. If DNR were lucky
and the lease sale concluded within six months, they would then
have a new lessee(s) who would have to review and analyze the
data, form the units, and create a new unit development plan
that would probably end up looking a lot like the existing one.
After all of that was done, they would be back where they
started, ready to start developing the unit.
6:47:16 PM
SENATOR WIELECHOWSKI took issue with the statement that "they
finally figured it out" about gas cycling. He said they figured
th
that out in 1986! In their 16 POD, they said they needed to
cycle the gas and promised to drill 7 to 10 wells but did not
drill a single one. In previous POD's they said they could not
develop Point Thomson until a gas line was built; but the
opposite turned out to be true. He said he fully supported
Governor Murkowski's and Commissioner Irwin's action to finally
take the leases from them.
MR. PORTER also supported what DNR did in terms of pushing the
producers to move the unit forward, and admitted that Senator
Wielechowski was absolutely correct about the unit plans of
development; they did propose cycling twice but then backed off
of it. He expressed his opinion that they got excited about what
they thought they could get out of stranded gas and thought they
could do gas blowdown. They thought they could get it approved
by the legislature, circumvent the rest of the process and not
comply with the POD's, and move Point Thomson straight to gas
blowdown.
6:49:27 PM
SENATOR THERRIAULT disagreed with Mr. Porter's statement that
new lessees at Point Thomson wouldn't have the data. He pointed
out that some of the same companies that were on the current
list of lessees could come back in and would have access to the
data.
6:52:20 PM
MR. PORTER conceded that was a possibility. He said he had made
an assumption that the state got rid of Exxon and the existing
owners, but if Exxon got in with the new owners somehow, they
would probably cut a deal to share the data.
SENATOR THERRIAULT referred to Mr. Porter's statements that "the
state can tell them what's acceptable" and "the state can tell
them what to do" and pointed out that the state brought the
producers in because they had expertise in developing oil and
gas that the state, the sovereign, did not have. He questioned
whether the state had the right to tell them how to develop the
leases.
MR. PORTER said that 11 AC 83.343(b) gave them that right.
(Slide 14 - State's Obligation Under Point Thomson Contract)
SENATOR THERRIAULT asked if the burden of proof would shift to
the state in that case.
MR. PORTER said no, not at that point. What 11 AAC 83.343(b)
said was that if you rejected a plan of development, you had the
right to propose an alternative that would be acceptable to you.
(Slide 15: DNR's responsibility under regs.)
SENATOR THERRIAULT asked what would happen if they disagreed.
MR. PORTER answered that if they disagreed, the state had the
right to reject the plan of development and then follow the
process for lease termination.
SENATOR THERRIAULT questioned what would happen if the producers
maintained that the alternative offered by the state was not
what a reasonable, prudent operator would do. He asked if the
state would have to prove to the court that what it had proposed
was fair, reasonable and prudent.
MR. PORTER did not agree with Senator Therriault that the burden
of proof would shift just because the state met its statutory
responsibility. He thought the court would defer to the state's
sovereign rights.
SENATOR THERRIAULT insisted that the court should give some
credence to the producers' claims in the matter.
MR. PORTER said he understood the argument and that argument had
actually been made, but it was not what the court did. The court
told Exxon that the state had the authority to do what it
pleased as long as it was not arbitrary.
SENATOR THERRIAULT felt strongly that turning down their POD and
telling them how to proceed were two different things.
MR. PORTER clarified that the reasonable and prudent operator
standard would not apply at the plan of development phase, but
at the unit termination phase.
6:56:08 PM
SENATOR STEDMAN asked if it would be correct to assume that if
Exxon's leases were terminated and the leases were re-
advertised, Exxon could submit a new bid to buy those leases.
MR. PORTER answered yes.
SENATOR STEDMAN asked how much information the existing Point
Thomson lease holders, primarily Exxon, might have that would
create an advantage in re-acquiring those leases.
MR. PORTER referred the question to DNR because he was not sure
what information was considered confidential and how much, if
any of it, would become public if the owners lost the leases.
CHAIR HUGGINS called a brief at east at 6:57:50 PM.
CHAIR HUGGINS called the meeting back to order at 7:12:09 PM.
He recognized Representative Doll and thanked her for her
suggestion that a map be displayed in the front of the room.
7:13:22 PM
MR. PORTER said in the interest of time he would skip to
discussion of his recommendations for the future and what the
benefits would be of moving Point Thomson forward timely.
If Point Thomson gas was not available for first gas, the
project would go from a 4.5 bcf/d pipe to about a 3.5 bcf/d
pipe, which would still be at the economic limit of what
TransCanada proposed. He stressed that whatever that number
would be, the tariff differential was what they needed to look
at. He estimated that to be roughly $.50 to $1.00.
