Legislature(2001 - 2002)
07/17/2001 09:11 AM Senate NGP
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* first hearing in first committee of referral
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+ teleconferenced
= bill was previously heard/scheduled
ALASKA LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
Anchorage, Alaska
July 17, 2001
9:11 a.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Rick Halford
Senator Pete Kelly
Senator Donald Olson, alternate
SENATE MEMBERS ABSENT
Senator Johnny Ellis
HOUSE MEMBERS PRESENT
Representative Joe Green, Vice-Chair
Representative Brian Porter
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate, alternate
HOUSE MEMBERS ABSENT
Representative Mike Chenault, alternate
Representative Reggie Joule, alternate
OTHER MEMBERS PRESENT
Representative John Davies
Representative Drew Scalzi
Representative Ken Lancaster
COMMITTEE CALENDAR
FEDERAL ISSUES
PIPELINE ACCESS ISSUES
REPORT ON MARKET CONDITIONS
UPDATE ON SB 158 & ECONOMIC MODELS
ROYALTY IN-KIND ISSUES & PIPELINE STUDIES
RIGHT-OF-WAY PIPELINE APPLICATIONS
ALASKA HIGHWAY NATURAL GAS POLICY COUNCIL
PREVIOUS COMMITTEE ACTION
None
WITNESS REGISTER
Mr. Mike Henry
Resources Aide to Congressman Young
United States House of Representatives
2111 Rayburn Bldg.
Washington D.C. 20515-0201
Mr. Mike Menge
Aide to Senator Murkowski
United States Senate
322 Hart Bldg.
Washington D.C. 20510-0202
Mr. Justin Stiefel
Aide to Senator Stevens
United States Senate
522 Hart Bldg.
Washington D.C. 20510-0201
Mr. Randy Methura
Office of Energy Projects and Pipeline Certificates
Federal Energy Regulatory Commission (FERC)
888 First St. NE Rm. 11A
Washington D.C. 20426
Mr. Robert Cupina
Director of Energy Projects
Federal Energy Regulatory Commission
888 First St. NE Rm. 11A
Washington D.C. 20426
Mr. Robert Petrocelli
Office of Energy Markets, Tariffs and Rates (OMPR)
Federal Energy Regulatory Commission
888 First St. NE Rm. 11A
Washington D.C. 20426
Mr. John Katz
Director of State/Federal Relations and
Special Counsel
Office of the Governor
444 N. Capitol NW, Suite 336
Washington DC 20001-1512
Mr. Anthony Scott, Staff
Regulatory Commission of Alaska (RCA)
Department of Community and Economic Development
1016 W 6th Ave.
Anchorage AK 99501
Mr. Will Abbott, Commissioner
Regulatory Commission of Alaska
Department of Community and Economic Development
1016 W 6th Ave.
Anchorage AK 99501
Mr. Ed Small
Cambridge Energy Research Associates, Inc. (CERA)
Charles Square, 20 University Road
Cambridge MA 02138
Commissioner Wilson Condon
Department of Revenue
PO Box 110400
Juneau AK 99811-0400
Mr. Roger Marks, Economist
Department of Revenue
PO Box 110400
Juneau AK 99811-0400
Commissioner Pat Pourchot
Department of Natural Resources
400 Willoughby Ave.
Juneau AK 99801-1724
Mr. John Goll, Regional Director
Mineral Management Service (MMS)
U.S. Department of Interior
949 E. 36th Ave.
Anchorage AK 99508
Mr. Jerry Brossia
Bureau of Land Management
U.S. Department of Interior
Address not provided
Mr. Bill Britt, Pipeline Coordinator
Department of Natural Resources
411 W 4th Ave., 2nd Floor
Anchorage AK 99501
Mr. Frank Brown, Co-Chairman
Alaska Highway Natural Gas Policy Council (AHNGPC)
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Mr. Mike Navarre, Chairman
Subcommittee on Alaska Hire/Buy/Build
Alaska Highway Natural Gas Policy Council
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Mr. Bill Corbus, Chairman
Subcommittee on State Pipeline Ownership and Tax Structure
Alaska Highway Natural Gas Policy Council
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Mr. Jack Roderick, Member
Subcommittee on Access for In-State Gas Use and
Future Opportunities
Alaska Highway Natural Gas Policy Council
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Ms. Ronda Boyles, Member
Subcommittee on Access for In-State Gas Use and
Future Opportunities
Alaska Highway Natural Gas Policy Council
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Mr. Ken Thompson, Chairman
Subcommittee on Access for In-State Gas Use and
Future Opportunities
Alaska Highway Natural Gas Policy Council
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
Mr. Harold Heinze
Special Assistant to the Legislative Majority
Alaska State Capitol
Juneau AK 99811
Mr. Scott Heyworth
Citizens for the All-Alaskan Gasline Initiative
P.O. Box 100531
Anchorage AK 99510
ACTION NARRATIVE
TAPE 01-1, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural Gas
Pipelines meeting to order at 9:11 a.m. and announced that the
committee would first take testimony from Washington, D.C. He
stated that President Bush, Senator Murkowski, Chairman of the
Resources Committee in Energy, Senator Bingaman, and Representative
Young have introduced separate bills in Congress that deal with
energy packages.
Federal Issues - Congressional Staff
MR. MIKE HENRY, Resources Aide for Congressman Young, said since
President Bush released his energy policy, Congressman DeLay,
Majority Whip, formed a group entitled HEAT (House Energy Act
Team), which meets weekly or more often. Each committee has
jurisdiction over various parts of the energy policy and is marking
up bills this week. He said:
By Wednesday, leadership hopes to have all the
committee's reporting bills relating to the energy
policy. Next Wednesday, leadership plans to bring a bill
to the House floor that has put all the various measures
into one comprehensive energy bill. After the August
recess, if not later, there will be various other small
components come forward that were left out, but no other
large comprehensive bill.
MR. HENRY said that most of the energy bills have been in the
Resources Committee. Several Congressmen, including Representative
Young, authored HR 2436, which contains a right-of-way provision to
study current rights-of-way for new pipelines. The Alaskan
Congressman has also introduced ANWR legislation similar to what
passed the House and Senate in the FY 95 budget. He said the Senate
bill is likely to get reported this afternoon or evening, depending
on how long the amendment process takes. He commented:
The one possible obstacle is the ranking member, Mr.
Emerson Rayhall (D-West Virginia), who has introduced a
committee substitute that is very different. It has the
democratic philosophy on some of the energy issues and
also excludes ANWR, which is an important component
obviously for Mr. Young and committee members, as well as
the President and Vice President. What it does do
specific to natural gas is that it recognizes the ANGTA
route. It basically just instructs folks to look at that
and work towards the ANGTA route and nothing prohibitive
or nothing that requires that route, but highlights and
revalidates the more current ANGTA route. It also
provides right-of-way conditions for any new natural gas
pipeline that crosses public lands, which is going to be
problematic. It's not specific to a large pipeline that
we think of in bringing gas through the state and to the
Lower 48 or to ships for an LNG facility. It's for any
natural gas pipelines. So in that sense, it is so broad
that it is going to be problematic, but it specifically
says that the pipeline must have a "buy American"
component of it while the steel would have to be created
in the U.S., which obviously [is] an issue considering
there isn't any one that makes the pipe that we would
need to build a pipeline of this type. It also requires
project labor agreements. Those are the two - ANWR and
the gas pipeline components that Rayhall's amendment
would have. In the end, I don't think it's expected to
pass and the full measure, as it stands now, the
Resources Committee bill should be able to be moved out
pretty easily today.
Specific to the gas pipeline, which I think is your
focus, Chairman Young's bottom line is that he wants to
bring gas to market.
MR. HENRY said that bringing natural gas to Alaskans is key in the
way they look at a gas pipeline project or any gas project. He
said:
The over-the-top route is certainly something that's
problematic for Mr. Young and one that he has a great
deal of heartburn over. Ideally, we want to see this gas
delivered to the Lower 48, but in the process want to see
it come through the state to the benefit of the state's
economy, as well as Alaskans in general.
MR. MIKE MENGE, aide to Senator Murkowski, said in his position
working with the Senate Energy Committee, he deals primarily with
public lands, Bureau of Land Management issues, and to a lesser
extent, mineral management, and any issues related specifically to
coal and energy in Alaska. He noted he worked in Alaska for many
years with the BLM and USGS and spent most of his career working on
pipeline or pipeline related issues. He said the change to
Democratic control has really slowed down Senator Murkowski's plans
to move and expedite an energy package out of committee.
Essentially, the Senate has been shut down while the reorganization
takes place and is just beginning to hold hearings on Senator
Murkowski's and Senator Bingaman's energy bills. Discussions with
Democrats have revealed that they are in a position to start
marking up legislation next week. They will start with the
Bingaman bill and try to blend it with the Murkowski bill and then
amendments will be added. He thought that next week is optimistic,
since it seems that every time they start, something else comes up.
He reminded the committee that they would be working on the non-
taxed portion of the energy bill. Their goal is to have it ready
for floor debate by September. The House is moving quicker.
MR. MENGE said that [Congress] confirmed the appointment of a
number of Department of Interior officials last Thursday night and
he feels there are now enough people to begin looking at the
various gas line proposals. He stated that, no matter what happens,
the Department of Interior, Pipeline Safety, Federal Energy
Regulatory Commission (FERC) and other federal agencies will play a
pivotal role in determining the route and specifications related to
bringing the gas south.
MR. MENGE said although there is a lot of disagreement with the
Democrats about the various proposals the Republicans have put
forward, just about everyone supports the concept of bringing
Alaskan gas south. He pointed out:
I think it is very encouraging that all of the
participants, both in the major environmental community,
our organizations and in the Democratic Senate, now have
expressed a desire to work together to bring that gas
south.
The President has already directed the agencies to assist
in any way they can in configuring a bureaucratic
organization that will support bringing this gas south
and we'll be working with them to try to work in
organizational structures to facilitate that. As you
know, Senator Murkowski has gone on record on numerous
occasions in support of the Alaska route bringing the gas
south. He does not believe that the permitting hurdles of
the over-the-top route could be addressed in a way that
could satisfy the Native community and the environmental
community in a way that would allow us to proceed
expeditiously. I don't think there's any question that
would address the major hurdles related to bringing gas
south in both the TransAlaska gas system (TAGS) right-of-
way and also the work that was done on ANGTA. So we're
kind of going across familiar territory there. In neither
one of those exercises were any single flaws identified
that would prevent the gas from coming south in a
terrestrial route.
MR. MENGE said the gas going out of Alaska will be very wet gas.
He thought serious consideration should be given to potential
problems that might occur under the ice given an over-the-top
route. He noted the Senate believes those kinds of things will make
permitting the over-the-top route extremely difficult.
He has asked the producers and a representative from the ANGTA
route to suggest language they would like to see in the energy
package that would facilitate the project, but he hasn't heard from
them yet. He offered to answer any questions.
9:30 a.m.
MR. JUSTIN STIEFEL, staff to Senator Stevens, said Senator Stevens
supports Senator Murkowski's efforts to move a comprehensive energy
bill out of the committee that would include the necessary
provisions to build the gas pipeline. He said:
Everyone should know that Senator Stevens is supportive
of the highway route, the southern route, and he wanted
me to stress this specifically. Senator Stevens sees no
reason not to realize that the producers have to analyze
all reasonable alternatives if they are going to prepare
a future EIS. They have to do this both for the
environmental side and possibly because they have a
fiduciary responsibility to their shareholders. If they
decide to choose a route, they are going to have a basis
for that route decision. He wants to recognize up front
that there is a reason they are probably pursuing
multiple routes. While the producers need to do an EIS
for route selection and for permitting and construction,
Alaskans are not going to need an EIS when they make a
selection and voice their preference for that selection.
He wanted me to note that there is a specific difference
between an EIS and an Environmental Impact Study and what
Alaskans would perceive to be an economic analysis. That
economic analysis is that when you have instate gas, you
can have more gas for residential, for commercial
purposes and for industrial purposes and because gas can
be used to make anything from nylons to Frisbees, as
we've all talked about on previous occasions. It's
important that Alaskans have the gas and they can use it
for themselves. So, supporting the Highway route and
looking for the opportunities for instate use is going to
be a critical determining factor, in his opinion.
If we have an abundant supply, that means that we have
more economic development and more jobs. The Senator
thinks that if we stay together as a state, we stand a
better chance of seeing the pipeline constructed and
following the southern route.
In summary, I can say his closing remarks were that,
because the gas belongs to the people of Alaska,
ultimately he thinks their preference is the one that's
going to be selected and, if not, there will be several
roadblocks to taking the gas out of state without being
able to use it for Alaskans.
REPRESENTATIVE GREEN asked, with the change in the Middle East oil
supply in Iraq, and prices going down, whether there might be a
change in the attitude of those people who support the pipeline in
that they might decide that timing is not as much of an issue as it
has been.
MR. MENGE replied that because of the Democratic control in the
Senate and the fact they have made such a huge issue of Alaskan
export of oil, it would be very difficult for them to turn around
and not push for domestic supply.
It's becoming a recurring theme, particularly for the
West Coast Democrats of developing secure domestic
supplies in areas they feel are environmentally
acceptable. Certainly, the Alaska gas at Prudhoe Bay
could fit that category, not to suggest that they might
not change their tune, but right now it would be very
difficult for them because of the arguments they have put
on the record for the export of Alaskan oil. I think they
will stay with us for the domestic gas supply....
MR. HENRY said that low gas prices shouldn't stop us from going
forward with something necessary to create this energy policy for
the country.
CHAIRMAN TORGERSON asked if that is the message the [President's]
administration was trying to put out. He stated, "It seems to me
that they are almost in a panic mode the way they fanned out all
their secretaries across America to talk about the energy policy."
MR. HENRY responded that low gas prices caught the administration
by surprise, but he said it had already been planned for many
months. He thought they were, in part, trying to drum up support
for the energy policy. They were focused on tax cuts earlier and
they are planning for the future and not worrying about how low the
prices are today.
REPRESENTATIVE FATE informed the committee that a discussion took
place at the National Energy Council meeting in New Orleans with a
representative from Alberta. He stated:
It was quite aggressive in that he wanted Alberta to try
to supply the needs on a regional high use basis in the
Lower 48 of the United States, very aggressively meeting
the demand to the United States and, if necessary,
through NAFTA, which was a surprise to me.
He asked Mr. Menge if he has heard anything about it in Washington,
D.C.
MR. MENGE responded:
The Alberta crew comes through here on a regular basis
and we have an on-going dialogue with them. They are
certainly interested in marketing Alberta gas and, in
particular, Alberta oil. Based on their calculations and
ours, there's not going to be any concern about stranded
product, at least in Alberta, with the increased demand.
They are going to very aggressively protect their
interests, but they also recognize the best way to
protect that interest is to lock in North American gas
into the market. That way, if they start developing LNG
projects around the country, that's going to lock out not
only Alaska gas, but their gas as well. So they
understand, better than most, the need to start moving
northern gas south early on so that we protect the
market.
MR. HENRY agreed and said, "LNG facilities are being planned and if
the domestic market isn't self sufficient, then entries from abroad
will come in and it's not good for anyone."
MR. STIEFEL said he didn't have any comment on that issue but noted
that people in Congress have been clamoring for some kind of public
action on the administration's part, similar to the tax cut, the
state based initiatives and other things the President put on the
top of his agenda. He stated, "The timing with the gas prices is
not what people had hoped for necessarily."
CHAIRMAN TORGERSON asked Mr. Henry if he had been asked by any of
the major producers or anyone to add incentives or provisions into
the bill they are currently working on.
MR. HENRY replied no one had approached him, but the delegation had
requested them.
CHAIRMAN TORGERSON asked if provisions for incentives in the House
have to be added in the Revenue Committee and not in the Resources
Committee, as they would in the Senate.
MR. HENRY replied that it is largely the same. They could introduce
a bill that includes incentives that would be referred to other
committees, but a bill with tax incentives would have to go through
the Ways and Means Committee. Since Congressman Young doesn't sit
on that committee, there would be a little less control. He noted:
A lot of people on Capitol Hill do realize that a gas
pipeline is certainly beneficial to the country and would
be a lot more helpful and would help us work through the
process than on some of the other issues that they might
have to fight with them on development issues. There's a
lot of support here. Some of the jurisdictional issues
might be a problem, but we'll have to deal with them.
CHAIRMAN TORGERSON asked Mr. Stiefel if he is aware of Senator
Stevens' perspective on adding tax incentive provisions to an
energy bill.
MR. STIEFEL replied that any tax measure would have to go through
the Finance Committee, which Senator Murkowski sits on. A couple of
the producers mentioned the need for incentives or streamlining
processes, but they haven't brought forward any specific request.
It's hard to move forward without them.
CHAIRMAN TORGERSON asked Mr. Henry, regarding the right-of-way for
pipelines across federal lands, if there are additional provisions
for limited environmental or judicial review in the bill that would
mirror provisions of ANGTA.
9:47 a.m.
MR. HENRY replied that as far as a gas pipeline project, there is a
very general provision authorizing a study for rights-of-way. The
ANWR provision has a limitation on judicial review.
CHAIRMAN TORGERSON asked if Mr. Henry had any discussions with
Ottawa or Canadian officials on the national energy plan as it
relates to gas lines.
MR. HENRY replied that he hadn't been involved in those talks but
that people from Ottawa have talked with Congressman Young.
MR. MENGE commented that they have had meetings with a lot of
officials from provinces who have expressed their positions. An
official position from Ottawa has been noticeably absent. He
thought there may be competing interests within Canada and they are
not eager to take a position until they know a pipeline is going
forward.
CHAIRMAN TORGERSON asked Mr. Menge what interaction he has had with
the Bureau of Land Management (BLM) or the Department of Interior
on any routes.
MR. MENGE responded that he worked in that agency for many years
and knows almost everyone involved in energy-related issues. He
said folks within the agencies are working on timelines,
organization structures and potential budgets and regulatory needs
but nothing official has come forward yet.
CHAIRMAN TORGERSON asked if he has heard anything about opening a
federal inspector's office, "that would be some kind of a big boss
over all the other bureaucrats that we've got running around back
there."
MR. MENGE replied that people are looking at what and how their
specific agencies might contribute, but no formal discussions have
taken place.
CHAIRMAN TORGERSON asked Mr. Henry if the bill being marked up now
contains a provision for an oversight agency.
MR. HENRY replied that it doesn't. He added that the large energy
bill is expected to move in the next week or two and, although it
won't be the only thing the House does on energy this year, it will
be the largest.
REPRESENTATIVE GREEN asked if the resolutions sent by the Alaska
Legislature to Congress are doing any good and if there is anything
else the Legislature could do to help spur people who are on the
fence on some of these issues.
MR. HENRY replied that the resolutions are helpful because they
show the Legislature is advocating a unified position. Also, having
members come to Washington, D.C. from time to time, especially when
there is a big push, is helpful.
MR. MENGE added the resolutions show unity as a state and head off
a lot of trouble at the pass. He said, "It's much more difficult
for people to dismiss us if there's a person or they can conjure up
a vision of an individual who has come and made a solid case in
their office."
MR. MENGE also said that Senator Murkowski asked him to express his
personal appreciation for leading this group in advancing this
issue.
