Legislature(2001 - 2002)
08/15/2001 09:08 AM Senate NGP
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
Fairbanks, Alaska
August 15, 2001
9:08 a.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Pete Kelly
Senator Donny Olson, alternate
SENATE MEMBERS ABSENT
Senator Rick Halford
Senator Johnny Ellis
OTHER MEMBERS PRESENT
Senator Gary Wilken
HOUSE MEMBERS PRESENT
Representative Joe Green, Vice Chair
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate, Alternate
Representative Reggie Joule, Alternate
HOUSE MEMBERS ABSENT
Representative Mike Chenault, Alternate
Representative Brian Porter
COMMITTEE CALENDAR
NATURAL GAS PIPELINE PRESENTATIONS
Congressional Update
Regulatory Agencies' Update
Alaska Highway Natural Gas Policy Council Update
Department of Revenue - discussion of tax issues
Overview by the Alaska Natural Gas to Liquids Company
Alaska Gasline Port Authority Update
Presentations from Producer Groups
Foothills Pipe Lines Ltd. Update
Joint Natural Gas Pipelines meeting - discuss scheduling
Additional Public Testimony by invitation of the Chair
The Honorable Ted Stevens
Public Testimony
WITNESS REGISTER
Mr. Mike Menge
Staff to Senator Frank Murkowski
United States Senate
322 Hart Building
Washington D.C. 20510-0202
Mr. C. J. Zane
Dyer, Ellis & Joseph
Washington D.C.
Mr. Duncan Smith
Dyer, Ellis & Joseph
Washington D.C.
Mr. John Katz, Director
State and Federal Relations and
Special Counsel to the Governor
444 N Capitol NW, Suite 336
Washington D.C. 20001-1512
Mr. Bob Loeffler, Attorney
Morrison and Forrester LLP
2000 Pennsylvania Ave., S.W.
Washington D.C. 20006-1888
Ms. Nan Thompson, Chairperson
Regulatory Commission of Alaska
1016 W 6th Ave.
Anchorage AK 99501-1963
Mr. John Katz, Director
Office of Energy Projects
Federal Energy Regulatory Commission
888 First St., N.E.
Washington D.C. 20426
Mr. Bill Britt, Pipeline Coordinator
Department of Natural Resources
411 W 4th Ave.
Anchorage AK 99501-2343
Mr. Mark Myers
Division of Oil and Gas
Department of Natural Resources
550 W 7th Ave., Ste 800
Anchorage AK 99501
Ms. Bonnie Robson, Petroleum Investment Manager
Division of Oil and Gas
Department of Natural Resources
550 W 7th Ave., Ste. 800
Anchorage AK 99501-3560
Mr. Wilson Condon, Commissioner
Department of Revenue
PO Box 110400
Juneau AK 99811-0400
Mr. Ed Small
Cambridge Energy Research Associates, Inc. (CERA)
Charles Square, 20 University Road
Cambridge MA 02138
Mr. Richard Peterson, CEO
Alaska Natural Gas to Liquids Co.
310 K Street
Anchorage AK
Mr. Dave Dengle, Executive Director
Alaska Gasline Port Authority
406 Cushman Street
Fairbanks AK 99701
Mr. Rigdon Boykin
Special Counsel to the Port Authority
O'Melveny & Myers, LLP
151 East 53rd Street
New York NY
Mr. Robbie Schilhab
Exxon Mobil
Representing Alaska Gas Producers Pipeline Team
550 West 5th Avenue, Suite 500
Anchorage AK 99501
Mr. Joseph Marushack
Alaska Gas Producers Pipeline Team
550 West 5th Avenue, Suite 500
Anchorage AK 99501
Mr. John R. Ellwood, Vice President
Engineering and Operations
Foothills Pipe Lines Ltd.
3100-707 Eighth Ave., S.W.