He stressed that if they fought Point Thomson out, everyone
would lose. No matter when they expected to get Point Thomson
gas into the pipe, they would still have a 10 year delay if it
was litigated.
He believed that DNR was interested in upholding the interests
of the state and hopeful that the parties would find a solution
to move the project forward so the court never had to make a
decision on this case. In his opinion, DNR thought they couldn't
talk to Exxon before they had submitted their proposal to the
courts. Now that had been done, he thought they would be able to
sit down with Exxon and work things out. Basically, he hoped it
was just a timing issue and they would be able to get the
project moving within six months.
7:18:22 PM
SENATOR BUNDE said as he understood it Exxon was a majority
holder at Point Thomson, but there were minority holders as
well. He asked Mr. Porter to talk about how they played into the
situation and whether they could negotiate on their own.
MR. PORTER understood that under the old plan, Exxon had veto
power over moving the project forward, but he believed they had
recently changed the operating agreement so that if all of the
owners got together, they could roll Exxon. He said that the
other owners included BP, Chevron, Conoco Phillips, and probably
20 smaller owners.
7:20:30 PM
REPRESENTATIVE LYNN felt he was stating the obvious when he said
that it wouldn't make any difference who they went with,
everybody would make less money if Point Thomson did not come
in.
MR. PORTER confirmed his statement. The sooner they could bring
Point Thomson in, the better it would be for any project that
moved forward.
7:21:57 PM
REPRESENTATIVE DOOGAN said, if by some miracle the department
were to allow this plan of development to go forward, he
understood that the producers would have to delineate the field
better and then, according to the Alaska Oil and Gas
Conservation Commission (AOGCC), they would have to either
produce the gas liquids and the oil rim or demonstrate that they
could not, before they could start taking off gas and reducing
pressure in the field. He asked Mr. Porter what the timing would
be to take the oil off first and get to gas.
MR. PORTER responded that getting to the gas would be based on
drilling a few more wells. Hypothetically, if Point Thomson
owners started producing the unit 6 years from now, that would
be phase one and they would have a lot more information. Even
before production, AOGCC would begin evaluating what they had
found, but once they were in production AOGCC would have a lot
more information about how much oil they could use, whether or
not they could even produce out of the oil rim, how gas cycling
worked, and how much of the condensates would be producible. At
that point they could begin to develop a time line, but that
would not start until the project started. So if they started
immediately, Point Thomson [gas] could show up as early as first
gas or a few years after.
REPRESENTATIVE DOOGAN reiterated that even under best case
scenario they would barely make first gas, and it wasn't likely.
MR. PORTER agreed that it was possible but not likely.
7:26:17 PM
CHAIR HUGGINS commented that the fundamental question was
whether it would be available for open season.
MR. PORTER said if the project moved forward, the owners of that
gas might show up at open season and commit the gas; but a gas
commitment is for 25 years, so even if they got in 2 or 3 years
late they would have to make that commitment or they would have
to commit at the expansion level.
7:27:10 PM
REPRESENTATIVE ROSES paraphrased Mr. Porter's testimony that if
they didn't bring Point Thomson on line it would drive the
tariffs up and the state would make less money. Then he referred
to Exxon's testimony about Point Thomson. They said it had cost
them about $500 million to obtain the information they had over
the years and to reach the point that they could put this plan
of development in place. If they were to lose the leases, since
much of that information was proprietary, whoever bought them
would have to spend a considerable amount of money to get to
that point.
MR. PORTER deferred discussion of that to DNR.
REPRESENTATIVE ROSES felt it would be fair to assume there would
be some cost to a new owner to acquire additional information.
MR. PORTER said they would have to acquire information from the
existing owners and then spend some time getting up to speed.
REPRESENTATIVE ROSES continued that whoever got those leases and
had to drill for information would be entitled to the credits
the state gives for exploratory operations. So if Point Thomson
wasn't on line and they had to go to those as yet undiscovered
reserves, the state would have to pay incentives to the
explorers for their drilling operations. That would mean even
more loss of revenue to the state in terms of Point Thomson gas
not being committed by the current lease holders.
MR. PORTER allowed that Representative Roses was correct in
terms of explorers; if someone spent money exploring a lease,
the state was going to pay for it and he thought that was what
they would want to have happen.
REPRESENTATIVE ROSES agreed, but maintained that when they
talked about the expense of not having Point Thomson gas
available, it included not only loss of tariff, but the money
the state would have to pay for exploration incentives to get
back to the level they would be at if Point Thomson were not
"taken off the map."