CHAIRMAN TORGERSON asked if Mr. Henry had the votes in hand on the
ANWR provision in the House.
MR. HENRY said it would take work, but all indications look good.
MR. STIEFEL concurred with Mr. Menge and Mr. Henry on the
resolutions. He said that he sees there are two lines being drawn.
He didn't know of any real opposition to allowing the pipeline to
go forward and be constructed from the executive perspective or the
congressional perspective. The second is the decision the producers
make, which is based on economics. Whatever the state could do to
encourage construction of the pipeline by altering economics with
incentives would help get gas to market.
CHAIRMAN TORGERSON said he appreciated their comments and thanked
them. He announced the committee would take a short recess.
10:00 a.m.
PIPELINE ACCESS ISSUES
CHAIRMAN TORGERSON called the meeting back to order and said they
were going to hear remarks from the Federal Energy Regulatory
Commission.
MR. ROBERT METHURA, Office of Energy Projects and Pipeline
Certificates, FERC, said he would have to speak in general since
there was no specific project for Alaska yet.
MR. JOHN KATZ, Office of the General Counsel, FERC, said they had
received Senator Torgerson's letter of June 25 and had discussed
his questions. They didn't have any formal comments and asked him
how he wanted them to present their information.
CHAIRMAN TORGERSON said he could go through the questions to stay
focused.
MR. KATZ reiterated that it was inchoate for them because there
weren't any specific proposals in front of them now. They would
move as expeditiously as possible when that happened.
CHAIRMAN TORGERSON said the first question is the relationship
between the Regulatory Commission of Alaska (RCA) and FERC over the
jurisdiction of a gas pipeline from Alaska to the Lower 48. He
noted that this question at least got the two agencies talking to
each other.
MR. METHURA said they normally are interested in being open and
cooperative with the state that is affected with a pipeline
proposal.
MR. CUPINA added that as helpful as it would be for Alaska to
coordinate its entities, a project's regulation would be under FERC
jurisdiction as an interstate pipeline.
CHAIRMAN TORGERSON said that his open season question and providing
access to Alaskan communities seems to be a joint responsibility.
His second question was about the process and timeline for handing
in an application under either the Natural Gas Act or the Alaska
Natural Gas Transportation Act.
MR. METHURA replied that there are so many variables, he couldn't
even speculate on a time frame. Typically for large gas pipeline
applications under section 7 of the Natural Gas Act the
environmental analysis is the critical path. They have gotten to be
very efficient at managing and completing that process having done
a number of major projects in up to a year and a half. A couple of
projects have taken longer than that, but it's the exception rather
than the rule.
MR. KATZ responded that he didn't think that processing an
application under ANGTA would take any longer, but it's hard to
speculate beyond that.
CHAIRMAN TORGERSON said his third question was whether such a
pipeline would have a common or contract carriage, who controls
when the open season occurs and how and when Alaskan communities
sign up for service.
MR. CUPINA responded that their approach to interstate pipelines
they regulate is that they are contract carriers on an open access
basis, which means they can't unduly discriminate against any
shipper in terms of rates, conditions and duration of service, etc.
The common carriage characterization is more closely associated
with the oil pipelines under the Interstate Commerce Act.
As to who controls the open seasons, he said the sponsors of
projects are encouraged to conduct open seasons as part of
designing the pipeline and properly sizing it and, more
importantly, for open access purposes to insure that all potential
shippers are aware of the availability of a new project and have an
opportunity to respond to an open season in order to get served.
The third part of the question seems to assume that there would be
mid-point delivery points along the way and that would depend on
what the design of the project is. He said the Alliance Project
from Western Canada down to Chicago has two points, the receiving
point and the delivery point in the states. In an open season, he
would expect any and all potential shippers to express an interest.
CHAIRMAN TORGERSON asked if the open season requested by the owners
of the line does not correspond with actual resource data on
resources that may be available, for instance, if some wells
haven't been delineated, so another producer may not be sure of
what's there, whether we could force that timeline back or they
could force it back for a period of time on the open season or
whether they are locked into the time asked for by the owners of
the line.
MR. CUPINA answered that they typically don't have information on
the open season until the application is filed, unless there were
problems with it, for instance, if potential shippers were denied
access or it wasn't advertised sufficiently in the publications
available to them. That's when FERC becomes involved in resolving
disputes regarding open seasons. "We are not in the position up
front to control the open season because we wouldn't be aware of
the details of it until after the application came in."
CHAIRMAN TORGERSON asked if the open season was generally a part of
the application.
MR. CUPINA said it is quite a bit ahead of time, because it helps
inform the design of the pipeline; it helps in the sizing of it.
REPERSENTATIVE GREEN said he understood that the line might be
designed initially for 4 BCF/D and since it's compressible, that
could be increased later by adding more compression. He asked if a
producer who missed the first open season would be able to
participate in the next open season when adding compression.
MR. CUPINA explained that they encourage open seasons for every
expansion.
REPRESENTATIVE GREEN said that mid-point delivery points might be
affected if a discovery was made down the line someplace. He asked
if that would trigger another open season.
MR. CUPINA replied that it could, especially if it created a need
for additional capacity as opposed to simply providing another
point of input into existing capacity. "If existing shippers were
getting gas from an additional source, perhaps not. We don't think
of that as an expansion. But if the additional source has created
expansion to add new shippers, that would probably be an open
season event."
CHAIRMAN TORGERSON said his fourth question was how access to the
pipeline would be determined initially and how access will be made
later. He asked if there were additional comments on that.
MR. CUPINA responded, "Once a pipeline becomes operational, it
operates under a FERC tariff, an open access tariff, which controls
the types of service that it offers, which are usually a firm
transportation service and an interruptible service and the terms
and conditions of that service."
He said, "This assures that shippers are getting some uniformity as
far as balancing penalties, nominations, etc. On a continuing
basis, the pipeline is under their open access requirement to
advertise capacity and sell that capacity under the terms and
conditions of its FERC tariff."
CHAIRMAN TORGERSON asked the fifth question: How will the expansion
of the pipeline be handled and how will the Commission handle
incremental costs?
MR. ROBERT PERTOCELLI, Office of Energy Markets, Tariffs and Rates,
FERC, responded that generally expansions come under two
categories. If they fall under a certain dollar amount, they are
considered under the blanket and all of their costs are rolled in.
If they exceed the blanket amount, they have to file a separate
application and the extension would be treated as either
incremental or rolled in. If they raised the rate at all, they
would be treated as incremental. If the rates with the new volumes
and costs together were the same, they would be treated as rolled
in. If they lower the rates, they would also be rolled in.
REPRESENTATIVE GREEN asked how FERC worked with the pipeline
traverse in Canada.
MR. KATZ replied there are pipeline treaties in effect between the
United States and Canada that deal with coordination of
international efforts. That's probably more under the purview of
the Department of Energy. The Commission would certificate that
portion of the line that is in the U.S. territory.
MR. METHURA followed up saying that while they don't have direct
responsibilities with respect to the Canadian portions of the
pipeline, they are in informal communication and cooperation with
the staff of the National Energy Board so they keep each other
updated about the project.
MR. KATZ agreed, but said they wouldn't have any jurisdiction over
any portion of the line that wasn't in the U.S.
REPRESENTATIVE GREEN said there has been some concern as to how the
TAPS rate was established and how it considered maybe too many
things. "With FERC dealing with a gas line like this, what sort of
process does that go through to ensure the net back is on a fair
basis?"
MR. PETROCELLI answered, "The rates are generally calculated in
accordance with cost of service methodology. We use a standard
formula to determine the rate base, the investment, the expenses
are generally estimated. Then we apply a rate of return that is
within the bounds that's been accepted at the Commission for other
pipelines of similar risks."
CHAIRMAN TORGERSON asked if adding the conditioning plant into the
base rate was a standard policy since and if that would
automatically be added to the tariff.
CHAIRMAN TORGERSON said it was his understanding that it would
MR. KATZ said the circumstances around [TAPS] were a little unique
because they resulted from some presidential waivers and other
things that related to ANGTS at that time. He couldn't say whether
a conditioning plant would be included in the rates of the pipeline
as a whole. Typically, such a plant is included in rates only if
it's part way down the pipeline.
10:25 a.m.
CHAIRMAN TORGERSON referred to Representative Green's question
about a future discovery, for instance in the Big Delta area, where
another conditioning plant would be necessary. He said he assumes
they could put provisions in the tariff to where they wouldn't
automatically add in the one conditioning plant on the North Slope
if you had your own or were required to build your own further down
the line somewhere.
MR. METHURA said it seems like he is asking if FERC plays some role
in requiring an existing pipeline to expand in the event of a
discovery. Typically, they don't do that; it's up to the pipeline
owner and new customers to get together and decide if there is an
opportunity for expansion.
MR. CUPINA observed that the way they regulate pipelines now, they
only perform the transportation function. In the Lower 48, the
processing activities and preparing the gas for pipeline quality is
part of the producing, gathering, and processing function that
happens in the producing field at the producer's expense. Some
issues he is raising may be the producer's or the shipper's
responsibility.
CHAIRMAN TORGERSON said he didn't want the state to be regulatorily
locked out of the expansion and that:
We basically have one field that this gas is going to
come out of to begin with and we have never, until
recently, drilled looking for gas on the North Slope. So,
we have a vast area where it's projected to be a lot of
reserves, but there's no incentive for other companies,
besides the ones who own the resource and who may end up
owning the line, to allow other people into the line.
That's a huge issue in the State of Alaska, as well as
the other producers that may want to drill up there.
He wanted to know what FERC and the State could do to control that.
MR. CUPINA said:
The Commission has nothing in their statutes requiring
expansion of a pipeline. However, several months ago, in
response to a court remand, the Commission issued an
order on pipeline interconnection that permitted shippers
to hook into a pipeline. As a result of that, it became
more difficult for a pipeline to refuse to tap into its
line. We expect there will be tariff provisions and we're
seeing more and more of them that set out the terms and
conditions under which the pipeline will consider these
requests for someone to tap into their line.
What I'm getting at is that it's getting more difficult
for a pipeline to turn anyone down than it would have
been before. Having said that, under open access, if
there's no capacity available on the main line, even if
you get hooked up, you may not necessarily get firm
service and the pipeline is not required to prorate any
other capacity as would a common carrier…
MR. KATZ agreed and said that typically the way these matters are
dealt with as a matter of business negotiations. Everyone has a
role to play in the certification procedure whether they support or
oppose the project and general concerns about how a pipeline will
be built, other routes, etc.
10:31 a.m.
CHAIRMAN TORGERSON said that brought him back to the question of
the open season and how that can be controlled, if it is
controlled. For example, he said:
What if they had an open season that met the requirements
and specifications they just laid out and do it well in
advance of anyone having a field developed, can we or you
postpone the open season to a later time line that
wouldn't necessarily affect the overall start of the
pipeline.
MR. METHURA said that would be a policy call for the Commission.
Their general policy is that if someone has an acceptable project
on environmental and other grounds, and if they are willing to put
up the money to pay for that project, the Commission is going to
consider it. An argument against it could be that it is too early
and the area is not developed and it's not in the public's interest
to approve a project at this time. He didn't know what the
Commission would do.
SENATOR KELLY said FERC couldn't assure that anyone could get
access to the pipeline on a firm basis and asked if it's worth it
for someone to develop a gas field and have their transportation be
on an interruptible basis. "Practically speaking, are they able to
go out and market their gas, if their transportation is
interruptible?"
One of the FERC officials replied that would be a business call.
There are other options in addition to interruptible, like capacity
release. Under that provision, existing firm shippers who may not
be using their capacity or all of it are authorized to sell it like
a sublease. That is just as firm as pipeline firm. Another way to
look at it is that the pipeline makes its profit by transportation
gas. So, its got a business incentive to expand and to take on more
business and increase it's revenues.
REPRESENTATIVE GREEN said:
Up here there are occasions when the oil pipeline gets
spiked with gas liquids - an undersaturated oil could
take more gas liquids and stay stable and be shipped to a
refinery to be worth more. There is a possibility with
this high pressure line that there may be shipping of gas
liquids from the start, but if down the road the producer
was to be on the road system, find some gas, go with
methane only, and the original producers may say no.
That's what we don't want in our pipeline. To what degree
does FERC get involved in something like that?
One of the FERC officials replied:
The only thing that comes to mind is the Alliance system,
which at one point was wetter than a typical pipeline.
Those kinds of things would be spelled out in its quality
standards in its tariff. Those issues would be considered
and resolved up front, before we approve that pro forma
tariff that's filed along with the construction
certificate application.
REPRESENTATIVE GREEN asked, if there was to be a subsequent open
season for a mid-point delivery point from a mid-point delivery
point, the contract would originally have provided for that and
there would be some sort of adjustment for that on a BTU basis or
some other thing, whether it would be a FERC problem.
The FERC official responded that the pipeline's tariff would
provide for that.
MR. METHURA added that at some point in the future a new
prospective shipper and the existing pipeline owner could negotiate
something different, like amended tariff provisions that would
allow for dry gas.
REPRESENTATIVE GREEN asked if there was capacity and the original
owners said they didn't want dry gas, whether that would be grounds
to prevent another producer from getting in.
MR. PETROCELLI replied if they can't meet quality standards for
delivering gas, that could be grounds to refuse entrance.
SENATOR KELLY asked if capacity release would be found mostly in an
environment where they had demand that was low.
MR. METHURA said it varies. There might be capacity available at
different times during the year. There are various reasons why
capacity might be released. He explained if every shipper is using
it's own capacity at maximum load factor every day, there won't be
any available to be released but, on many systems, capacity is
released every day throughout the year, even in the peak season in
the winter.
10:40 a.m.
SENATOR KELLY said it seems if you were in a business environment
where demand was very high, you wouldn't have a lot of
opportunities for those who do not own the pipeline to get their
gas transported through it on anything but an interruptible basis.
He asked, "If there was a period of high demand, why would the
people who own the pipeline have any incentive to allow space on
their pipeline for those?"
One of the FERC officials replied they can only sell on an
interruptible basis if some firm shipper is not using capacity. The
interruptible capacity, itself, is a consequence of unused firm. It
adds an incentive to expand.
MR. PETROCELLI said:
You seem to be operating on the assumption that the
pipeline owners would be the transporters. There's a
whole class of rules that apply to affiliate shippers,
but first of all, under our unbundling rule, the pipeline
owners generally don't do the transporting. They just
sell transportation to other shippers. Those shippers
have fair access rights unto themselves. So, any shipper
who wants access should be able to gain it. He wouldn't
be competing supposedly against the pipeline owners.
Although affiliates can transport, there are rules that
apply so that everybody has equal access including the
affiliates.
CHAIRMAN TORGERSON asked if that brings them back to the question
of whether or not whoever files for this - it could be the
producers - has to be a common carrier.
MR. PETROCELLI asked if he meant common carriage in the sense of
talking about open access of contract carriage.
CHAIRMAN TORGERSON indicated yes.
MR. PETROCELLI said, "You can't unduly discriminate under the
Natural Gas Act so you are open to all shippers whether they are
affiliates or not."
CHAIRMAN TORGERSON added, "As long as you go through the provisions
of the open season and the rest of that."
MR. KATZ responded:
It comes down to business choices. If they conduct an
open season and affiliates of folks who are proposing to
build the pipeline want to sign up for 100 percent of the
capacity, the question is whether there are other folks
who want to sign up for capacity, too. Usually what
happens then is that it gets allocated…. The question
remains, are you willing to pony up the money to reserve
space on that pipeline, and that becomes a business
decision.
MR. CUPINA said the committee was imagining when an application is
filed, there's going to be some tension. They want to slow down the
open season versus those who are exhorting them to speed it up,
their general direction.
10:45 a.m.
CHAIRMAN TORGERSON responded, "Not necessarily. The open season of
the example I gave you may be two or three years before you're
permitted."
He then asked Mr. Cupina if he knew of any regulations under their
purview that would create a hub, such as coming down to Fairbanks
and spinning off to other projects in the state. He asked whether
FERC or the RCA would regulate that.
MR. CUPINA responded:
We don't regulate hubs. We kind of stand back and let
hubs develop and market centers. While we don't regulate
hubs per se, there might be some services within that hub
that the pipelines that interconnect there perform that
we do regulate and that are additional services under
their tariffs....
REPRESENTATIVE DAVIES said he is concerned about the common carrier
aspects of FERC's regulatory framework. He asked how much of the
regulatory environment is set by the pattern down south where most
producers do not own the pipeline. He noted, in Alaska, we might
have a situation in which the producers are the dominant owners and
there is a serious possibility of anti-competitive situations
developing on the North Slope. He asked how that might affect the
way they regulate an Alaskan gas pipeline.
TAPE 01-2, SIDE A
MR. CUPINA replied that there are some producer-owned pipelines in
the Gulf of Mexico and that:
Although they transport some of their own gas, they are
open access pipelines like we've been describing. We've
held them to the same standards as the pipelines that are
not producer owned or producer affiliated.... If you had
a story to tell to persuade the Commission that something
should be different, the burden would be on the sponsor
to do that, or interveners, for that matter, in the case.
10:50 a.m.
REPRESENTATIVE DAVIES asked if he could provide an example of a
producer-owned pipeline that transports other folks' gas at this
point.
MR. CUPINA said that Shell's (Gordon Banks, now) initial business
plan was to move its own gas. "They came in on a prefiling basis to
discuss some of these things and we advised them accordingly and
they have open access tariffs."
CHAIRMAN TORGERSON thanked everyone in Washington D.C. for their
testimony and said they would now hear the RCA presentation.
10:52 a.m.
MR. METHURA said they appreciate being involved and want to leave
the committee with the impression that they are anxious to
cooperate.
CHAIRMAN TORGERSON assured them that the Alaska Legislature is not
trying to slow the project down, but "to understand a little bit
more of what your function is compared to what we have to do with
in-state functions...."
Regulatory Commission of Alaska
MR. ANTHONY SCOTT, staff to the RCA, said that the FERC is in
charge if there is one molecule of interstate pipeline and on the
TAPS they have joint jurisdiction with the FERC. He stated:
Under the Natural Gas Act, there is a large body of case
law, which says that if molecules that are interstate and
molecules that are intrastate mingle in the same
pipeline, all the gas in the pipeline is considered
interstate even though some of it comes off earlier.
There's a lot of case law suggesting [indisc.] Bob
Maynard, when he was Attorney General back in 1976, wrote
an opinion in which he suggested that authority over
intrastate movement of natural gas would pretty much be
preempted by the feds. Finally, there's express language
in the Alaska Natural Gas Transportation Act, which seems
to say pretty clearly that the feds have jurisdiction
over tariffs for intrastate gas. What that means is that
it looks like the RCA in terms of tariff setting and so
on is pretty much out of the picture.
MR. SCOTT said he would provide the committee with some background
as to what the RCA's authority is. He said that FERC's authority to
border access is not as strong as RCA's appears to be.