Calgary, Alberta, Canada T2P 3W8
Ms. Ronda Thompson, Special Assistant
International Trade Office
Alaska Legislature
716 W 4th Ave., Ste. 660
Anchorage AK 99801
Ms. Kara Moriarty, President and CEO
The Greater Fairbanks Chamber of Commerce
250 Cushman St., Suite 2-D
Fairbanks AK 99701
Mr. Gordie Lewis
Golden Valley Electric Association
PO Box 71249
Fairbanks AK 99707-1249
Mr. Paul Metz
3510 Rosie Creek Rd.
Fairbanks AK
The Honorable Ted Stevens
United States Senate
522 Hart Building
Washington D.C.
Ms. Deb Moore
Northern Alaska Environmental Center
Fairbanks AK
Mr. Ken Freeman, Member
Alaska Highway Natural Gas Policy Council (AHNGPC)
Office of the Governor
550 W. 7th Ave., Suite 1700
Anchorage AK 99501
ACTION NARRATIVE
TAPE 01-12, SIDE A
9:08 a.m.
CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural Gas
Pipelines meeting to order at 9:08 a.m. and announced that Mr. Mike
Menge, staff for Senator Murkowski, would comment.
CONGRESSIONAL UPDATE
MR. MIKE MENGE, staff to Senator Frank Murkowski, said he came to
Alaska in 1979 with the U.S. Geological Survey and spent the
ensuing years working on various oil, gas and coal development
projects across the state, including working on the TAPS line.
During Governor Hickel's latest governorship, he came to Juneau and
worked four years as Director of Environmental Quality within the
Alaska Department of Environmental Conservation. So, he got a
chance to look at resource issues from a permitting perspective,
which controls a lot of Alaskan projects. Over time it has become
the dominant issue. Alaska is awash in resources, but not
necessarily awash in good will or the ability to permit the
development of these resources. When Senator Murkowski assumed the
chairmanship of the Natural Resources Committee in D.C., he was
invited to serve as professional staff dealing with public land,
energy issues and Alaskan issues. When he was authorized officer
for the TransAlaska pipeline he and Jerry Brossia (then with the
Alaska Department of Natural Resources) created the Joint Federal
State Pipeline Monitoring Office, which was created primarily to
issue the right-of-way permits necessary to proceed forward with
the TAGS line and also to continue monitoring the TAPS line. So, he
has followed the gas development in Alaska from "the lowest rung."
MR. MENGE said he would give them a brief update on activities in
Washington, D.C. where the Senate is engaged in the energy package.
When the Senate finishes its package, both House and Senate
versions will go to a conference committee. The committee will get
into the meat of the energy package starting about September 12 and
expects to have an energy bill before the full Senate by the end of
September. With the transition of power in the Senate, it looks
like issues will be debated well through October. Other than the
appropriations, the energy bill will be the principle issue. He
said further:
Senator Murkowski has encouraged the advocates for gas
development in Alaska to bring forth energy legislation,
which would be considered during the energy package.
About two or three weeks ago we received that submittal
from the producers group. We have also asked the
TransCanada Foothills group for legislation and to this
point that has not been forthcoming. Senator Torgerson
shared with me proposed legislation I had not seen
before. So, now is the right time for the consideration
of that legislation. We have submitted the producers'
legislation to various federal agencies for their review
and comment and have not received that back yet. The
Senator will reserve his actions until after we have had
a full hearing of this information. I believe we will be
scheduling a hearing in mid-September to take a look at
this information shortly after we get back. The Senator
has made it very clear that he prefers the Alaska line, I
think for all the reasons that Senator Torgerson has been
working on and elaborating, as well. We have serious
concerns over the 'permittability' of the over-the-top
route. We also have concerns with the potential impacts
of that line. However, Senator Murkowski has not closed
out his options and is prepared to listen with an open
mind to all of the various proposals before we draw our
conclusions. Clearly the energy in the committee right
now is focused primarily on ANWR opening, but not to the
exclusion of potential pipeline legislation, as well. I
think we'll be doing a full-court press in doing
everything we can to advance the ANWR legislation and now
would be the time when that requires almost all of our
energy. That is pretty much all I have to report at this
point. I'd be pleased to answer any questions…"
CHAIRMAN TORGERSON added that he had shared Charlie Cole's proposed
legislation with Mr. Menge this morning, not anything he had
written personally.