MR. PORTER thought they would end up with some incremental costs
on whoever came in with Point Thomson. In terms of other
explorers, they would explore whether Point Thomson showed up or
not. So while there would probably be an incremental cost
associated with Point Thomson he didn't know what it would be.
7:30:57 PM
SENATOR BUNDE said, because the stakeholders at Point Thomson
were in litigation they obviously could not book the reserves;
but they were also aiming at a moving target with regard to when
a pipeline would be available. He asked at what point they could
book the reserves if the producers and the administration made
piece, and if Mr. Porter could venture a guess as to what the
value to the producers would be when they booked those reserves.
MR. PORTER replied that he didn't have a clue; he was sorry but
it was not his field.
7:31:55 PM
SENATOR THERRIAULT conjectured that AOGCC would not be able to
give its blessing on an off-take rate for the first open season.
He asked if it was possible to bid for capacity on a reserve
that AOGCC had not "blessed."
MR. PORTER responded that he thought TransCanada only required
40 percent of the bid be identified reserves, so it would be
possible for the three majors to overbid Prudhoe.
SENATOR THERRIAULT felt a growing concern that Point Thomson
would not be able to participate in the first open season,
because he didn't see how AOGCC could come to an off-take
decision that quickly. If it were bid without AOGCC blessing, it
seemed that would be taken into consideration by the financiers.
MR. PORTER replied that AOGCC would not be a factor at open
season, but it would be in terms of what a risk-taker would be
willing to risk. If Point Thomson owners believed they were at
least 10 years out and might not have the Point Thomson leases,
they might not factor that into their bid. If they believed they
had some chance of bringing that Point Thomson gas into the
pipeline soon after first gas, they would show up and bid the
gas, even if AOGCC had not approved it. If they could look
forward and feel confident that they would approve it, they
would risk that in their bid. With regard to the financiers, if
Exxon, Conoco Phillips and BP came forward and bid 4.5 b without
Point Thomson, and committed to 4.5 b over the next 25 years
with TransCanada, TransCanada would have a pipeline and could
finance it.
SENATOR THERRIAULT touched again on the question of whether any
new lessee would be starting from scratch with regard to down-
hole technical information and said that was not true.
MR. PORTER interrupted that it would depend on who the lessees
were.
SENATOR THERRIAULT continued that it could be an existing lessee
who already had access to all of that information.
7:35:59 PM
SENATOR WIELECHOWSKI went back to Senator Doogan's timeline
regarding when the gas would be available. He noted that the
unit owners intended to pull 10,000 of the 5 or 6 million
barrels per day of condensate which, according to DNR's
calculations, would take over 40 years at that rate. Based on
not getting started for 6 years, they would be looking at first
gas rolling out of Point Thomson under Exxon's current plan in
2054. So yes, they were promising to develop just like they had
for the last 43 years.
SENATOR WIELECHOWSKI said that according to DNR's testimony in
Anchorage, the physics of the gas cycling as proposed by Exxon
didn't work. He wondered if Mr. Porter had an opinion on DNR's
testimony.
MR. PORTER maintained it was completely irrational for Exxon to
build a $1.2 billion facility and then cycle it for 40 years
producing only 10,000 barrels a day. He stressed this was a
phase 1 process; either it would work and they would expand it,
or it wouldn't and they would go to gas blowdown. What would not
happen would be 10,000 barrels a day for 40 years.
SENATOR WIELECHOWSKI said if this is the largest undeveloped
field in North America, and if the Superior Court affirmed
Alaska in taking the leases back, shouldn't they have producers
lining up to take those leases?
MR. PORTER agreed it's worth a whole lot. That's why the
producers finally decided to move forward.
7:39:54 PM
REPRESENTATIVE HAWKER followed up on the Point Thomson testimony
in Anchorage. A great deal of it seemed to be speculation by
dueling consultants over the proper way to develop that reserve,
whether they should do gas cycling or go straight to blowdown,
and how they should deal with the oil rim. The oil rim seemed to
be a very critical factor and he couldn't understand how the
experts could have such widely differing opinions on how to deal
with it. As he understood it, there were two exploratory wells
that had gotten close to the oil rim and could provide tangible
information. One of those wells was solidly into the oil rim;
the other well got into the mixing zone where the oil met the
gas liquids. That test well that was solidly into the oil rim
came up at 18 API.
MR. PORTER interrupted that it was actually 11 API and the well
in the mixing zone was 18 API.
REPRESENTATIVE HAWKER confirmed that the well in the rim was 11
API, very viscous, and the one in the mixing zone was 18. He
asked Mr. Porter to explain those numbers to him.
MR. PORTER said that those were the only two pieces of
information available on that oil.