We have two different statutes under which we regulate
intrastate natural gas pipelines and we have gas
pipelines in the state that are under both. We have gas
pipelines that are under the Pipeline Act and they are
considered pipeline carriers and are common carriers
similar to the situation that we have with TAPS. Then, we
also have gas pipelines, both the Beluga line in Cook
Inlet or Enstar System, which are regulated under Title
42.05, our public utilities legislation. They are not
common carriers. They're also not contract carriers. We
don't have such a thing as contract carriers for public
utilities.
The Commission powers insure access or [indisc.]
depending upon the particular statute the pipeline falls
under. For intrastate pipelines that are certificated at
the pipeline areas of the public utilities, the
Commission does have prorationing authority, so that if
space on a line is limited and nominations exceed
capacity, we can proration or we can decide - our statute
doesn't require that we can strictly proration, but we
can decide how to allocate that capacity. We don't have
that clear authority for public utility pipelines.
The Commission also can order a facility's expansion
under [indisc.] by statute. Our expansion authority is
actually a little bit clearer and stronger on the
pipeline side than on the public utility side. So, unlike
with the FERC, if we have a [indisc.] gas pipeline, which
is certificated as a pipeline, we can order them to
expand capacity. We also, under both our statutes, have
interconnection authority and the language under both
statutes is identical. Finally, for pipeline carriers
during construction, the state can order the pipeline to
install offsite facilities. The state has to pay for
that, but nevertheless, if it was determined that it was
cheaper to do up front, they could order [indisc.]
facilities installed.
An unidentified person interrupted, "You had prefaced this by
saying the state would not be involved. It was purely the
jurisdiction of FERC. Is that true about during construction as
well?"
MR. SCOTT answered:
That's a good question. I think so. I mean I think our
ability to order that would probably be preempted. I'm
less clear on that, though. What is clear is that we
wouldn't be able during construction to order off-site
facilities unless the pipeline was certificated by our
Commission and there would be no need for an intrastate
certificate if there are, during the open season, no
nominations for intrastate shipment of gas. So, if nobody
steps to the plate within the state and says we want some
gas and we're willing to commit to it now, during
construction, they wouldn't need an RCA certificate.
There would be no intrastate sales. So, our ability to
exercise that authority clearly does not apply.
An unidentified person asked if FERC would have to make that
determination, anyway, "If there is a molecule of interstate gas in
that line, you're out of the picture, right?"
MR. SCOTT replied that is correct.
REPRESENTATIVE FATE asked if, with construction, there is such a
thing as a change order while in progress, rather than having to
plan ahead.
MR. SCOTT replied, "I'm not familiar with the language change
order, but for pipelines that are certificated by the RCA, it's
conceivable that we would be able to require during construction to
order offsite facilities. If they're not certificated by the RCA,
it's very clear we're out of the picture. Even if they were
certificated by the RCA, we might not have that authority. We might
be preempted."
REPRESENTATIVE OGAN said, "So, FERC regulates from the well-head to
wherever the pipeline connects to the hub somewhere?"
MR. SCOTT answered, "Yes."
REPRESENTATIVE OGAN said there had been some discussion about a hub
concept in Alaska and, although it's probably not an appropriate
term because there's only one spoke coming from the supply side,
there might be two or three spokes coming out of the demand side,
and [indisc.]. He said that basically they were moving the
wellhead to the hub point. He asked if that concept was put into
statute, would the RCA have authority over who's in or who's out
and then the FERC regulates from that wellhead that's moved from
the North Slope to Delta or wherever from there on down.
MR. SCOTT said that was an excellent question, but they didn't have
an answer for it yet.
REPRESENTATIVE OGAN said the House Oil and Gas Committee intends to
explore that possibility in statute before next session.
MR. SCOTT said he was disappointed that the FERC people left,
because he was interested to hear their input.
REPRESENTATIVE GREEN said he was confused and asked:
Let's go from the hub down to some other market that
would by its nature be under FERC, but that in route some
gas is pulled off for one or more utilities. There was
prior testimony in the Oil and Gas Committee that that
portion would be under RCA - that portion that went to
the utility. So, you would actually have a dual
regulation. Any, yet, I just heard you say that if
there's a molecule of FERC gas in there, it's all FERC.
MR. SCOTT replied:
Even though there was off take of gas in Fairbanks, it's
all regulated by FERC.... Even though those molecules are
produced instate and they're taken off instate, the line
to get it from the North Slope to Fairbanks is all
instate, it's treated as interstate shipment of gas.
REPRESENTATIVE GREEN said, "So, that earlier testimony was not
right. There wouldn't be dual oversight?"
MR. SCOTT said, "That's right.... If you commingle molecules that
are bound for intrastate market, the molecules that are intrastate
all become interstate."
MR. ABBOTT, RCA Commissioner, said another scenario is getting it
off the pipe and taking it to a distribution center and then it
goes into [indisc.]. We don't know where that cut off valve is
going to be that says that belongs to the state to regulate and
this belongs to FERC to regulate. [indisc.]
SENATOR KELLY said he thought he understood that they are talking
about a federal molecule of gas that has gone to a distribution
center where it becomes someone else's - a whole separate pipeline.
CHAIRMAN TORGERSON said:
Assuming that access is going to be voluntary, I know
you're talking about your power to demand an increase in
capacity, I don't necessarily think you're going to have
to do that, but in the hub, my definition of a hub might
be different than yours. A hub is just a valve where you
have a price set. Is that your definition, too? From
Prudhoe to Fairbanks, that hub - you have a price
predetermined at that particular location. So, if you
spun off that....
MR. ABBOTT responded that it would be nice if it worked that way,
but they needed to look at that further. His understanding is,
"Absent the market, where ownership of gas changes hands and so on,
that's a hub concept. Just the idea of a valve doesn't get you
where you would like to go."
CHAIRMAN TORGERSON asked him to explain the process to him.
MR. ABBOTT replied they have had preliminary discussions with the
Department of Law who indicated that their authority to regulate
tariffs looks to be preempted [by FERC].
CHAIRMAN TORGERSON said:
If this is federal law, what Representative Ogan was
talking about, state law, really has no bearing on it. Is
that correct? Tell me how this would affect your
jurisdiction over an all-Alaskan route. It may be for
export or maybe to the Lower 48 or somewhere else. Are
you the main players in an all Alaska route or is that
also FERC?
MR. ABBOTT answered that he thought that would be FERC, because of
interstate commerce.
REPRESENTATIVE PORTER said, "An Anchorage spur that was not at its
terminus for export, would the RCA have the line from where it
hooked up to the line to its distribution in Anchorage?"
MR. ABBOTT answered, "Generally, I believe, yes, we would."
REPRESENTATIVE OGAN asked, "It looks like the FERC would
hypothetically get involved in an LNG line to Valdez, for example,
when the ship leaves the port, when the ship arrives, or would they
be involved in it for the whole thing?"
MR. ABBOTT replied, "I think the whole thing from the North Slope
down."
CHAIRMAN TORGERSON asked, "Who's looking after FERC if they have
all this responsibility?...You're starting to worry me a little
bit."
MR. ABBOTT replied:
It strikes me, in terms of policy, we're supposed to take
care of pipelines that are within our jurisdiction.
Insuring that pipelines are within our jurisdiction is
probably a matter for you folks to take up either
directly or through the congressional delegation or what
have you. I'm not sure. It's not clear to me that we want
the RCA running around trying to grab turf.
CHAIRMAN TORGERSON agreed, at least until they get a legal
analysis. "As an Alaskan, I'm territorial as all get out. And I
want Alaskans to make decisions on what's happening. Not back in
DC...."
MR. ABBOTT said he thought that concept had served them well on the
TAPS. He used the Golden Valley tariff as an example for joint
jurisdiction where it helps secure lower tariffs. He said they had
discussions with FERC regarding who pays for capacity [indisc.].
RCA doesn't have existing precedent on the gas side. In general, if
everyone benefits from the capacity expansion, the cost of it is
generally shared.
CHAIRMAN TORGERSON asked if he had any interaction with Canadians
on how they are going to handle this.
MR. ABBOTT replied that they hadn't. He said RCA would handle a
distribution system.
CHAIRMAN TORGERSON asked if FERC would set the price at the valve.
MR. ABBOTT said that was right and it was a real concern in terms
of Fairbanks off-take having to pay the Henry Hub price.
CHAIRMAN TORGERSON thanked them for joining the committee and asked
to get copies of any legal opinions on this subject. He announced
the committee would break for lunch at 11:19 am and they would
start again at 12.45 pm.
12:45 p.m.
CHAIRMAN TORGERSON called the meeting back to order and asked Mr.
Ed Small to testify.
Cambridge Energy Research Associates (CERA)
MR. ED SMALL, CERA, made the following statement.
...I intend to be as realistic as possible to describe to
you the fundamentals as we understand them and as we
expect to see them unfold. There is a window of
opportunity for Alaskan gas. It is just that, though, a
window of opportunity. It is not a done deal by any
stretch of the imagination.
That window of opportunity is probably larger than it has
been at any time in the past. We have seen windows of
opportunity for Arctic gas come and go. We think there is
a reasonable probability or possibility of seeing Alaskan
gas within the course of the next decade. I would have to
suggest that, as one of my colleagues says, he's been
suggesting that will be the case for the last three
decades. So, again, it's not a done deal.
What I do want to talk about is what some of the drivers
and what has created this window of opportunity, what
some of the opportunities are, and what some of the
pitfalls as we see them will be.
One of the biggest factors in creating this opportunity
as you can see is we have gone to a point in time where
the pricing level is significantly higher than it has
been at any time in the past. We have gone from a level
of below $2 to a level where we're going to see prices
averaging over $4, taking the average of 2001 and 2002.
Again, I have to point out, though, the weak link in that
is the 2002 price. It is being propped up by the prices
we have seen over the past winter. We don't expect to see
prices go down to those lower levels in the past. We also
don't expect to see them staying in that $4 range.
The biggest driver behind the prices we see today is the
demand. We see a situation in the Lower 48 where
installed capacity has increased but it has not kept up
with peak demand. The situation has been created whereby
we've seen capacity margins, which have dropped down
below 10 percent, are slowly coming back up to 10
percent, for which the conventional thinking is that they
need to be around the 15 percent level in order to
adequately handle peak demand and demand needs, because
of whatever. We're a long way from that 15 percent
margin.
It is that narrowing gap between the installed capacity
and the peak demand that is creating the need for a lot
of the natural gas demand going forward. We saw close to
30 gig watts of capacity installed last year. We're going
to see between 45 and 50 gig watts this year and probably
a similar number next year. Those are almost exclusively
gas fired. This graphic only shows the projects going out
to 2005 and it looks like a declining number. That's only
because a lot of the projects close to 2004 have not hit
the books, yet. So, we do expect to see power generation
being one of the strong drivers of gas demand throughout
the next decade.
What this picture shows is the two areas the Arctic gas
would target are two of the strongest growing regions,
the Midwest and the West. One of the things we do not
subscribe to, though, is the 32 percent growth. We have
heard a lot about that potential growth level, that
demand level by 2010. We view that as being more
plausible than probable. If you look at the upper line in
this picture, it shows an unprecedented level of growth
required to get there, growth both in supply and in
infrastructure. We just do not see it happening. With the
demand structuring and high prices we have seen over the
past winter, this makes a 32 BCF world even less
probable, in 2015 perhaps, but not in 2010.
MR. SMALL explained three different bars on his graph. CERA sets
out different paths that the world may evolve on. They are
separate, have their own drivers and are all plausible. "Gas
favored the world we were in up until two years ago. It is one
where supply and demand grow in lock step. It was a very healthy
economy and a robust world. It is the least likely at this juncture
going forward."
Supplier realignment is the path that we are on currently. It is
the one where supply has failed to keep up with demand. MR. SMALL
said:
It is also a world of strong growth going forward,
though. Lower GDP's and gas favor a strong economic
growth. It is the world that requires gas supply from
other sources. Those frontier sources could be offshore
Canada, they could be LNG, they could be a resurgence in
existing areas…What it does show in this world, on that
path we are on, we do not even achieve a 32 BCF world by
2015.
MR. SMALL continued:
The aftershock is the scenario that we developed about a
year and a half ago that said, "Well okay, what happens
if we see a recession starting in the second half of 2001
going into 2003?"
It is one where we see a slow down in growth in both
supply and demand, but peaking out towards the end of the
period when both of them get back to a comparable
realignment with supplier realignment.
MR. SMALL explained that the producers' idea of the price softening
[to $3] is almost amusing, because that's almost double what it was
two years ago. Perspective can change quickly he said.
What has brought the price down from the highs we saw
this last winter has been the resurgence in storage
refills in the Lower 48…It was extremely doubtful whether
they could be filled to even last year's levels, which
were considered low by the end of this injection season.
That has turned around substantially. We have seen
injections that will put us not only above last year's
levels, but will probably approach 1999 levels. That will
probably be adequate to prevent significant or serious
price spiking that we saw over the past winter again this
winter.
What that means in the short term, in a pricing context,
is we saw prices spike at over $9 last winter, which was
significantly higher than we had seen on a sustained
basis before. We do see softening next year. We expect
next year's average to be $3.53 Henry Hub versus the
$4.45 that we're seeing for this year. So, this year is
probably the peak.
MR. SMALL reiterated that CERA didn't expect to see prices
dropping down to the previous levels of 1998-99, but they
should be significantly lower than the past winter. The same
dynamics are at play with the Alberta price. "Even though
there is excess capacity out of Alberta currently, we expect
to see a wide differential in prices between Henry Hub, which
is the U.S. prime pricing point, and AECO (Alberta Energy
Company) of almost 70 cents."
They expect to see an Alberta price of $2.85.
He said the two target markets for Arctic gas are the Midwest
and the West Coast, areas that command a slightly larger
premium from the Henry Hub price, although he didn't know how
sustainable that was in the long run. He said:
It is subject to supply. Currently, there is a
significant premium in California to Henry Hub and a
modest premium in Chicago. For the purpose of Arctic gas,
it is probably best to think in the context of Henry Hub,
at least for planning purposes.
One of the reasons that we got through last winter is
that the system is flexible. There wasn't a crisis. There
was a shock to the system, definitely. What we saw was
6.5 BCF of demand come off the market. That's how we made
it through the winter. The price controls [indisc.]. That
is going to have a long lasting impact. As you can see,
switching to residual fuel oil and distillate fuel oil
took off almost 4 BCF. Ammonia, methanol - the cessation
of creation of those products - resulted in a demand drop
of about .8 BCF/D. We saw ethane not being taken out of
the gas stream, but sold as gas, which had an impact on
the petrochemical industry and we saw decreased
manufacturing of .7 BCF/D.
Go to today's world, specifically the third quarter of
this year, and the outlook that we expect to see is one
where there is still demand that has not come back on.
Seven hundred million per day of decreased manufacturing
we don't expect to come back. There is a question as to
whether that was due to the high prices or due to the
soft economy. The answer is probably both, but we don't
expect to see that manufacturing come back on in the near
term.
We expect to see residual fuel oil priced into the
market, in other words, displaced gas demand for at least
the next year, if not two years. There is 700 MCF of
ammonia that is not being manufactured. That may not come
back. Due to high prices, that product may go overseas or
offshore of North America permanently.
The same with methanol. Distillate, we probably don't see
that being in the market until next winter. If demand is
strong enough next winter, you will see gas priced out of
the market and distillate priced in. Ethane will probably
be above that point. Those dynamics will continue to be
in play going forward depending on the price. So, this is
a structure one could expect to see not only in the past
winter, but going forward. This just shows one aspect.
I wanted to pick one aspect to show what has happened
with the high price today. You can see when natural gas
prices spike, ethane production drops dramatically. This
is something to keep in mind if there is any interest or
intention of developing a petrochemical industry in
Alaska. When you see the gas prices spiking, the source
of the supply for the petrochemical industry is gone. So,
your petrochemical industry is [indisc.]. That is a
significant factor going forward, as well.
Do we expect to see softening going forward? Am I a
pessimist? We expect to see prices that are above what
we've seen in the past, but not anywhere like what
occurred in the past winter. We expect to see through
2005 prices that will begin in the low to mid $3 range.
The volatility will be more on the upside than the
downside simply because that residual fuel oil I
mentioned is providing a floor for gas prices and will
probably continue to provide that floor until supply
picks up. So, over the next five years we expect to see
minimum downside spiking and potential upside spiking,
but with a price that's in a range of $3 - $3.25 level.
On the supply side, which is the other side of the
equation that gets you to price, the demand being one
side and the supply being the other, what is the picture
in a North American context? We see both coming from four
specific areas - western Canada, the U.S. Rockies, the
Gulf Coast and U.S. Gulf of Mexico, and Sable Island
offshore east Canada. A lot of the other areas in the
Lower 48 are mature, are having trouble keeping their own
and the record drilling levels in the U.S. probably will
only support a limited amount of growth.
We are seeing record drilling both in the U.S. and in
Canada. It is starting to have an impact. We finally got
the actual numbers in for 2000 and supply decline in the
Lower 48 was lower than we anticipated. The supply growth
this year, largely because of the high drilling, is going
to be higher than the recent estimate. We expect to see
growth in the Lower 48 of between 500 and 700 MCF/D going
to between 700 and 800 MCF/D next year. The large
percentage of the drilling activity in the Lower 48 is
gas directed. We don't think that the current prices are
low enough that that is going to disrupt or discontinue
the current drilling activities that we are seeing. So,
we expect to see robust drilling over the next year,
which should support the growth levels that I mentioned.
One of the factors that opened the window for Arctic gas
was the gas production in the U.S. has been flat to
declining (referring to graph illustration). What we do
see, though, is for the Lower 48, we feel 2000 was the
bottom point. We see the capacity in the U.S. Lower 48
growing. What is interesting though, is that it's going
to take until almost 2005 to get back to 1995 levels. So,
there's still a need when you couple that with the
growing demand.
Onshore production in the U.S. is a bit of a different
story. It is going to grow through about 2005, 2006 at
which time we see it flattening out. So, even with the
drilling levels we see, the conventional areas in Lower
48 onshore have limitations. What is going to happen is
that growth in the Rocky Mountains, as one example, is
going to offset declines in the Anadarko and [indisc.]
areas.
The other offsetting factor is the Gulf of Mexico. There
are two dynamics at play here. The one has been most
responsible for the decline in the Lower 48 for the last
several years and has been the steep decline in the
shallow shelf. That is an area that has high
productivity, but high decline. With the low prices that
we saw in both oil and gas in 1997, drilling activity
almost ceased in this area. That steepened the rate of
decline. It's an area, because of the high decline, that
you have to continue drilling to replace production.
We're starting to see that turn around. We don't expect
to see the decline displaced or discontinued, but we see
the rate of decline becoming more shallow. It is going to
be offset by the deep water Gulf, though. Those are the
projects that have been committed to, that have been
under way for the past four or five years, that are just
coming on stream this year. So, we see the deep water
Gulf not only offsetting the shallow Gulf decline, but
providing positive growth.
1:03 p.m.
The Canadian story is an interesting picture. The western
Canadian sedimentary basin is not a mature basin in the
same context as the Lower 48. It still has a lot of
potential. What has happened and what is the result of
the less production we saw last year, was that the focus
has been on shallow gas drilling. That does a couple of
things. It increases your rate of decline, it decreases
your initial rate of production, you get on a treadmill.
You have to drill more and more just to stay in the same
spot. What has happened in the past year is the
significant increase in drilling that has occurred in
western Canada, as well. Last year, while there wasn't a
percentage increase in exploratory activities, just by
the sheer number of wells drilled, there was an increase
in exploratory wells. We're starting to see the impact of
that now. After significant year over year growth in
western Canada throughout the 90's, last year was flat.
This year it was a slight growth for the first four
months. We're now seeing growth in June and July of over
1 BCF/D, which is significant.
What has happened in this year because of the high
prices? Exploratory well licenses are up 23 percent. To
give an example of the significance of that, there is one
discovery, a relatively small area geographically, in
northeast B.C. called Lady Burn (ph). It had zero
production as of the end of the year. It is now producing
500 MCF/D and probably going to 800 BCF/D by the end of
the year.
Are there other areas out there like that? The answer is
probably yes. We expect to see significant growth in
western Canada going forward. And while this graph is
very confusing, what it attempts to show you is the year
over year change from western Canada. As you can see,
from '96 through '99 there was annual growth. Last year
was flat, declining in the first half of the year
[indisc.]. What's really significant is the growth this
year. The growth in the first four months of the year was
probably in the 350 - 400 BCF/D, but it is increasing
dramatically so that the annual average growth for this
year is probably going to be 700 MCF/D. We expect to see
the same, if not more, next year. So, western Canada
should not be counted out.
One of the other interesting aspects of western Canada is
coal bed methane, which is becoming a significant portion
of gas supply in the U.S. It has not, in fact, in Canada.
There's been less than 70 wells drilled for coal bed
methane in all of time. The estimate of coal bed methane
reserves in western Canada alone are double the total
U.S. Lower 48. So, it could substantially be the
replacement for shallow gas drilling in western Canada.
Having put all that together, what it still says though,
is that there is production required from what we call
frontier areas in the future. One of those areas is
Atlantic Canada. We saw Sable Island come on stream at
the end of 1999. It is increasing in production; there
have been new discoveries. We do expect to see growth
from there. The Arctic is another region. This is just a
range of potential gas from various areas. LNG is
probably lower than we would put it if we were to redraw
this graph today.
The Scotian shelf, which is offshore eastern Canada, Nova
Scotia, is currently producing at about 500 MCF/D. We see
that growing to 1 BCF/D by 2005 and 3 BCF/D by 2006. This
could even be higher. Similar structures in geology could
develop in Mexico. All that has been explored to date is
the relatively shallow steep water areas.
One of the areas that used to be a wild card and has now
become significantly more important is LNG. There are
currently four facilities in the Lower 48, all of which
were mothballed until last year. Two of them have come
back on stream; Lake Charles last year; Everett has come
back on; gas discoveries in Trinidad are ramping up; Cove
Point in Elba Island will be coming back on stream next
year. We see not only these facilities running at
capacity, but we see expansion of these facilities such
that we see 3 BCF/D being imported to these four
facilities probably by 2005. The [indisc.] capability
will be probably higher than that, but because of storage
and ship turnaround requirements, 3 BCF/D is probably the
highest sustainable number.
What is really interesting though is if you look at the
world LNG facilities. Not only are there significant and
numerous liquefaction facilities throughout the world,
there are significant plans for more going forward in the
2005 - 2010 as you can see in this graphic. So, we expect
to see the supply side of LNG being very strong post 2005
on a global basis.
What does that mean for the Lower 48 and for the
potential for Arctic gas? Over the course of the winter,
we started seeing more and more starting with monthly,
almost going to weekly, announcements of new projects.
There are at least three for the Baja that are proposed
and a year ago I would have discounted any potential of
LNG gasification facilities on the West Coast. There are
three that are being studied. The ones off California
don't sound as outrageous as you might think because they
are not located onshore. They would be gasified from a
ship that would be tethered to a buoy probably out of
sight and out of mind of California. So, it does have
some feasibility.
The East Coast has an area that's being studied and one
that has a high potential. The Bahamas, Florida, and the
Gulf Coast all have projects that have been put forward.
We see some of these projects going ahead. Even the Alta
Mira one that has been announced in Mexico has an impact
on the Lower 48 because it reduces the amount of gas that
needs to be imported into Mexico from the Lower 48. We
don't see Mexico as exporting gas to the Lower 48
certainly not within a 2010 timeframe and probably not
until 2015. Any facility that is built in Mexico reduces
the requirement for U.S. gas to flow into Mexico thereby
having the same impact as new supply.
To touch on the Canadian side of things, one of the
things I think everyone is finally getting around to
realizing is that Canada is not a market. As I showed you
on the pricing page, the AECO price is lower than Henry
Hub price. There's reason number one - you don't want to
stop that and here's reason number two - Canadian demand
is more than adequately supplied by Canadian supply. In
fact, more than half of the Canadian supply is on export
since the early 1990's. The growth in Canada is going to
continue that. The majority of the growth in production
in Canada is going to export to the U.S. Lower 48. In a
sense, that is the competitor for Arctic gas.
What I wanted to do is get away from sounding like a
pessimist. Here is the opportunity for Arctic gas. What
this shows is absent Arctic gas and absent new LNG, there
is a requirement that starts growing in 2007 increasing
through 2010 for new supply. One of the wild cards is the
demand decrease that we have seen. How much of it will
come back; are we going to see a lower demand growth than
we had anticipated? As I said earlier, the power
generation demand is still there and will still be there.
So, a good portion of it will not go away. What this also
shows though, is new LNG projects and Arctic gas both can
compete for this shortfall between the supply and demand
going forward.
One of the things I find somewhat curious is it doesn't
matter which road you take, roughly two-thirds of the
pipe goes through Canada. Very little attention has been
paid to that aspect. I think that is something that has
not demonstrated its potential as an obstruction in this
process, but may very well occur. Again, on the
optimistic side, we do see potential for Arctic gas in
the three scenarios I described before. That potential
could start as early as 2007, although at this juncture I
think that 2008 is probably the earliest. Under the three
scenarios that we see there is an opportunity for Arctic
gas starting that early. Under the supplier realignment
scenario I described, where we need to see supply from
frontier regions as opposed to conventional U.S. supply
sources, it could be as early as 2008. In that instance,
we would see gas of probably about 2 - 2.5 BCF/D in 2008
growing to 3.5 BCF/D by 2010 and probably peaking at 4
BCF/D by 2015.
In the recession scenario, because of the delay in the
demand growth we would see as a result of that, we would
see Arctic gas being deferred until probably 2009. In
that instance, it would more likely be Mackenzie Delta
gas that would precede Alaskan gas simply because of the
lower need initially and the greater disposition of
people to spend less money on. Even in the case where we
have strong growth in North America meeting demand, we
would still be in need of more frontier gas in Arctic
opportunities starting in 2011. None of these exceed 4
BCF/D by 2015. What that suggests is that there is a
competition going on even among Arctic gas. Depending on
the size of either the Mackenzie Delta or Alaska gas,
there is a limited opportunity. Therefore, I would
suggest that if you saw an Alaskan project of 3 BCF/D
that preceded Mackenzie Delta gas, it would probably
defer that development beyond 2015. That would be of
significant concern to the Canadian government. Again, in
our work, we've looked at the need to meet the demand.
Four BCF/D is probably the highest we could see Arctic
gas without having a significant price impact in the 2015
timeframe. What's also interesting in this graphic is
that there is a growing commonality between Mackenzie
Delta producers and Alaskan gas.
Having suggested that Arctic gas not stop in Alberta, how
does it get to market and what are the markets? As I
showed earlier, a lot of the power generation demand and
requirement is in the West Coast, especially Northwest
California and the Midwest. Those are the two logical
markets for Arctic gas just as they are the logical
markets for Canadian gas. We do not expect that there
will be excess capacity from existing pipelines out of
Canada in any timeframe that Alaskan gas can be brought
on stream. It doesn't mean that there aren't expansion
potentials, but the infrastructure is in place. What I
mean by that is that - this isn't based on the Canadian
exchange rate - what this shows is that for 4 BCF/D of
Arctic gas, you need to build at least 5 BCF/D pipe
capacity out of western Canada. The simple reason for
that is we anticipate the existing pipe infrastructure
being full and at least 1 BCF/D of expansion required for
Canadian supply within a 2010 timeframe. So, within the
same timeframe, you would have to see 5 BCF/D of pipe
filled out of western Canada. You can do that in the
context of the existing infrastructure either by the
cheap expansion, which very well may be gone by the time
Alaskan gas comes on stream, or by some of the more
expansive expansions, all of which will be cheaper than
building a pipe.
In our opinion, it is more likely you will see expansion
of existing structure for a number of different reasons:
lower costs and it goes to multiple markets. Four BCF/D
of Arctic gas to one market is going to have a tremendous
impact. Spread over different markets it's going to have
a lesser impact. One thing I always like to do is tell
people, when you're building pipe, you're building pipe
to capture an opportunity. The bad news is building that
pipe destroys the opportunity you thought you had with
it. What I mean by that is regardless of which market you
build a pipe to, it is going to have a depressing effect
on that market's prices. We don't see that as being
significant or insurmountable.
Having said that, there is a window of opportunity and
competitive forces out there. There are risks in northern
pipeline development. We believe you need a sustainable
price around $3. The project once built could survive a
price probably as low as $2.50, but you're into cost
economics then, but we believe you need a $3 sustainable
price to justify Arctic gas.
Interestingly enough, with technology improvements, LNG
is economical at $3. LNG is also a competitive force
because you can build it in a short timeframe and it has
a smaller environmental footprint. But in favor of Arctic
gas, you have to build the whole bunch of them where you
only have to build one pipeline to fill the need. So
there are pros and cons to both. You need to have
marginal growth; we need to see that power generation
requirement; we need to see some of the manufacturing
come on line, such that the demand is there to justify
the need for the supply. We've talked about the supply
potential in both the Lower 48 and Canada. There still is
expected to be a shortfall between lapsed supply growth
and demand. So, the supply growth is a risk, but it
appears to be there.
The political side is something that I think has not been
given enough attention. Mackenzie development is
important to Canada. It appears that what is happening is
that lines are being drawn in the sand as opposed to
developing cooperation, such that a project of this
magnitude can be built. Two-thirds of the pipe runs
through Canada. The infighting, the delays that could
result from any potential obstacle could be enough to
close the window. While there is likely to be a new
greenfield pipeline to Alberta, it is more likely to be
existing infrastructure expansion and looping beyond that
point.
In the categories of ongoing, once you start
construction, delays can raise your cost. Resource
development is something that needs higher prices to
sustain itself. I talked about coal bed methane, the
deeper drilling in western Canada, as an example.
One of the things that I think has to happen is that
there needs to be risk sharing. This is a project of such
magnitude that it is unlikely any one player will
undertake the risk. It's probably going to take a
cooperative effort between markets, producers, and
pipelines to see this done.
Liquids is an area that is just starting to get some
attention. One of the ways of reducing the cost of a
pipeline is to keep delivering wet gas. What that does is
it reduces your heating value cost of transportation.
Taking the liquids out increases that cost so there is a
potential opportunity there. Once you get to Alberta,
though, a large portion of those liquids need to be
extracted. So, that's probably the last point that
liquids need to be extracted. The reason for that is once
you've [indisc.] the existing infrastructure, the
majority is not capable of handling high liquid content
gas. One of the biggest risks going forward and one of
the reasons we now think 2007 is unlikely and 2008 is
probably more likely, is you need to see some contracts
before anything goes ahead. You need to see a commitment
made before you can use this analogy.
I wanted to just touch on natural gas liquids because it
is a significant factor here. Natural gas liquids are the
next heavier hydrocarbon from methane, which is the prime
component of natural gas. You get ethane, propane and
butane. Those three components need to be at high
pressure to stay in a gaseous state, which is why you
need a high pressure pipeline. Once the pressure is
reduced, propane and butane especially, turns to liquid.
The uses of these components are largely in the
petrochemical industry. Propane you may know from
barbeque use, butane is used in cigarette lighters, but
the majority of the uses are petrochemical. Butane is
also used to enhance the octane of gas. Ethane and
propane are the prime components of ethylene, propylene,
polypropylene and polyethylene that plastics are made of.
To have a viable industry in Alaska would be difficult.
It would also add to the cost hurdle of getting this
project built in a narrow window. Not infeasible, but
with a project in the size of 3 - 4 BCF/D, you would have
enough liquids for one world class ethylene manufacturing
facility. You would have an industry that would be less
than one third the size of existing infrastructure in
Alberta. You would not have the same advantages. The gas
supply isn't on a tidewater. It would have to be piped
there or the liquids would have to be piped there. You do
not have necessarily a price advantage. One of the
reasons Alberta developed an industry was twofold: lower
priced gas and that was largely because of the price
differential between Canada and the U.S. dollar, both of
those significant in the manufacturing and the product
cost for ethylene.
The part I said I wanted to end on was there is still a
window of opportunity. We see prices going forward, being
at or above that threshold with the exception of the
supply realignment and aftershock. Aftershock, you can
see the reason why we don't see Arctic gas coming in
until after 2010 or later. Prices just don't support it.
Supply realignment, you see the price drop in 2007 and
2008 simply because of that factor I mentioned earlier.
You bring gas into the market in less quantities; you
will have a dampening impact on prices. It is not
enduring as long as you continue to have some kind of
growth, however. So, there is an opportunity.
1:26 p.m.
CHAIRMAN TORGERSON asked MR. SMALL to comment on LNG to the Asian
markets.
MR. SMALL responded that was not his area of expertise, but they
see adequate supply at a lower cost than Alaskan LNG being
available until 2015.
SENATOR KELLY asked him to further expand on the 2007 - 2010 window
for Arctic gas to be absorbed into the market.
MR. SMALL replied that 2007 is the earliest from two perspectives,
one being need and the other being the ability to get it in place.
The 2010 timeframe is the outside end of the window, depending on
which scenario you're looking at. He noted, "The offsetting factor,
though, is LNG and how many of the proposed projects we've seen
over the last six months are going to come to fruition. That could
push it out further."
SENATOR KELLY asked him to expand on the Canadian position on their
Mackenzie Delta gas.
MR. SMALL said:
I didn't mean to imply that there is a drive by the
Canadian government to open Mackenzie in any timeframe.
What I meant to suggest is that the Canadian government
should be concerned if there was realistic probability of
Alaskan gas precluding development of the Mackenzie.
SENATOR KELLY asked how long he thought our gas line would preclude
development of that field.
MR. SMALL replied that 4 BCF/D of Alaskan gas would probably push
to beyond 2015. He explained that TAPS approval was predicated on
the Canadian government putting in the Dempster lateral, "So, there
has been a precedent set as far as the Canadians are concerned over
the linkage between the two projects and the development of
Mackenzie."
SENATOR KELLY asked what the development of the Mackenzie would do
to Alaska gas.
MR. SMALL replied that the current plans for Mackenzie Delta gas
range from just under 1 BCF/D to 1.5 BCF/D, so, Mackenzie Delta
development would not preclude Alaskan gas development. He said
they could do both, but there would be a bigger impact on the
pricing here. He pointed out, "If Mackenzie goes first, what that
really means is a lower volume of Alaskan gas or that Alaskan gas
phased in over time would be more probable."
SENATOR KELLY asked if there would be a bigger impact on price or
the window when those competitive forces are at work.
MR. SMALL replied, "A bit of both. If Mackenzie goes first, I think
it has more of an impact on the volume than the window. They have
the same ultimate volume, but the window is longer."
CHAIRMAN TORGERSON said that Arctic gas needs a higher BCF in order
to be economical. "In effect, it could have a slowing effect for
many years - if you need 4 BCF/D out of Alaska and you're supplying
1.5 BCF/D out of Mackenzie."
REPRESENTATIVE PORTER asked if the risk factor in Arctic natural
gas and LNG is about the same.
MR. SMALL answered, "Yes."
REPRESENTATIVE PORTER asked if that is assuming no Asian market,
but a Lower 48 market for either route.
MR. SMALL responded:
LNG for existing facilities is economic in [indisc.].
Arctic gas is probably economic and both routing and
market destination have an impact on it. It is economic
at about $3. So, they are very comfortable in the
threshold needs with LNG probably having a slight nod.
Shipping is one of the biggest cost factors for LNG.
He said that in shipping LNG to the East Coast of the U.S.,
distance is such that you could probably land it for less than $3.
He tried to frame his answer in the context of North American
demand. He didn't know what the price threshold was for the Asian
market.
SENATOR HALFORD asked about the chart on page 33 that shows the
breakdown of ownership on the Mackenzie Delta. He asked what the
alliances were between the companies.
MR. SMALL answered that those were the net acreage positions of
those different companies. There is some sharing of properties. For
instance, BP has partial ownership in Burlington/Chevron/BP.
Alberta Energy is trading its land position in the Mackenzie Delta
with Anadarko, which has land positions in Alaska. He noted,
"You're seeing a lot of consolidation."
SENATOR HALFORD asked if Exxon/Mobil was absent.
MR. SMALL replied that they are absent from the Mackenzie Delta.
Imperial Oil is owned by Exxon/Mobil - Imperial Oil is the Canadian
division of Exxon.
SENATOR HALFORD asked if any others are Exxon/Mobil affiliated.
MR. SMALL answered, "No."
REPRESENTATIVE GREEN asked if Canadian gas came on at 1.5 BCF/D and
Alaskan gas was phased in, whether that would be practical.
MR. SMALL answered, "Yes."
REPRESENTATIVE GREEN asked how "some" gas could be phased in, if
you're talking about economies of scale for a big line.
MR. SMALL said there are a couple of different ways. He explained:
Routing is one way. Construction could be done in the
context of fewer or more compressor stations. It's going
to be difficult to phase it in between a low volume and a
high volume simply because the capital cost doesn't allow
you to do that, but the difference between 3 BCF/D and 4
BCF/D might be feasible. I don't know. I wasn't
suggesting starting ours really low and building up to
the 4 BCF/D. I'm just suggesting that if 4 BCF/D is the
ultimate outcome, it's highly unlikely that the Mackenzie
Delta would start out at 1.5 BCF/D. It would probably
start out at 1 BCF/D building up to 1.5 BCF/D. I would
think the same thing with Alaskan gas. Even with an
ultimate of 4 BCF/D, it probably wouldn't start there
just because putting into service a project of this
magnitude would not be easy. Similar projects have taken
a fair bit of time to phase in. This would be doubling or
tripling the problem of even an alliance project.
CHAIRMAN TORGERSON said a large amount of exploration activity is
going on in the Mackenzie and Alaska is basically ready to go. He
asked how long he thought it would take to produce 1 BCF/D from the
Mackenzie Delta.
MR. SMALL answered that it is conceivable for the Mackenzie Delta
to be on stream in a similar timeframe.
CHAIRMAN TORGERSON said they have read a lot about the Premier of
Canada wanting his cut of our liquids. He asked how much the
Alberta petrochemical industry is in trouble as far as getting
liquids.
MR. SMALL said he didn't think it was a problem and that the
Premier's statement was twofold. He said:
One, the province will not allow itself to be put into a
position where it did have a shortfall of liquids and
two, this is one of the lines in the sand I've talked
about that I think was one of - if you're going to build
a pipeline, you have to talk to us.