REPRESENTATIVE HAWKER asked if he was correct that the
administrative consultant's report, on which DNR based its own
proper plan of development, used 20.
MR. PORTER answered yes, that a debate was going on between the
consultant and AOGCC as to whether 11 API was truly a good
number. If it was a good number and the 18 API was a mixed
number, then 20 was probably not appropriate and they should
have used 11. He said the right number was somewhere in that
range, but they wouldn't know for sure until they punched some
more holes. He added that they had used the term "discontinuous
oil rim," meaning it would be difficult to estimate how much oil
would come out of that particular section of the reservoir.
7:44:52 PM
REPRESENTATIVE HAWKER asked if Mr. Porter could distill that
into layman's terms and tell him what it meant.
MR. PORTER explained that if that was the only decision you had
to make, you would punch some holes to see if you could produce
that oil rim. If it was really that heavy, if it was 11 API
gravity even under high pressure, then the estimate of value to
Point Thomson, the amount of oil you would need to produce, and
how many years you would need to produce it would go down
substantially.
REPRESENTATIVE HAWKER said this was one of his favorite topics
in these debates; the false precision of putting a chart on the
wall and asking them to believe that what was up there was the
truth.
CHAIR HUGGINS asked Mr. Porter what he meant by "punching a
hole" and how much that would actually cost.
MR. PORTER said the problem with these wells was that there were
very high pressure zones down below that required special
drilling equipment and techniques that would greatly increase
the cost. He had heard figures from $80 million to $100 million
per well but could not really say how much it would cost.
7:47:04 PM
REPRESENTATIVE SAMUELS said the way he understood it was that
the small scale cycling project was a good idea, but they
didn't' believe Exxon would do it. He asked if that was too
broad a simplification of the situation.
MR. PORTER agreed that was fairly accurate. The problem was
believing Exxon would move forward. He reiterated that, from a
contract standpoint, if you don't believe someone, you set the
contract penalty structure accordingly. DNR tried imposing
penalties for not drilling, but Exxon just paid them and didn't
drill. DNR's stance was that they didn't need money, they needed
a well. Exxon finally said they were ready to drill a well, but
DNR didn't trust them. It created a catch 22 because the state
was basically saying to the court that they wanted out of the
contract because they didn't trust Exxon and, under the law, the
courts could not allow that to stand or it would mean a
sovereign could unilaterally jump out of any contract.
He summarized that DNR would eventually have to come to the
table with the producers and solve the penalty problem. He
believed and hoped that both parties wanted to come to some
agreement; if they failed to so, the court could very easily
hold against them on the unit termination issue.
7:51:32 PM
REPRESENTATIVE GARA said they had been focusing on how Exxon was
supposed to develop Point Thomson, but the bigger argument was
that they didn't have all the information necessary to decide
how it should be developed because Exxon had not done the
exploration they needed to do to provide that information. He
asked if that wasn't a strong part of our case. Exxon had a duty
to explore, so the problem was not so much that they didn't move
forward but that, they didn't perform the exploration they were
required to under the leases.
MR. PORTER said that was true, but in the 23rd plan of
development, they proposed to do that. He stressed that under
contract law, the court wouldn't look back at what they didn't
do in plans 1-21, only at what they were currently doing, and
they actually did what they were supposed to do in the 23rd
plan.
REPRESENTATIVE GARA objected that the 23rd plan came out after
the state had said "we're not giving you any more chances." Up
to the 22nd plan they hadn't explored like they were supposed
to, so the state said "tough we're not playing this game any
more." After the state sued because they hadn't followed through
on their obligations, Exxon made another offer. He felt the
latest plan wasn't binding because it was offered after the
state filed suit.
MR. PORTER corrected that the suit was kicked back into the
administrative process, and the court didn't care what had
happened in plans 1 through 22. They cared about what was in the
23rd plan of development, which was a proposal to the court as a
solution to unit termination.
7:55:18 PM
CHAIR HUGGINS interrupted and advised those who wanted to
continue the conversation that Mr. Porter would be available
afterward. He asked Mr. Porter to wrap up.
7:55:33 PM
MR. PORTER said the key on this was in the owners' hands. He
hoped they would be able to solve the problem with Exxon because
if they fought it like a battle, the state would lose. If DNR
approached the Point Thomson Unit owners as a problem to be
solved, the state could win. He did not think the parties were
that far apart and was confident this was soluble.
7:56:49 PM
CHAIR HUGGINS thanked Mr. Porter for his insights and announced
that they would begin again with a new presenter at 8:00AM
sharp.
CHAIR HUGGINS adjourned the meeting at 7:57:18 PM.
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