He added:
At this point in time, there are more liquids than are
being utilized in Alberta, but that doesn't mean it's not
for industry. As an example, there is a liquids pipeline
that goes to eastern Canada through the Midwest where a
lot of the liquids are dropped off and sold. So, a lot of
the liquids that aren't used for the petrochemical
industry are shipped to both the U.S. and [indisc.]. So,
all of the liquids are utilized. Not all of them are
necessarily utilized in the petrochemical industry.
SENATOR KELLY said that some of this would be predicated on long-
term contracts. He asked how much of the pricing is going to spot
now and whether that will affect the long-range contracts he
perceives will be necessary before the project begins.
MR. SMALL answered:
A high percentage of gas is being bought on the spot
market; prior to this past winter, probably close to 100
percent. This past winter has had a profound impact on
that psychology. Up until last winter, people were even
acquiring pipe space on a spot basis. Hence the price
runup. We've seen power generators, such as Alpine buy
producing companies so that they would have a secured
source of supply. We've seen people bid for pipe capacity
signing [indisc.] contracts. So, there's been a dramatic
reversal within a short space of time from a spot
mentality to a longer term.
Because of the impact on residential consumers in the
Lower 48 and Canada, a lot of the distributors are now
getting approval from the local government regulatory
bodies to buy on spot [indisc.]. That's a whole different
attitude than was prevalent a year ago. I think we're
seeing a shift because of the high prices. Is it a strong
shift? It probably will be in the context of a project of
this magnitude. The buying of reserves by a power
generator, I think, it's the implication that they seem
to need the long-term supply. So, I think it's not as
much of an obstacle as it used to be.
1:42 p.m.
Update of SB 158 and Economic Models
CHAIRMAN TORGERSON thanked Mr. Small for his testimony and said
that last year the legislature passed SB 158, which directed the
Department of Revenue to hire an expert to study the financing
possibilities of a pipeline. He said Commissioner Condon was here
to give an update on that project. Then, Mr. Roger Marks, an
economist with the Department of Revenue would show models of
different projects that have been discussed.
COMMISSIONER WILSON CONDON, Department of Revenue, said SB 158
requires the Department of Revenue to prepare and submit a report
by January 31, 2001 to the Legislature and the Governor addressing
five issues:
1. Should the state take an equity position in the North Slope
gas line project?
2. Should the state participate in financing the project?
3. If yes, under what terms and conditions should it
participate? If the state does participate, will that
participation affect the state's ability to provide services
or negatively affect the state's financial integrity or credit
worthiness?
4. Would state participation assist or damage efforts to
complete and operate the enterprise?
5. Could or should the state make it possible for individual
Alaska residents to become shareholders in the project?
COMMISSIONER CONDON said the legislation waived the competitive
bidding solicitation of his department that would normally apply to
purchasing contractual services. They canvassed a number of people
and have offered contracts to two firms. Mr. David Gray with CH2M
Hill is one. CH2M Hill does a variety of different kinds of
consulting, including energy consulting, and it advises on a number
of different kinds of issues including rate making and financing.
Mr. Gray has participated in projects with AIDEA, AEA, private
firms and public entities in Alaska. The other firm, Petrie
Parkman, is in investment banking, with principal offices in Denver
and Houston. The principal partners in that firm were with First
Boston when they became Credit Suisse First Boston, but formed
their own firm shortly after. Petrie Parkman specializes in the
energy industry and was the investment banker for the United States
government when it sold its interest in the petroleum reserve in
southern California. They were recently investment bankers for half
of Saudi Arabia, which privately financed and developed three gas
infrastructure projects. Petri Parkman is experienced in both
upstream and midstream hydrocarbon projects and transactions.
In preparing the reports, the department looked at the proposals
from 20 years ago when ANGTS was front and center. Many things had
changed and many things remained the same. The studies that were
particularly useful for today's issues were done by Dillon Reading
Company in February 1978 and presented to the legislature. The
legislature commissioned a series of studies in '78 and '79 to be
performed by Heiser at the University of Alaska. Affiliated with
him at the time were Dr. Arlen Tussing and Connie Barlow. That
study was presented to the legislature in three separate volumes,
one in October '78 and two in '79. Finally, three and a half years
later, the state commissioned another study to look at state
financial participation, specifically by Kidder Peabody and
Company. He said he had copies of the studies if they wanted to
look at them.
COMMISSIONER CONDON said the question of state participation is one
of weighing competing considerations. The following reasons have
been advanced for state participation (pros):
1. [Indisc.]
2. If the state participates, it may provide the additional
momentum required to get the project done.
3. The major producers have too many competing opportunities
and the only way we'll get our project done is if we do it
ourselves.
4. Seat at the table arguments: a) If we have a seat at the
table, we will learn information that is important to us and
we'll learn it soon enough to protect our interests than if we
are not at the table; and b) by having a seat at the table,
we would have the leverage to protect special state interests
that are important for us to protect. The incomplete list of
those are: routing decisions, local hire and buying, gas for
communities along the route, potential gas availability for
communities not on the route but which are closer than others
(Southcentral Alaska), gas for industrial development along
the route, the size and pressure configuration of the facility
such that it would enhance the possibility of having chemical
development in Alaska, and gas availability for petrochemical
industry in Alaska.
On the other side of the scale (the cons), COMMISSIONER CONDON
said:
1. State ownership or investment would compromise the main
responsibility for governing, which includes environmental
protection, health and safety protection, economic regulation
and taxation.
2. State investment would concentrate state assets in the oil
and gas industry. When given our dependence upon the industry
anyway, we ought to take any money we have and invest it
somewhere else to diversify the investment portfolio of
Alaskans.
3. Many people feel that governments don't do a particularly
good job of running commercial enterprises. This is generally
thought to be true around the world today and in Alaska, we've
had some particularly bad experiences with government trying
to act as a businessperson.
4. State ownership or participation could easily involve the
project in governmental red tape and institutional tugging and
pulling, like confirming members of the Board and the
Executive Director, the question of how much of the financial
activity would be put under the umbrella of the Executive
Budget Act, and the way the corporation would involve the
enterprise in governmental oversight.
5. Finally, there are those who say the return to a pipeline
would be regulated and, therefore, not really such a great
investment and the state would likely be able to make more by
investing the same amount of money in THE Permanent Fund.
CHAIRMAN TORGERSON asked when the legislature would get a
preliminary report on the interaction of this committee with his
group of clients and how many of these questions he anticipates
will be answered by his consultants' research.
COMMISSIONER CONDON replied that he doesn't anticipate any of the
questions to be answered, but they would help the state evaluate
information it gets, if any, if it has a seat at the table. He said
that they would come to the legislature at its pleasure to report
on progress.
CHAIRMAN TORGERSON said the committee will be meeting monthly
through October, at least. He asked if he had signed the contracts
since he said he "offered" them.
COMMISSIONER CONDON's answer was indiscernible.
REPRESENTATIVE OGAN asked if he thought it would be in the state's
best interest to have a seat at the table.
COMMISSIONER CONDON replied that he would like to wait to answer
that question until they have finished the study. He noted, "In the
oil pipeline the things that were important to know were not
discussed at the table we had a seat at." He said the [department]
was on the Alyeska Owners Committee during discussions about
whether or not the [department] was complying with the electrical
code in the pump stations and what kind of request it was going to
take back to the oil companies to fix it. The person from the state
would be talking about how much money the legislature would
appropriate to fix the electrical shortcomings of the pump station.
The question about economics and return and that sort of thing was
internal in each of the companies who were participating in the
TAPS. He stated:
Given the fact that the gas pipeline is organized very
differently, I don't know whether my judgment would be
the same. By the way, I would make the observation that
if we really wanted a seat at the table on the oil
pipeline today, I'm sure we could persuade Amerada Hess
to sell us their share of that pipeline…They tried to
talk us into buying it.
REPRESENTATIVE GREEN said two pro factors are that we would know
what was being discussed and have lead-time, in which case we could
buy a very small percentage. Having some say in what was happening
would probably require a fairly significant percentage to have any
clout. He asked if Commissioner Condon saw a need to wait before
making that kind of analysis - going small rather than large.
COMMISSIONER CONDON answered:
If folks think that in participating, if we conclude that
there is some validity to the notion that we could affect
a decision and that decision can be affected better if we
take a larger interest, I think that we could tell you
whether or not we think that's true. Certainly, in terms
of state decision making about what to do, it seems it's
unlikely that all of the institutions that have to be
mobilized to do something are going to be ready to do
anything before our main report gets due very early in
the session. We'd be in a position to give you our best
judgment on the trade-offs on that issue in a couple of
months.
CHAIRMAN TORGERSON said he assumed this could lead us into
additional studies.
SENATOR OLSON asked if any other states have participated to this
degree in other natural gas pipelines and, if so, what the result
has been.
COMMISSIONER CONDON said he wasn't aware of any state participation
in a natural gas pipeline but there has been governmental
participation in natural gas distributing companies. There are
other examples of state participation in various kinds of
infrastructural projects throughout North American like airports,
highways and canals.
SENATOR OLSON said those entities were utility-oriented as opposed
to financial investments with considerations that would lead to
business decisions.
COMMISSIONER CONDON said, "There are certainly people who would
argue that a gas pipeline is a special kind of highway that hauls
gas." He doesn't agree, but he thought it would be a valid way for
some people to view it.
REPRESENTATIVE OGAN asked if he is looking at state ownership of a
percentage or the whole project, in reference to the three or four-
spoked hub they were talking about and whether the state should own
the line going into the hub or the whole thing.
COMMISSIONER CONDON replied that they would look at as many
possibilities that they think people might be reasonably interested
in. He didn't think people would be serious about owning the entire
project from Prudhoe Bay to Alberta.
SENATOR OLSON said he wasn't interested in looking at partial
ownership in a segment to Fairbanks or Delta or wherever the hub
would be. He asked if that would be within his scope.
COMMISSIONER CONDON said it would.
REPRESENTATIVE FATE asked what kind of participation he would have
with the firms that are doing the studies based on specific
objective questions, like annualized rate of return of x number of
years, accounting methods, etc. He asked if the Commissioner was
going to be involved in that at all.
COMMISSIONER CONDON said yes, he would be spending a substantial
amount of his time between now and late January working on this
project.
REPRESENTATIVE PORTER asked if Alaska was interested in substantial
or total ownership of the Alaska portion of the route, whether that
would affect the regulatory authority in terms of FERC versus RCA
and would a commitment for investment of the substance have an
effect (and what effect it would have) on the Permanent Fund. He
asked, for example, if it would require a constitutional amendment.
CHAIRMAN TORGERSON said he hoped the Commissioner would generate
some financial principles that could be adopted to any one of the
questions they hear today whether it's a spur line or excess
capacity, particularly in response to question five: Is it even
worth getting into a regulated industry? He also thought he should
be able to establish whether it would make the same or more money
than the Permanent Fund. He thought he should establish that as a
set principle before the state would have ownership in any line. He
thanked the Commissioner for joining the committee and invited Mr.
Roger Marks, Department of Revenue economist, who has been working
with different gas projects that have been suggested and created,
to address the committee.
MR. ROGER MARKS, Economist, Department of Revenue, said he would
present the department's economic model to the committee for the
gas project. He said:
Our model is something that evolved over a period of
years and was originally put together in 1995 looking at
LNG. It has since evolved to looking at gas to liquids
and now it is looking at the North American pipeline
project. It's been reviewed over time by a lot of
entities including the North Slope producers, ARCO, I
don't think Phillips has officially reviewed it yet. ARCO
reviewed it back when we were putting together our report
to the governor in 1997. Foothills has reviewed it; Yukon
Pacific has reviewed it along with their parent company
[indisc.] along with their financial advisors, First
Boston; Dr. Pedro van Meurs' chart group; the Port
Authority and their financial advisors, Taylor DeJongh. I
will say it's a work in progress and continues to be a
work in progress. It's changing and evolving all the
time. It is also a public model; anyone who wants it can
get a copy.
Like all models, there are inputs to it. Basically, the
inputs for this model are cash flows. The main ones are
volumes, prices and costs. The main costs are capital
costs, operating costs and taxes. The state tax system
and federal tax system are modeled into it. The outputs
are financial capability in terms of rate of return, what
the tariffs of cost of service would be, what the
wellhead values would be and what the state revenues
would be. These are in terms of cash flows.
There are a lot of tariff methodologies on the shelf. We
used one, but basically they are all similar in that they
provide a rate of return, cost of service and a rate of
return on the costs. Again, this is a tool. What it does
is explain how numbers work together, how things work
together and you can answer budget questions. If the
input is so, what is the output. It also can evaluate the
economics of different routing options.
MR. MARKS said the numbers he used were not necessarily what the
economics of the project are, but what the economics would be with
specific inputs. The department doesn't claim any expertise
relating the capital costs.
TAPE 01-03, SIDE A
CHAIRMAN TORGERSON asked what kind of interaction he had with
producer groups that they have shared this with.
MR. MARKS replied that the producers reviewed the basic model he
put together for the governor in 1996. In terms of the input, he
said the producers were still studying what they thought the costs
and routing would be.
REPRESENTATIVE GREEN asked if he had run sensitivities to see if
price or cost was the major factor.
MR. MARKS responded that was exactly what he was going to cover
next.
REPRESENTATIVE GREEN asked if the model was set up to run for a
profit making organization. He asked if it could be tweaked so they
could look at various ranges of input from the state's standpoint
where at least the taxes would be different.
2:20 p.m.
MR. MARKS answered that it could be easily modified to show that.
He pointed out some of the sensitivities using a less favorable
scenario - a bare bones project. He used a route along the Alcan to
Alberta, a $3 Chicago gas price and 4 BCF/D. He explained that they
used 4 BCF/D for two reasons. He thought they would need the
additional volume to get the unit cost down to be competitive and,
in terms of the Mackenzie Delta, there may not be enough productive
capacity to build two pipelines at once. So, if there's a niche for
4 BCF/D, it would perhaps come from only one project initially.
MR. MARKS said he used a $1 charge from Alberta to Chicago, which
represents the combination of new and expanded pipeline capacity
there. To create a least favorable scenario, he used a $3 gas price
in Chicago at 4 BCF/D. If you assume that a minimum rate of return
required to make a project economic is 10 percent, he asked himself
what is the highest capital cost you could have. That turned out to
be $14 billion. Given the range of numbers he had seen, $14 billion
was very high, but he wanted to illustrate the sensitivities of
what happens when capital costs go down or prices go up. So, this
model is a useful template to start out with. Of the $14 billion,
$2 billion was for a conditioning plant on the Slope and the other
$12 billion is for the pipeline, itself.
MR. MARKS said there were two other issues, oil losses for one, but
he didn't factor that in nor any of the economics of the gas
liquids mainly because, at this stage of the game, the producers
are trying to figure out exactly what those are. He noted, "We [the
state] frankly have no idea."
MR. MARKS said that the oil losses and the liquids directionally
offset each other, although probably not exactly. The first
sensitivity he used was capital costs and, given that less
favorable scenario [4BCF/D and $3 Chicago gas price], produces a 10
percent rate of return [at least]. He explained that scenario
produces a very low wellhead value of four cents. He used a
representative year of 2015 to see what total state revenue would
be and in that year with this project, it was $398 trillion.
He explained that the overhead was broken down into elements of
state revenue. A big chunk of it was property tax, which is high
because the cost is high. This underscores the point that a
property tax is regressive. So, it is not the best thing for the
project. Another element is royalties and he noted that it was $0
with a wellhead value of five cents. This is because the wellhead
value represents the Chicago price plus the pipeline in Alberta,
plus the pipeline from the conditioning plant and the conditioning
plant. Upstream of the conditioning plant and downstream of the
point of production, which is the point of royalty in taxation, is
the central gas facility where there is a 20 cent processing fee
deduction for royalty. He stated, "Any netback going into the
conditioning plant less than 20 cents will actually negate the
royalty."
SENATOR HALFORD asked if it reduced the tax to the same company
with regards to oil production.
MR. MARKS answered, "There is a 6.4 cent minimum severance tax at
the field. So, you'll see the next column over, the severance taxes
are positive, which reflects that 6.4 cents."
He modeled the state corporate income tax on a separate accounting
basis, simply 9.4 percent of the net income. The state has a
modified apportionment type of it, which reflects a variety of
economics worldwide, impossible to model. So, it will likely not be
9.4 percent.
MR. MARKS said the next column is state corporate income tax and
the pipeline tariffs. Whoever owns the tariff will pay taxes on
their income, which goes to the state. He said the final column is
additional severance tax from the economic limit factor (ELF)
increase. He stated:
For oil, depending on field size, 300 barrels per well
per day are more or less tax-free. For gas, it's 3,000
MCF per well per day tax-free. For oil and gas coming out
of the same well, which is what will happen at Prudhoe
Bay, the tax-free barrels of oil and MCF for gas get pro-
rated. So, as a result of having a gas field, there'll be
less tax-free barrels. So the above taxes will go up.
MR. MARKS went back to the capital cost sensitivities and showed
what happened when one goes from $14 billion to $12 billion leaving
everything else constant. The rate of return goes up to 11.6
percent; the wellhead value goes up to 29 cents and the total state
revenue goes up to $413 million. He pointed out:
There are two reasons the state revenue doesn't go up
that much. One is the property tax. When you decrease
your capital costs, on one hand, you've increased the
wellhead values, which means higher taxes and royalties
and you've increased the property tax.
He said the wellhead value for anything between four cents and 20
cents for the $14 billion essentially has the same severance tax
royalties. He took the committee to the $10 billion scenario. The
rate of return goes up to 13.6 percent, the wellhead value goes to
55 cents, and the total state revenue goes up to $440 million. He
stated:
One interesting thing you can see with the sensitivities
is that for every billion dollars that you change cost,
the wellhead value changes about 13 cents. This suggests
to him that for investors looking at this project, the
gas price is very important. A small change in gas price
has the same effect as a very large change in the capital
costs.
2:32 p.m.
MR. MARKS said on the state revenue side, once you get over 20
cents on the wellhead, every billion dollars in capital costs is
about $13 million instate revenue. He said the reason that number
is so low is that when the capital costs go one way, wellhead
values go down and the property goes up as well. The reverse
happens when the costs go the other way.
He directed the committee to look at overhead number 8, capital
cost sensitivities and reviewed "the same dismal case," $3 gas, a
$14 billion project, 10 percent rate of return, 4 cents at the
wellhead, and $398 in revenue. At a $4 gas price, the rate of
return goes up to 14.6 percent, the wellhead value goes up to 96
cents and the state revenues go up to $684 million. For $5 gas, the
rate of return is 18.3 percent, wellhead value of $1.89 and state
revenue of $1.081 million. He noted that the change in the gas
price of $1 leads to a 92 cent change in the wellhead value.
The reason that is not a dollar-for-dollar change is that there are
some losses along the way in volume of about 8 percent. He said:
If you put 100 MCF into the conditioning plant, you only
get 92 MCF out. You still get only 92 MCF in Chicago, but
have to allocate that over the 100 MCF that went in and
that works out to less than a dollar.
The $1 billion change represents the same change as 13 cents in
price. A one dollar change in market price has the same effect as
$7 billion in capital costs. The change of 50 cents in the market
price has the same effect as $3.5 billion in costs and underscores
the fact that investors are very concerned about the gas market
price.
The final sensitivity beyond capital cost and gas price is volume
sensitivity. He used the same dismal scenario again of 4 BCF/D, $3
gas, 10 percent rate of return, 4 cents wellhead and state revenues
of $398 million. If you increase the volume and keep everything
else constant, and you go from 4 BCF/D to 5 BCF/D, economy of scale
raises the rate of return to 12.3 percent, 40 cents wellhead value
and total state revenues of $532 million; going from 5 BCF/D to 6
BCF/D is 14.5 percent rate of return, 64 cents wellhead value and
state revenues of $695 million.
REPRESENTATIVE GREEN asked why, in going from 4 BCF/D to 5 BCF/D,
he used 36 cents and, when he went up one more billion, he used 24
cents.
MR. MARKS answered because the ratio of total capital costs is $14
billion to the volume is on a percentage and changes those numbers.
"In reality, your costs would go up with your rate of volume."
REPRESENTATIVE OGAN asked if the feasibility of the project was
based more on price to market than routes.
MR. MARKS responded that a small change in gas price will have a
much more profound effect on the project than capital costs.
CHAIRMAN TORGERSON asked if he had put together similar
sensitivities for LNG and PTL.
MR. MARKS said they had done that, but there are limitations using
the models. He noted, "What really matters in terms of measuring
economics is how you can compete with competing projects."
REPRESENTATIVE GREEN asked if these numbers were adjusted for
inflation.
MR. MARKS said he kept inflation out so that, "These are real
numbers."
CHAIRMAN TORGERSON thanked Mr. Marks for his presentation and said
the committee would next hear from the Commissioner of Natural
Resources, Pat Pourchot.
2:50 p.m.
Royalty In-Kind Issues and Pipeline Studies
CHAIRMAN TORGERSON announced that the committee would next hear
from Commissioner Pat Pourchot, who would respond to six questions
posed to him in a letter from the committee.
COMMISSIONER PAT POURCHOT, Department of Natural Resources (DNR),
introduced Bonnie Robson, Deputy Director of DNR's Division of Oil
and Gas, and Kevin Banks, a petroleum market analyst with the
Division of Oil and Gas. He explained they have been responsible
for developing the Request for Proposal (RFP) for the study that is
the subject of one of the questions posed by the committee.
Commissioner Pourchot noted he distributed a handout to committee
members that covers DNR's primary objectives. He said he would
discuss some of DNR's broad objectives and then respond to the
questions.
COMMISSIONER POURCHOT said the administration's work on this issue
cuts across both his department and the Department of Revenue.
They are both looking at maximizing income to the state to benefit
Alaska citizens when looking at the various aspects of a gas
pipeline project. Their first objective has been to look at how
Alaska can maximize its royalty impact value and how that will
affect tariffs, selling prices, field costs, conditioning costs and
how gas may or may not affect oil revenue loss. In addition, fuel
dynamic interaction might take place under different scenarios.
DNR is vitally interested in all of those topics and is trying to
learn as much as possible about them. Regarding the benefit to the
people of Alaska, the second objective, DNR is looking at in-state
jobs and at state uses of natural gas. The third main objective is
to maximize benefits to Alaska businesses and businesses operating
in Alaska and how access may or may not occur under different
scenarios. He pointed out those objectives are not mutually
exclusive.
COMMISSIONER POURCHOT stated that the answers to some of the
questions are not as simple as "yes" or "no" because ultimately,
DNR is keenly interested in developing a common project. Some
things might be traded so that maximizing one aspect could be at
the expense of another. At some point the viability of the project
will be affected. He briefly covered the "tools" that will be
necessary to accomplish DNR's objectives, such as legislation, and
noted that both federal and state agencies will be involved in
studies and permitting. In terms of the permitting, a whole
conglomerate of entities will be involved; DNR is trying to bring
some of those entities together for some of those tasks.
COMMISSIONER POURCHOT said the first question he was asked by the
committee concerned the state's rights to take gas in-kind for
major gas sales, commonly known as overlifting, or alternatively,
the state's right to defer taking royalty gas, commonly called
underlifting. There is no expressed ability in statute or
regulation or in the terms of any lease agreement that gives Alaska
the right to overlift or underlift Alaska's royalty gas in advance
of gas sales. However, there are ways of accomplishing that, most
notably, if Alaska has implied that if there is a viable market,
that producers under the terms of the lease sales shall market that
gas. If, for example, there was a proposal to seek as-is gas right
off of the North Slope at some market rate and there was a viable
purchaser at a credible market rate, there is an obligation to
market that gas.
Alternatively, if there was a viable proposal with a sensible
market price, the state should work cooperatively with the
producers to overlift its royalty gas on the Slope, a negotiated
process.
The Alaska Lands Act had a provision many years ago that gave the
DNR commissioner authority to negotiate with companies to underlift
oil. It was specifically mentioned that there was a strategy prior
to bargaining that allowed DNR to affect the routing of the oil
pipeline. He believes the likelihood of success of such a strategy
is debatable. The legislature specifically put in that element, but
it did not grant a lateral authority to negotiate with the
producers.
CHAIRMAN TORGERSON asked if the negotiations with producers fail,
the state would have no right to assert a claim to overlift or
underlift.
COMMISSIONER POURCHOT said he believes that is correct, and that
DNR deals with the companies on so many issues, such as development
plans, exploration plans, lease terms, participating areas, etc.,
that overall it is their desire to cooperate and to negotiate in
good faith on a variety of issues. He said he believes there is a
climate of cooperation.
CHAIRMAN TORGERSON asked Commissioner Pourchot if he feels using a
legislative route would constitute a breach of contract with the
existing lease sales.
COMMISSIONER POURCHOT replied that in the event of a breach of
contract, the state has no lateral expressed right. That could
potentially lead to legal action.
COMMISSIONER POURCHOT said the second question the committee posed
was in relation to the state's right to control access to the
pipeline for potential users that come later. He acknowledged that
he deferred part of the answer to the RCA and to the FERC.
However, in the area of state regulation of pipelines, there is a
big body of law surrounding federal preemption in this arena. The
state has several options. It can go through the FERC process. It
could make recommendations for how an open season will be
conducted. Alaska statutes and permitting procedures could
conceivably be tried but, in the end, the state can be preempted by
federal law or federal regulatory action. Conversely, federal law
changes.
COMMISSIONER POURCHOT said DNR is very concerned about open season
and that there be a fair nomination process both initially as well
as ten years down the line when a producer might discover large gas
reserves. DNR is also concerned about the possibility of a process
that barely addresses a potential looping expansion and how costs
are allocated and how access to facilities are handled. DNR is
concerned about establishing a process that is as open and fair as
possible. More access for potential interests means more value
because it will create an incentive for further exploration and
production.
CHAIRMAN TORGERSON asked the commissioner if he is continuing to
seek legal advice on those issues and what process he is using to
give the committee final answers prior to next session.
COMMISSIONER POURCHOT said DNR has received additional legal advice
but he has not asked for a formal legal opinion. The question is
whether the committee wants the information in black and white. He
could request that the advice he has received be formalized and
made final and available soon. Regarding whether he is continuing
to seek legal advice, he would have to reframe some of his
questions to the Department of Law and he has not done that.
CHAIRMAN TORGERSON said the open season question is one of the
largest issues facing the state right now. He asked:
If the producers build a 4 BCF line and won't let anybody
else in there for the next 20 years, where does that
leave any oil and gas sales on the North Slope - or gas
sales. To me, you can't sell anything up there. Who
would buy acreage or, if they did, it wouldn't be at any
good price for the State of Alaska.
COMMISSIONER POURCHOT said there are a couple of options. DNR has
asked that same question of economists and believes it always pays
to have more people participate in a project of this type because
of the per volume cost of the line and, presumably, once the
upfront costs of the initial line are incurred, the cost of running
a second parallel line for another volume of gas, if necessary,
would be cheaper. Pressurization can move significantly more gas
and provide for a significant increase in capacity. The producers'
argument is that if somebody comes with more gas, they would
welcome that because it would reduce the per volume cost of gas in
the line.
CHAIRMAN TORGERSON said he appreciated that statement but he wants
some assurance that will happen. He expressed concern that the
opposite could happen so, if the producers let another producer in,
the market price could be affected quite a bit. He pointed out
this situation is different from Calgary or other places in which
10,000 wells are being drilled each year. Alaska has a very
controlled resource going into a very controlled line that has the
potential of having other players involved or left out for a number
of years. He said he hopes that DNR continues its legal analysis
of that question and he said he will recommend that the legislature
do some of that on its own.
COMMISSIONER POURCHOT stated the third question posed by the
committee was in regard to DNR's support for common carrier versus
contract carriage of a pipeline. DNR would prefer a common carrier
status for all leases because it would be easier to expand the line
for later gas reserve discoveries. Again, he said that DNR is
concerned that there be a process for expanding the line. The
Alaska Natural Gas Act provided for contract carriage and is a
matter of federal law, the argument being that contract carriage
provided the kind of arrangement necessary to finance a project.
Most gas pipelines in the United States are contract carriage but,
as Chairman Torgerson pointed out, shipping through different
pipelines will not be an option on the North Slope.
COMMISSIONER POURCHOT, in response to the fourth question, said
DNR obviously favors open seasons for both initial nomination and
for subsequent nominations, as well as for additional capacity to
take on volumes of gas.
COMMISSIONER POURCHOT said the next question [number 5] raises
another element - how to deal with the export [indisc.] capacity
volume for coming years. That question is in relation to the
committee's question about agreements to backstop non-pipeline
owner/producers firm capacity obligation with the state's royalty
in-kind (RIK) gas. DNR has been approached by companies who are
not producers, but hope to be producers or owners of gas in the
future. They are not in a position now to make a firm commitment
for nomination and do not know whether or not they will find gas,
but they do not want to be locked out. The committee asked whether
the state would be willing to take their gas in-kind at a later
date and have those companies make a nomination for a quantity of
gas but, if they did not find gas or could not meet that commitment
to ship that volume of gas, they want the state to take that gas
in-kind and sell it to the people with the reserved space in the
pipeline. DNR is open to that notion. DNR wants to protect its
ability to take its gas in-value or take it in-kind and be able to
use it for in-state purposes. The gas would still be shipped out,
but there may be some economic value. The state could get a
premium for it; it could get a tariff component for that off of the
state's netback. It is a way of meeting the goals of keeping the
values high on the North Slope.
COMMISSIONER POURCHOT said it would be part of the whole mix. One
wouldn't presumably over commit if you only had 500 MCF per day.
TAPE 01-3, SIDE B
CHAIRMAN TORGERSON said he is not sure that it would be necessary
if the open season question on additional access to the line is
solved. He said he posed the question to find out whether the
commissioner would be willing to consider it. He repeated if the
open season is early, the state may not be prepared to respond.
COMMISSIONER POURCHOT said the next question posed by the committee
asked about the current status of discussions with Netricity. He
said DNR took the Legislature's resolution [HCR 17] on this matter
seriously. Not only is the proposal intriguing, it is a good focus
for the larger question of state in-kind gas. DNR is in discussions
with Netricity. He noted he provided committee members with
specific information about Netricity that DNR is looking at,
regarding the dollar amount if the state accepted Netricity's
proposal of 36 cents per cubic foot. He noted the worksheet only
contains Netricity's initial offer. In his opinion, that offer
does not appear to be in the state's best interest, particularly
when the state's cost of extracting gas on the oil grounds is
unknown. There will be some cost associated, if it is computed
back in terms of a gas price. It could amount to 10 or 20 cents
but, beyond that, the amount could get to zero quickly on this kind
of a proposal.
CHAIRMAN TORGERSON asked if DNR is still in contact with the
principals of Netricity.
COMMISSIONER POURCHOT said DNR is participating in on-going
negotiations with Netricity. He then said DNR would like to talk
about its study for the component of this evaluation of the values
associated with gas. He noted that Netricity has approached
producers also. DNR is in disagreement with Netricity on some
issues. Netricity has a methodology for how it arrived at 36
cents. It used a fairly aggressive discounting schedule.
Obviously, there is some value in selling gas in advance of a gas
sale that might be seven years down the line, but DNR believes the
discounting would be less than 18 years' worth; it might be four to
seven years, which would change the value considerably.
3:26 p.m.
COMMISSIONER POURCHOT stated that the last question Chairman
Torgerson asked was in regard to ongoing gas pipeline studies. DNR
has proposed several different studies. He believes DNR has
figured out how to pay for the in-state demand study and, pending
the upcoming Legislative Budget and Audit (LBA) meeting, he will
know more about how and whether the other studies will be funded.
DNR has published a request for proposals (RFP) for the in-state
demand study and the deadline is July 23. DNR is hoping for a
completion date in early or mid-November. The study is designed to
determine at what price North Slope gas can be delivered to
different regions of the state; how can it be used in-state
relative to the price of other fuels; and what new uses might arise
if natural gas were more readily available from the North Slope.
Other questions regard where a pipeline might go and how much it
will cost to access gas in Southcentral versus Fairbanks. The
study is designed to try to get a better handle on the demand for
in-state gas, which directly relates to a price and route.
COMMISSIONER POURCHOT informed the committee that a value study is
due back next week. It will review various factors that will
impact netback values of North Slope gas and will identify pricing
policies and practices used elsewhere. The goal is to determine
methodologies that provide the most transparent ways of calculating
netback value and transportation costs. DNR has had a lot of
experience with oil and has spent a lot of time litigating how
costs should be calculated to arrive at a netback. Their
settlement agreements over the years have made oil netback
calculations easier and more clear.
DNR wants to maximize the state's resources and avoid more
litigation, COMMISSIONER POURCHOT said, and hopes to avoid having a
complex system of calculating netback prices. DNR is also looking
at a larger supply structure and trying to assess the supply of
other kinds of gas, not just Prudhoe Bay gas, and how those might
come into play. Obviously, transportation makes other things more
economical. DNR hopes to do an in-house effort and compile known
information describing it by different kinds of gas sources and
making assumptions relative to proximity to transportation.
COMMISSIONER POURCHOT said that DNR has proposed a component of a
reservoir study using the economics of the impact of gas extraction
on Alaska's oil reserves, primarily at Prudhoe Bay. AOGCC has the
major responsibility for this and would be the lead agency. He
noted that funding issues in regard to that study have not been
resolved because of the way the budget items were structured, the
issue being whether the AOGCC has the ability to reimburse for
those costs. Some of that will be discussed at the upcoming LBA
meeting. DNR would not do its component of that without the Alaska
Oil and Gas Conservation Commission (AOGCC) study, but DNR views
that study as very important. It will provide the information the
state needs to have going into negotiations. There is information,
but DNR needs an evaluation so that the state's own views can be
represented. He offered to answer questions.
CHAIRMAN TORGERSON commented that regarding the LBA meeting, he
will probably be less than friendly towards the Commissioner's
request until a method is accomplished in which the Legislature and
administration work hand-in-hand on this project instead of running
parallel courses. He noted he has had that conversation with the
commissioner and with other department and division heads. He said
he has recommended to the Chairman of Legislative Council that the
Council fund many of those projects so that the information can
flow to the committee. He then announced the committee would take
a short recess.
3:35 p.m.
Right-of-Way Pipeline Applications
CHAIRMAN TORGERSON introduced John Goll, Alaska Regional Director
of U.S. Mineral Management, and Jerry Brossia, the federal pipeline
coordinator with the Pipeline Office.
MR. JOHN GOLL, Regional Director for the Minerals Management
Service (MMS), U.S. Department of the Interior, said he would
present information on the right-of-way for an offshore route and
that Mr. Brossia would answer questions afterward in regard to
onshore responsibilities of the Department of the Interior.
MR. GOLL gave the following testimony.
I know that the offshore route is not the popular route.
I want to emphasize that we, the Department of the
Interior, are new to a lot of [indisc.]. It is not our
job to propose or advocate the selection of the route.
However, we are required to review any application that
might come before us. So, I will try to outline the
right-of-way process that we would use for an offshore
pipeline through federal waters, but I would also like to
take this opportunity to make some brief remarks on
future gas supplies from the perspective of our agency.
Our agency is one that is deeply involved in the nation's
energy production picture. I think it might complement
some of the things that you heard a little bit earlier
this afternoon.
Natural gas resources, including those in the Arctic, are
very significant and a visible part of the Department of
the Interior's strategy for managing U.S. energy
resources. So, the issue of getting an Alaska gas
pipeline permitted and constructed is a challenge for you
and for us and an opportunity.
First of all, I would like [indisc.] the Minerals
Management Service and who we are. The Minerals
Management Service, also known as MMS, is an agency in
the U.S. Department of the Interior. We are responsible
for managing the mineral resources on U.S. offshore lands
under the jurisdiction of the federal government. Our
jurisdiction covers nearly 1.7 billion acres of the
submerged lands called the federal Outer Continental
Shelf, or the OCS. This includes about 1 billion acres
offshore Alaska.
Along with managing the leasing of OCS minerals resources
and estimating the amounts of resources that may be
there, our responsibilities include regulating offshore
operations of the oil and gas industry, helping to ensure
worker safety and protecting the environment. We have a
robust technical research program, which includes
research on pipelines, drilling safety, oil spill
response, and other topics and we are also responsible
for collection of the revenues that are generated by the
leasing rights to produce the minerals owned by the
United States and individual Indians and tribes, both
onshore and offshore, and for distributing the funds to
the U.S. Treasury, to the states, and to other accounts.
For example, the CARA bills are totally funded from the
revenue that we generate on the OCS.
Today the OCS, primarily in the Gulf of Mexico, accounts
for 25 percent of the nation's oil production and 27
percent of its natural gas production. Our agency
provides oversight there on about 31,000 miles of seabed
pipeline. And, over 50 percent of remaining oil and gas
resources in the U.S. are located on the OCS.
I would like briefly to review first what is going on in
the Lower 48, part of it, again, to complement what was
said a little bit earlier because this, again, can
influence some of the issues that you're facing with
regard to the supply and demand in the future.
As I mentioned, the Gulf of Mexico accounts for about 25
percent of the nation's oil and gas production. On the
Gulf, activity is going gangbusters with continued
discoveries in the traditional shallow waters and the
step out into the deeper waters of the Gulf, as you heard
earlier. The fact is some of the shallow waters will be
more likely to produce the gas in the future than the
deeper because it will take a little bit longer to do the
production from the deep water. So, we'll be talking
beyond what we have here on this chart, most likely
before the deep water can start taking effect. The
natural gas potential in the Gulf remains very high -
around 190 TCF. The present gas production has been
about 5 TCF, but the future, as I mentioned, is with all
predictions a little uncertain as I've noted on the chart
depending on the continuing discoveries, trying to
stabilize the production there and getting projects under
production to shore which, again, takes longer. So, we
really do see in the Gulf things staying pretty much even
this side of the Gulf - not tremendous rises as some
people maybe have noted.
Looking at the rest of the Lower 48, the picture is not
as bright. Most of the Lower 48 of the Outer Continental
Shelf is off limits. In the Atlantic, there is very
likely prolific gas, with estimates ranging from 24 to 34
TCF. The extension of discoveries off Southeastern
Canada most likely go down the eastern seaboard. The
Eastern Gulf of Mexico's border opposes development off
the coast and we just scaled back a proposed sale in the
Gulf in the Eastern Gulf of Mexico. On there, the mean
estimate is about 12 TCF. On the West Coast, gas areas
are likely off of Washington, Oregon, and Northern
California with a range of 15 to 23 TCF. Some production
does continue off California, primarily oil. Leasing is
unlikely in any of these offshore areas in the
foreseeable future, although groups such as our national
OCS policy committee is trying to get the discussion
going by simply thinking about what resources these areas
may contain. But, right now most of these states do not
want production off of their coast even though it may
benefit [indisc.- coughing] the localities there. It is
noted in the national energy report, much of the Rockies
have been off limits or with great restrictions and there
the estimate is around 137 BCFs - again off limits.
The point of this overview is that the nation has not
been exploring, much less producing, in many areas with
good potential and this does give Alaska a step up with
known reserves. We see great potential offshore of
Alaska for natural gas. This is the chart of the
potential on the Outer Continental Shelf. These are
[indisc.] undiscovered and eventually recoverable so they
do not include economics. But the Chukchi and Beaufort
Seas look very promising, as noted on the chart, with
estimates ranging on the Chukchi from 14 to 154 TCF and,
in the Beaufort, perhaps as high as up to 163 TCF, and
likewise, also favorable for oil. But we are a number of
years away for gas development to proceed there. Of
course more exploration would be needed and the
infrastructure developed, but the message is there can be
plenty of gas in Northern Alaska to sustain a pipeline,
or pipelines, well into the future if we all want to
pursue the [indisc.] chance and develop those resources.
Just a few other side comments on the Alaska offshore -
maybe not totally on the North Slope but.... In the
areas off of Alaska's west coast, from the Chukchi down
into the Bering Sea, we have indications for good gas
potential that could be used for communities in those
areas, especially if onshore sources of gas or some other
alternative energy that is being looked for there, are
not found or available. The economics, of course, may be
the limiting factor but the potential is there off the
west coast. Also for future reference, and maybe this is
dreaming more wide into the future, there is the
potential for significant quantities of the presently
unconventional resource of gas hybrids. Estimates of 590
TCF onshore and, what I would call an unbelievable
amount, 170,000 TCF offshore around the state. That's
primarily up in the Beaufort and even along the Shelf
break south of the Aleutians. This is probably not for
us but maybe for our children or grandchildren or
something, maybe to look forward to in the future with
regard to hybrid development. But there are, of course,
hybrids on the North Slope that may be a little bit
easier in the nearer future.
But then again, the message remains that the energy
sources are likely there if we want to look for them and
if we want to use them.
Let me go into some of the regulatory authorities again
if an offshore route were ultimately selected. If the
northern offshore pipeline route were selected, the MMS
has specific authorities to grant pipeline rights-of-way
and maybe also to approve oil spill contingency plans.
Our right-of-way authorities are established under the
Outer Continental Shelf Lands Act, the OCSLA. Other than
the right-of-way permits, MMS exercises approval and
oversight responsibilities for the installation,
operation, maintenance and abandonment of the pipeline.
An oil spill contingency plan may also be required if the
pipeline were carrying naturally occurring condensate or
if condensate is injected into the pipeline. MMS
contingency plan authorities are established under the
OCS Lands Act and the Oil Pollution Act of 1990 and would
apply to all segments of an offshore pipeline, whether
around the federal OCS or the state's submerged lands.
In the event there is the potential for a spill,
additional demonstration of financial responsibility will
be required under the Oil Pollution Act.
REPRESENTATIVE GREEN asked if Mr. Goll was referring to condensate
as opposed to natural gas liquid.
MR. GOLL said that is correct, but clarified that these provisions
would likely come into play for any liquids going into the pipeline
if there was potential for a spill. He then continued his
presentation.
The MMS would share management responsibilities for this
pipeline with the Federal Energy Regulatory Commission,
the U.S. Department of Transportation's Office of
Pipeline Safety, and the State of Alaska's Pipeline
Coordinator's Office and with our Canadian counterparts
also. MMS is also a new member of the State of Alaska-
Federal Joint Pipeline Office. At this point, I'd like
to mention that the Department of Energy and the national
energy report - there was a provision in there for the
Department of Energy to pool together the federal
agencies and recently, over the last two or three weeks,
the Department of Energy has pooled together themselves,
the U.S. Department of State, the Department of the
Interior with representation from our agency, Minerals
Management Service, and from the Bureau of Land
Management, and the Federal Energy Regulatory Commission
to get together again, to investigate ways to expedite
permitting for a gas pipeline and then to make
recommendations to Congress and the President on how to
proceed. So, that work will be going on over the next
couple of months and I believe they do plan a trip up
here, perhaps in September. I'll make sure that you are
informed. That would be the regulatory authority. Other
agencies would be involved in the project depending on
the proposal and issues, many in some indirect ways with
regard to some other laws.
MMS has regulations and guidance that outline the
information requirements in detail for right-of-way
applications. First we encourage the pipeline permittee
to collect information prior to submitting a request for
a permit. This allows important geotechnical,
geophysical, archeological and biological information to
be available earlier in the process. The producers'
group plans to collect such information this summer as
part of its study of the two routes. MMS will do a full
safety and engineering design review, including
consideration of site-specific issues using data from a
survey and other sources. We would proceed doing this
jointly with the State Pipeline Coordinator's Office and
in coordination with the U.S. Department of
Transportation. The MMS will also provide an opportunity
for public comment and would conduct an environmental
analysis under the provisions of the National
Environmental Policy Act. In the event of an
environmental impact statement, which is very likely for
these pipeline routes, a lead federal agency would be
designated. Which agency has the lead would depend on
the scope and the nature of the specific proposal and
relative responsibility of the various agencies. In the
case of the over-the-top pipeline proposal, MMS, the U.S.
Department of Transportation, the U.S. Army Corps of
Engineers or FERC are all possible lead agencies for the
EIS.
I can give an example in the Gulf of Mexico that we've
just completed. We worked with the federal - with FERC
on the Gulf Stream gas pipeline that ran from Mobile Bay
to Tampa Bay, across the Gulf. FERC was the lead of
contracting the EIS, with post-coordination with our
staff. Our staff within MMS did a full engineering
review that considered the specific route and
environmental issues and technical issues and it was also
doing inspections as the pipeline was being constructed.
The project would also be subject to coastal consistency
review, with the State of Alaska's Coastal Management
Program. [Indisc.] consultations would be required with
the National Marine Fisheries Service and the U.S. Fish
and Wildlife Service. We foresee a number of
environmental and technical considerations for an
offshore pipeline and I'm sure there's more. But, the
paramount environmental consideration is the bowhead
whale and associated subsistence hunting activities that
occur during the open water periods across the Beaufort
Sea. One would need to ensure that construction or
operation of a pipeline would not unreasonably interfere
with the whales or subsistence. Seasonal broken ice
conditions in the fall and spring will also pose
challenges for construction, maintenance and repair.
Permafrost, ice gauging and strudlescour (ph) are other
design considerations. Metering and lease protection
would be of concern even though this is not an oil
pipeline. Strudlescour can be at spring break-up. When
the water is starting to come out of the rivers, it will
go across the ice and it finds a hole; it will go down
like your toilet flushes and it essentially moves gravel
or whatever the seabed is. Why take that into
consideration when you [indisc.] a pipe?
One of the main efforts that we or any lead in this
project if, really, any of these projects go forward, but
of course we're talking here about the over-the-top
route, would be consult with all concerned parties, such
as the list that I have here. We and other agencies
would need to work closely with the many stakeholders to
make sure that their concerns are addressed in our
decision, but we would also want to ensure that the
process that we were working under was done in a timely
way.
So, in conclusion, Alaska does have significant untapped
natural gas resources that can go a long way to serving
the nation's need for natural gas in the coming decade
and well beyond. It may be a step ahead of other areas
of the U.S. that have good potential, but again, the
country [has] not developed that way. The right-of-way
procedures do exist for offshore permitting. But, first
I'll emphasize again that the route is not ours to
propose or advocate and, regardless of the route that is
ultimately chosen we, within the Department of the
Interior, being MMS and I think I can speak for BLM, that
we would work where we can to assist through whatever
route is decided on. The challenges that face us with
getting these resources out of the Arctic while ensuring
that it is done safely and with maximum protection of the
environment. Also, within the department, again because
of the importance of Alaska, I think it's - of course you
are all very aware that Secretary Norton went to the
trouble of having two special representatives for Alaska
to give views to people back in Washington and here and
to be her eyes and ears and to provide advice and
counsel. So, you'll also be able to work with Senator
Drue Pearce and Cam Toohey as these projects go forward.
So, the wrap up. If you're interested in more
information, of course we can provide it. We also have a
web page that goes into much more detail in regard to our
rules, technical research and environmental research that
we're doing and other information about MMS. Thank you
very much for your time. I'm here to answer questions or
if Jerry would like to ....
CHAIRMAN TORGERSON asked Mr. Brossia if he would like to add to Mr.
Goll's presentation.
3:54 p.m.
MR. JERRY BROSSIA introduced himself as the representative to the
Secretary of the Department of Interior, located in the Bureau of
Land Management, and said he will administer the TransAlaska
pipeline, as well as the Trans-Alaska gas system right-of-way and
the ANGTS right-of-way.
MR. BROSSIA made the following comments on the status of rights-of
way.
Both the ANGTS route and the TAGS route have federal
rights-of-way in place. They also have a couple other
important documents in place. In order to get those
federal rights-of-way, you're essentially, as John
mentioned, going through the National Environmental
Policy Act or what will become the EIS process. Both of
those projects have EISs in place. They have another
significant document in place, they have under the Alaska
Natural Gas Act, they have a presidential claim. And
that presidential claim [indisc.] for both projects so
those are significant documents. The right-of-way that
BLM issued to the TAGS project required a presidential
decision - again, the process.
The third project that we recently started to look at,
and we're not fully geared up to [indisc.] but the
owners, Phillips, BP and Exxon's gas project. We just
recently started meeting with those folks. They would be
required to go through a pretty similar process to what
John outlined, with the exception that instead of the
Outer Continental Shelf laws, we would be using the
Minerals Leasing Act of 1920. Again, BLM would - once we
receive an application that would trigger the legal
process it would probably require an EIS. Again, as was
discussed, any new project would also look at some kind
of a permit with FERC. The other two projects have the
usual permits from FERC. The Corps of Engineers would
also want to be involved and we would also be involved
with the state as far as issuing a right-of-way. When
these projects come through the Joint Pipeline Office, in
the past, we've looked at it as one process with many
steps. In this case, the two primary drivers for a new
project, obviously for the [indisc.] as well as the
right-of-way, both again would trigger the EIS process,
both would be coordinated with the state right-of-way
process as well as the CZM being done by the Corps. I
don't have prepared remarks but I am willing to take
questions on how we've worked on these projects in the
past.
3:57 p.m.
CHAIRMAN TORGERSON asked whether either department has geared up
for pipeline applications by hiring staff or doing studies.
MR. BROSSIA said that both the BLM and MMS have policy quotes just
coming out of Washington, D.C. They have formed several task
forces to look at various aspects of the project. While the
Department of Interior issues the right-of-way for the ANGTS
project and BLM was the lead on the TAGS project, the Office of the
Federal Inspector may or may not be resurrected as the overall lead
agency on the ANGTS project. That is being discussed now in
Washington, D.C.
Locally, BLM has been looking at the status of each project and
developing a project RIK plan, a project legend, a project
schedule, looking at agreements with the State of Alaska and other
federal agencies and developing a budget and organizational plan.
BLM has met with the owners three or four times and discussed their
need to do field studies in preparation for EIS and right-of-way
work. Some of BLM's district offices have issued permits for
stream studies. BLM is in a very preliminary stage of looking at
this project.
MR. BROSSIA said if BLM is chosen as the lead agency on a new
project or on the ANGTS, it would use the joint pipeline model,
which has been fairly effective over the last 12 years. BLM would
probably spin off of [indisc.] and work with the state on that.
However, they have not finalized any plans.
4:00 p.m.
MR.GOLL said, likewise, the MMS has not hired anyone at this point.
MMS met with the producers who wanted to know what kind of
information they would need to collect for the surveys he
mentioned. They plan to do the surveys this summer and need to
collect information for alternative plans. MMS does have a
representative on the Department of Energy group but, overall, they
have been very low-key and will continue that way until the
direction is decided upon. He noted the MMS has a process so that
several models could be used and can foresee taking the lead on the
EIS.
CHAIRMAN TORGERSON asked if one of the producer groups filed under
the Natural Gas Act or anything besides ANGTS, whether BLM would
require a presidential decision before proceeding with that
application.
MR. BROSSIA said that has been the past practice. That was a
condition for the right-of-way permit for TAGS. He would
recommend it.
CHAIRMAN TORGERSON asked about an offshore application.
MR. GOLL said he was not sure. That is one thing the DOE group
could look at. He guessed the answer would be no.
CHAIRMAN TORGERSON asked if the original 1977 presidential decision
to deny the ANWR over-the-top route that was onshore would hold for
the offshore route, or whether the offshore route substantially
differs enough that the original decision would not apply.
MR. GOLL said he did not know.
4:02 p.m.
REPRESENTATIVE OGAN referred to an earlier slide shown by Mr. Goll
about limitations in the Lower 48. He added the numbers and
calculated that 188 to 206 TCF are off limits. He asked what
percentage that is in comparison to the total reserves.
MR. GOLL explained those are not reserves in the sense of being
discovered, they are potential.
REPRESENTATIVE OGAN asked if about one-half of it is off-limits.
MR. GOLL said that probably 20 to 25 percent is off limit. He said
the point he was trying to make is that the areas that need gas,
particularly the East Coast, are not looking to produce local gas.
Alaska gas will probably end up in the Midwest and West, but right
now some of that could be heading toward the East Coast where there
is a great peak. Likewise, there is gas off of the west coast, but
they are not looking to use it. He added that it would be easier
to produce locally, but many areas of the country are not going in
that direction right now.
REPRESENTATIVE OGAN asked if that gas is off limits because
drilling would raise environmental concerns. He noted gas is
probably the safest thing to drill.
MR. GOLL said that is correct, but people are concerned about oil
spills on beaches.
CHAIRMAN TORGERSON thanked Mr. Goll and Mr. Brossia and asked Mr.
Britt to testify.
4:05 p.m.
MR. BILL BRITT, Gas Pipeline Coordinator, Department of Natural
Resources, informed committee members that he distributed a packet
of information, including his written testimony. He gave the
following synopsis of that testimony.
There are three modes available to move gas out of Alaska:
pressurized natural gas, LNG, and gas to liquids. Four routes are
being discussed: Prudhoe Bay to Prince William Sound; Prudhoe Bay
to Kenai; the highway route; and the over-the-top route. He counts
at least eight projects with groups of proponents:
· Yukon Pacific TAGS project;
· ANGTS route;
· A producer group of North Slope natural gas producers (BP,
Phillips, Exxon Mobil);
· A sponsor group led by Phillips that includes Foothills and
BP;
· The Alaska Gasline Port Authority;
· The Cook Inlet pipeline terminus route;
· The Municipal Energy Resource Group (MERG), which advocates
the over-the-top route;
· BP gas-to-liquids plant.
TAPE 01-04, SIDE A
MR. BRITT emphasized that neither routes nor modes are being
exclusively considered and that more than one project is certainly
possible. Two of the pipeline projects have received right-of-way
and other permits from both federal and state agencies. Foothills
has received various permits for the ANGTS route. BLM completed an
EIS for the TAGS route and granted Yukon Pacific a right-of-way in
1988. The FERC EIS on the Anderson Bay terminal was completed, the
presidential finding and export license is in place and a
conditional state right-of-way was issued and renewed. He noted
that Section 2 of the conditional lease pertains to the
requirements of the conditional state right-of-way.
For the ANGTS route, BLM completed an EIS and granted a right-of-
way in Alaska in 1980. A treaty between the United States and
Canada was signed in 1978, which sanctions the project, and
Canadian permits and approvals are in place. The state right-of-
way process was begun, but is not completed.
The state right-of-way process is described in the Right-of-Way
Leasing Act (AS 38.35). The steps are:
· Public notice of an application;
· Analysis of the application;
· Negotiation of a draft lease;
· Preparation of Commissioner's analysis and proposed decision;
· Public notice of the availability of the Commissioner's
analysis, proposed decision and public comment period;
· Public comment period and public hearings;
· Consideration of comments;
· Preparation of final decision; and
· Execution of the right-of-way lease, if that is the final
decision.
MR. BRITT said the right-of-way lease is one of a whole variety of
requirements that would come into play with a project this large.
The Producers' Consortium consultants recently issued a draft
report entitled, "Data Review and Permitting Requirements." Their
list of permits, approvals and consultations for one or both of the
routes contain 29 categories of federal authorizations, 22
categories of state authorizations, and 8 categories of local and
private authorizations. Each of these categories would have
anywhere from one right-of-way lease to many land use or water use
permits. These lists are incomplete as they only considered the
pipeline and gas treatment plant and not associated or support
facilities, such as compressor stations, construction camps, access
roads, material sites, disposal sites, staging areas, and other
temporary use areas.
MR. BRITT noted another frequently asked question is how long it
will take to permit a project. That will depend on two variables:
the applicant's ability to provide information in a timely manner
and the federal approval process. A reasonably ambitious schedule
would be in the 18 to 24 month period. On a project-by-project
basis, this will be highly variable and will be based on the amount
of work that has already been done and the controversy associated
with it.
MR. BRITT said regarding what is happening now, Yukon Pacific
submitted a refined pipeline centerline alignment for the TAGS
project on July 2. It is being reviewed in the Joint Pipeline
Office and it may or may not result in amendments to the federal
and state rights-of-way. Regarding the Alaskan Northwest Natural
Gas Transportation Company (ANNGTC) project, they requested that
the state proceed with processing their application, which it did
on March 6. He requested ANNGTC to identify documents relevant to
their applications. ANNGTC responded on July 2. He said he made
that request because he has no estimate of the tons of paperwork
relative to the ANNGTC's project that was processed 20 years ago.
It seemed more expedient to ask ANNGTC to let him know what it
considered to be relevant in this point in time. He has not
finished reviewing those documents yet. In summary, ANNGTC
completed a large amount of work relative to their right-of-way
application.
MR. BRITT said the Alaska Gas Producers Pipeline Team (AGPPT), the
producers' consortium, has about 90 personnel. They've awarded
about $75 million in contracts for feasibility work. The contracts
they've issued have been for pipeline engineering, gas treatment
facility engineering, natural gas liquids extraction facility
engineering, environmental and regulatory work and land status
work. The number of people involved is very, very large. For
example, the two prime contractors for the U.S. environmental and
regulatory issue have 11 specialized subcontractors and, according
to the producers, they have over 500 full-time equivalent people
engaged in these efforts right now. On July 6, the producers
provided a list of field studies for the summer. There are 21
studies in Alaska, several of which have been completed, some are
in progress, and many have not begun. The state has begun
processing the permits necessary for them to do this work. They
need a collection permit from the Alaska Department of Fish and
Game (ADFG) for the drain work. The Pipeline Office has
communicated its expectations of the studies to the producers.
MR. BRITT said the sponsor group is continuing to assess the
feasibility of the Kenai LNG project. He has proposed that they
start assessing markets for LNG, exploring possible synergies for
the highway project and working to reduce the contingencies for
their project plan and thus increase the commercial viability. He
has also been told their consultants recently completed an
environmental and regulatory evaluation of the project with the
emphasis on permitting of the Parks Highway Route. Depending on
the conclusion of that study, he would expect to begin contact with
them.
MR. BRITT noted the State Pipeline Office has had very little
contact with the Port Authority, the Cook Inlet Terminus Group or
the over-the-top route. Regarding a brief overview of state
government, his specific role is defined by Administrative Order
187. He has been directed to coordinate state permitting and
authorization processes and to lead communications and coordination
with federal and Canadian agencies related to permitting and
authorizing projects. He included a document in packets entitled,
"Gas Pipeline Office - Anticipated Pre-application and Application
Processing Tasks for FY 2002." It contains a list of short-term
tasks that are associated with the roles.
The point of these tasks is to positively affect the time required
to permit the project by integrating the state and federal
government processes, as was done with the Joint Pipeline Office.
They also want to make the permit authorizations more responsive to
Alaskan interests when they are issued by others and they want to
make the financial return on the project greater for the state.
Progress on these tasks has been limited due to a lack of funding
and lack of staff. He does not have a funding source at this time,
but perhaps will get one during the upcoming Legislative Budget and
Audit meeting. The limited funding provided in the last fiscal
year allowed the hiring or assignment of liaisons from DEC and
ADFG, an ADFG field leader and his position. Existing staff in
several state agencies are performing very limited gas pipeline
work, paid for with discretionary funding. He has negotiated
reimbursement MOUs with Foothills and with the producers for the
tasks on the list. He cannot execute those agreements until he
receives funding from LBA.
MR. BRITT noted the staff at the State Pipeline Coordinator's
Office made remarkable progress in collecting and organizing ANGTS
files. The Gas Pipeline Office (GPO) staff is working with
Foothills and the producers to move their efforts forward. He has
received expressions of interest in GPO positions from a number of
excellent candidates, which he is very happy about. In addition,
he has found inexpensive housing for the office until the end of
the year. Hopefully, they will move into those temporary, but co-
located offices, in August.
In conclusion, MR. BRITT said a lot has been happening and the pace
of proponents' efforts is increasing. If general funding for the
GPO is approved, he will sign reimbursement agreements with
Foothills and the producers. They will then begin a detailed work
plan and hiring to support the work plan. If general funding is
not approved, the state will continue to fall behind the
proponents, both in the staff necessary to process their
authorizations and, of particular interest to legislators, in the
knowledge necessary to promote state interests. He offered to
answer questions.
CHAIRMAN TORGERSON thanked Mr. Britt for doing such a great job.
He noted that he participated in the memoranda of understanding
(MOUs), as that was part of the legislation he worked on this
session. He also does not anticipate a lot of opposition to Mr.
Britt's request to receive the funding through the MOUs as they
relate to what the producers are willing to pay for. He pointed
out the percent the producers are willing to pay for differs from
the percent the administration wants to fund and that is what they
are trying to work through. Another problem he has is in regard to
interaction with the administration is the legislature's lack of
access to documents that it is funding. The legislature has found
it is running a parallel course, to some degree. He does not favor
putting more money into that kind of a procedure. He would rather
fund the studies directly through the Legislative Council. He told
Mr. Britt the general fund request is above and beyond what the
producers are willing to pay for. So, LBA is questioning why it
should fund things that the producers are not willing to pay for.
He asked Mr. Britt to be prepared to explain the difference to the
LBA Committee.
4:21 p.m.
The committee took a short recess.
4:30 p.m.
ALASKA HIGHWAY NATURAL GAS POLICY COUNCIL
CHAIRMAN TORGERSON called the meeting back to order and welcomed
the members of the Governor's Alaska Highway Natural Gas Policy
Council (GAHNGPC). He introduced Mr. Frank Brown, Co-Chair of that
Council, and noted that Mr. Sampson had to be out of town today.
He asked Mr. Brown to proceed.
MR. FRANK BROWN, Co-Chair, Alaska Highway Natural Gas Policy
Council, informed committee members that Jim Sampson could not
attend as he was called out of town on family business. He
explained that Governor Knowles appointed 28 Alaskans to the AHNGPC
in January. The group's mission is to develop recommendations
promoting a natural gas pipeline project that maximizes the
benefits to all Alaskans. The AHNGPC will formulate its
recommendations and report back with its findings on November 30.
Since January, because the group is so large, members spent time
getting to know each other, learning how to work together and
educating each other. The group's task is formidable so a key part
of the early stage has been educating the group. The group has
also been engaged in a public process in which it has been going
out and sharing information with, and listening to, the public. To
handle so many issues, the group was divided into five
subcommittees. In addition to the public meetings and subcommittee
work, the AHNGPC has held statewide hearings in Fairbanks, Kenai,
Tok and Anchorage and it will travel this summer to Barrow, Juneau
and Southeast. He noted he would introduce the members and ask
them to discuss their work, and then AHNGPC members would answer
questions. Mr. Brown commented that the 28 members and four ex-
officio members of the Legislature have no staff so they have been
working very hard.
MR. BROWN introduced Bill Corbus, who is chairing the State
Pipeline Ownership and Tax Structure Subcommittee; Mayor Rhonda
Boyles, who is on several committees; Jack Roderick, who is
involved in the Access of In-State Gas Use and Future Opportunities
Subcommittee; Charlie Cole, who is chairing the Federal-
International Action Subcommittee; and Mike Navarre, who is
chairing the Alaska Hire/Buy Subcommittee.
MR. MIKE NAVARRE informed the committee that he asked to serve on
the AHNGPC because, as a former legislator, he couldn't resist the
opportunity to keep an eye on the Administration and because he
wanted to be involved on the policy level to make sure the project
is done right and will benefit Alaskans. The Alaska Hire/Buy
Subcommittee is focusing on several things. First, it wants to
identify what type of training will be needed for workforce
development and to identify the numbers of the necessary workforce.
The Subcommittee is also looking at socio-economic studies and it
is trying to dovetail those with other studies related to GARVEE
bonds, and other work and at the potential impact to the
communities and to the state. The Subcommittee will make
recommendations and have a report ready that the legislature or
anyone else can use.
MR. BILL CORBUS informed the committee that, in civilian life, he
is the President of Alaska Electric Light and Power Company in
Juneau. He believes it is important that everyone get behind the
gas pipeline. He is chairing the Subcommittee on the State
Pipeline Ownership and Tax Structure. The Subcommittee is made up
of six members who have met with the Alaska Permanent Fund
Corporation (APFC), the Alaska Industrial Development and Export
Authority (AIDEA) and Department of Revenue staff to discuss
various aspects of financing the pipeline. The Subcommittee will
also be gathering ideas for the tax structure.
MR. JACK RODERICK informed committee members that he has been
helping Ken Thompson, who chairs the Subcommittee on Access for In-
State Gas Use and Future Opportunities. He noted that Carl Marrs
also had a committee, but the two were merged with a new emphasis
on in-state access to gas. The Subcommittee heard testimony in
Fairbanks about the use of gas, which was quite impressive. DNR is
doing a study on in-state use. The Subcommittee is looking at LNG
and GTL projects. He said he believes Ken Thompson was correct
when he suggested the subcommittee should be thinking about the use
of this gas 50 years down the line. He suggested that legislators
put on their business hats as the state will be in the business of
gas and that negotiations will be coming on down the line with the
producers and gas owners. He believes it is critical that the
legislature and administration use a partnership approach on this
issue. He pointed out that the Governor has given the Council carte
blanche to conduct its investigations on a natural gas line. The
Governor has not given the AHNGPC specific mandates or said that he
wants certain results or information that exclusively favors the
highway line. The Governor has only said that he believes that is
the preferential line. Beyond that, the AHNGPC will provide the
state with the information it develops. The AHNGPC certainly wants
to work with the legislature. He believes it would be disastrous
for both bodies if they do not cooperate fully. He pointed out that
no one on the AHNGPC is getting paid for the time they are putting
in on this project. He noted that two members of his subcommittee
are super lawyers, who are getting a workout. The subcommittee has
also met with Bob Loeffler of the Division of Mining, Land and
Water, and John Katz in Washington, D.C.
4:43 p.m.
MS. RHONDA BOYLES informed the committee that she serves on two
subcommittees and had two points to make today. One is that the
importance of the gas pipeline rises above any party politics or
the issue of administration versus legislature or Native versus
non-Native. She said, e HH"We have to worry about the entire
state." Second, she said they need to share good information and
not spend time being redundant.
REPRESENTATIVE GREEN asked if sharing of information includes the
legislature.
MR. BROWN replied that was his understanding.
CHAIRMAN TORGERSON said he was concerned with the legal end of
things and that the legislature does not have access to studies
they have funded for the administration. He said they probably get
the same paperwork from the producers. He asked Mr. Corbus if he
was looking at incentives the producers might want.
MR. CORBUS replied they would be looking at the tax structure.
CHAIRMAN TORGERSON asked if he would look at the ELF or royalty
tax. He said that experts in the administration would not share
that data with the committee.
An unidentified person said the producers don't really know the
economics of the processing plant or the line yet.
CHAIRMAN TORGERSON said his question didn't have to do with the
plant. He stated, "We know in the early '80's the cost of the plant
was included as part of the tariff. There is no alliance yet and
there is no tariff."
His question had to do with other companies downstream that may
have their own conditioning plant. He wanted to make sure the state
was not locked into a tariff on a conditioning plant where somebody
else can probably build their own. It's a question that has been
posed to him by other producers.
MR. NAVARRE said his committee was looking at tax structure policy.
MR. KEN THOMPSON spoke to the issue of the processing plant:
That's an important issue that we really need to look at
legally as well as what the leases allow for. For
example, some North Slope leases were modeled after the
Texas Oil and Gas Lease Law. No state leases in Texas
conditioning gas for market is often considered on the
lease as lease cost and is not included in pipeline
tariff calculations. However, if there's a situation
where you have a lot of leases and it's not economical on
one to put that plant, sometimes a pipeline consortium
would build that and that can be included.
I think we'll need to review the Prudhoe Bay leases and
see, but I think there may be some clauses in there that
really dictate that it not be in the pipeline tariff or
it could be the other. This is an issue we haven't
examined yet, to my knowledge.
CHAIRMAN TORGERSON said he understood that an amendment to the
presidential decision allows that so, it probably will not show up
in a Prudhoe Bay lease. He commented, "It still needs to be looked
at."
MR. THOMPSON informed the committee that he chairs the Instate Gas
Use Committee. It has looked at the Anchorage Economic Development
Corporation's study on Cook Inlet gas supply for the Anchorage
area. An Enstar representative stated during testimony at an AHNGPC
hearing that a major concern for Anchorage residents is that by
2007 or 2008, deliverability of the Cook Inlet reserves will fall
below the projected needs at that time. While reserves will be
there, deliverability will fall short of demand. At that point,
things have to be done, such as storage or whatever. He commented,
Those solutions will likely be costly and will increase,
we think from our committee's viewpoint, the cost of
natural gas in Anchorage. That will affect businesses as
well as citizens.
MR. THOMPSON said that by 2017, the deliverability problem of gas
becomes even more extreme. To solve that problem would cost even
more because of costs associated with increased exploration,
exploration incentives, gas storage and bringing in LNG. He noted:
We believe bringing natural gas down from the Slope
through a spur line off the line that goes south would
really allow gas prices to be much more reasonable for
all Anchorage residences and businesses. This whole thing
of south or north interestingly in my own mind is
becoming clean energy, self-sufficiency for Alaska. If it
goes north, we will not have clean energy, self-
sufficiency 10, 20 or 30 years down the road. If a line
comes south and we can build spurs off of to our major
interior cities, Anchorage and other locations, we can
have that self-sufficiency. What a shame to have a huge
resource if our own state cannot be self-sufficient in
energy ...
Another thing - we have this in the state of Texas to see
how they handle their royalty state leases. We found that
they market about 50 percent of their royalty gas in-
kind, market it themselves, use a portion of it to
generate electricity for state government buildings and
schools. It's trimmed their electricity bill by 30
percent for the state. They also allow 50 percent of the
royalty gas to be sold by the producers. Fifty percent of
the time they're able to get a higher netback price than
the producers. That's an interesting observation and we
will examine that as kind of an option for Alaska's
royalty share of gas, as well ....
REPRESENTATIVE FATE said he noticed when reading a report on one of
the charts on the chemical industry based on the liquid components
of gas (ammonia specifically), that it's either moving overseas or
it's in danger of moving overseas permanently. He asked if that
creates a vacuum that could be filled by a chemical industry in
this state.
MR. THOMPSON replied that they are looking at that issue and
whether there can be value-added processing for petrochemicals,
expansion of fertilizer and potentially some limited LNG to the
West Coast or to very select Asian markets on a smaller scale than
a large Valdez project, but viable. Petrochemicals, such as
olephins, are made from natural gas and are used in feed stocks.
Asia has a rapidly growing need for more olephins. Japan has
expressed interest in DME (dymethyl ether), which is used like a
propane butane (LPG). Williams Energy testified that they had an
internal study that assessed a broader natural gas liquids business
within Alaska.
REPRESENTATIVE GREEN said 20 years ago Dow Chemical was looking at
the possibility of a petrochemical plant at Fire Island and that
met with a lot of resistance, but he was thinking of something like
that. He asked if it was within his committee's purview to study a
line to Kenai.
MR. THOMPSON replied yes. They are looking at a spur line into
Anchorage for domestic use and if that takes place, there could be
an additional spur off of a hub that would go to Kenai for a
natural gas refinery. They are assessing whether that would be
economical. He said the Dow study looked at an assessment of not
shipping natural gas, but instead taking all the natural gas
liquids like propane and butane out on the North Slope and shipping
down a separate liquids line to Fire Island and some other
locations. His committee is looking at something different like
taking the gasoline itself and manufacturing some of the other
products he described. They are looking at the Kenai Peninsula.
REPRESENTATIVE OGAN said, "Don't rule out Pt. Mackenzie."
MR. THOMPSON said that was an excellent point.
MR. BROWN added that everyone needs to recognize that there is a
market window out there and it's going to get subdivided. He
commented:
If we're not part of the solution, something else will be
- nuclear, LNG from other sources, plane coal technology,
whatever ... We should all work together to make sure
Alaska's North Slope gas is ready.
CHAIRMAN TORGERSON thanked everyone for their participation and
announced an at-ease from 5:03 p.m. to 5:06 p.m.
MR. HAROLD HEINZE, resource consultant for the Legislative
Majority, said he is under contract to help evolve alternative
strategies on the gas issue. There are three major areas where
studies are not being done or they are way behind. He stated:
Number one is, I was struck by the fact that we need to
seriously understand the state of Alaska as a shipper and
in a strategic sense, what we would achieve by being a
shipper. Frankly, we need someone in the state government
to kind of look at that as almost an advocate and develop
that idea. I think it is almost intuitively obvious that
we would get many of the same benefits from ownership as
you would to be a real shipper in the pipeline. It's
something you could probably manage as a business a lot
easier than investing millions of dollars. It would help
a lot on the access issue that we were concerned about
this morning. So, there are some real payoffs there.
Clearly, being a shipper under federal law gives you
special standing before FERC and what I mean is if the
State of Alaska [was] to make modified contracts
contingent on [indisc.] in Fairbanks, [indisc.] city of
Chicago, for instance. That might be an interesting
position to be in as far as all the FERC proceedings and
all the other things that would happen. The producers
would have to deal with you as another shipper and not be
discriminated against in terms of [indisc.].
I also noted that the state is not using a royalty board.
If you look back, there's a reason the Royalty Board was
put in place and it would really be a pity if the seller
of gas would make the same mistakes we did on [indisc.].
Whether it's Netricity or whatever, it seems to me those
are triggering provisions and we should be using that.
CHAIRMAN TORGERSON said the resolution that required them to look
at the Netricity proposal directs them to use the process that's in
place, which is the Royalty Board. He said, "So, we have not
forgotten."
MR. HEINZE said he knew the Chair had not forgotten, but he was
surprised that there was no mention of it. He stated:
The second broad area that I notice is from a strategy
point of view and trying to look at the gas issue. It's
obvious that we're trying to maximize the benefit and
minimize, eliminate or mitigate the impacts, the
negatives.
MR. HEINZ said that there are human impacts as well as
environmental and the TAPS experience is fully documented showing a
good idea of what all the impacts are for a large project. He
didn't see anyone studying them. He asked, for example, what is the
impact on school systems and public facilities like airports and
roads - and how to pay for them. Those issues need to be reduced to
dollars so you know if they have a big or small price tag.
Finally, MR. HEINZE said he was struck by what he didn't hear from
the AOGCC. While FERC is going to dominate the regulation of the
interstate molecules, there's not one molecule coming out of those
wellheads that is going to be sold until AOGCC changes its rules.
The reason that's important is that the [indisc.] rules right now
prohibit gas sale. He said that creates a huge range of uncertainty
until this gets resolved. He said he looked forward to working
with the committee on these issues to get something done.
REPRESENTATIVE GREEN said he thought he was right on the gas sales
and asked how they circumvented that by spiking the oil with gas
liquids.
MR. HEINZE replied that the original definition of oil in the TAPS
provided for 90 percent crude oil and up to 10 percent natural gas
liquids. There are also minor gas [indisc.] that occur in the field
right now, but no one has questioned those volumes.
Public Testimony
CHAIRMAN TORGERSON then took public testimony.
MR. SCOTT HEYWORTH, Citizens for the All-Alaskan Gasline
Initiative, gave the following testimony.
The State of Alaska, both the administration and the
legislature, must insure that the new Prudhoe Bay unit
operating agreement is a public document and here's why.
The hydrocarbons at Prudhoe Bay remain Alaska's single
largest and most valuable natural resource. Right now
nobody outside the producer companies knows anything
about the underlying intercompany contractual
arrangements governing its operation and development. The
Prudhoe Bay unit members stated in 1996 in hearings
before the AOGCC that the Prudhoe Bay operating agreement
in no way inhibited a major gas sale. In 2000, they
announced that they had totally realigned the oil and gas
interest to remove all the major conflicts and
impediments which were not even supposed to exist at all.
If it wasn't broken in 1996, why was it changed in 2000?
Is realignment of those interests the only thing that
changed with the new ownership arrangement and operating
structure and has realignment actually even taken place?
The State of Alaska simply cannot allow the basic tenets
governing future control of its single largest revenue
resource to be confidential. I urge you to ask the
appropriate industry witnesses tomorrow when they testify
just exactly when the state and the citizens of Alaska
will have our opportunity to examine and judge this
critical agreement. It is the most important question and
one that you must ask them tomorrow and hope we will get
an honest answer.
REPRESENTATIVE OGAN said he plans to follow up on that issue.
CHAIRMAN TORGERSON thanked everyone for sitting through this
marathon and adjourned the meeting at 5:17 p.m.
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