REPRESENTATIVE OGAN asked him to comment on what a radio station
was saying about legislation Senator Murkowski had introduced on
this issue. He thought there was only draft legislation.
MR. MENGE replied:
I have also encountered that rumor and I can assure you
that it is absolutely not true. We have received the
legislation offered by the producers' group. We have
disseminated that to various federal organizations for
their review and comment. Senator Murkowski has not taken
a position on that legislation nor has he offered that
legislation and will not until after we have an
opportunity to look at it in significant detail and
receive the input from a lot of other organizations and
entities. Thank you for the opportunity to clarify that.
CHAIRMAN TORGERSON asked if he was guessing September for the
hearing Senator Murkowski had been able to schedule on that
legislation with Mr. Bingaman.
MR. MENGE said he was guessing and there had only been preliminary
discussions. He didn't think there would be any opposition from
Senator Bingaman to have a hearing.
CHAIRMAN TORGERSON asked him to tell Senator Murkowski that he
would like to have the opportunity to testify on any legislation
that may come through on this proposal.
MR. MENGE said he would carry that request to the Senator.
REPRESENTATIVE DAVIES said that he thought the bill provides an
advantage by expediting the process for the northern route and, "We
would have serious concerns with that…"
MR. MENGE said he would pass on that concern.
CHAIRMAN TORGERSON announced that C.J. Zane and Duncan Smith, Dyer,
Ellis and Joseph, were under contract through Legislative Council
to monitor the progress on the energy bill in the House, the
Senate, the conference committee and the Bush Administration. He
said they actually signed the contract yesterday, but they had been
on the job for over a month and had set up some very important
meetings between him [Chairman Torgerson] and staffers in D.C.
MR. C.J. ZANE, Dyer, Ellis & Joseph, said he was Chief of Staff for
Congressman Don Young for many years and is familiar with Alaskan
issues. He also lobbied for Native corporations, Alyeska Pipeline
and Alaskan based interests for a number of years. He said that a
partner in the law firm, Mr. Duncan Smith, worked as committee
staff for Congressman Young at the same time. They feel they are in
a good position to help the committee stay on top of developments
with Congress and the Bush Administration. The administration can
do a number of energy policy things on its own that may or may not
have an effect on the Alaska natural gas project. There is a lot of
interest in the energy issue. The bill that just passed the House
didn't seem to have anything that was disproportionately skewed to
adversely affect this project. That bears watching as this effort
moves forward. Other than the tax grants and incentive packages for
other types of energy, the only thing in the House bill of note is
the language that bars the over-the-top route.
I think that several democratic senators who
traditionally vote with the environmental community are
going to be very key in this debate in as much as several
of the national environmental groups have said they would
support natural gas delivered from Alaska, but they have
made it pretty clear that does not include a system that
would be in the Beaufort Sea...
9:27 a.m.
MR. DUNCAN SMITH, Dyer, Ellis & Joseph, added that four bills were
consolidated into one. Everyone was putting forth ideas and the
bill needs to be watched through to the final package.
REPRESENTATIVE DAVIES asked if he concurred with the
characterization of the producers' bill that it provides at least
equal footing, if not an advantage, to the over-the-top route.
MR. ZANE answered that he read the transcript that Charlie Cole
provided yesterday and could understand why John Katz and Mr.
Loeffler believe the language provides for an over-the-top route,
but he wasn't sure which proposal Representative Davies was looking
at. The Walker Walker & Associates language [commissioned by
Charlie Cole and the Port Authority) does not advantage the over-
the-top route; it would advantage the existing Foothills and Yukon
Pacific line.
REPRESENTATIVE DAVIES asked him to expand on language regarding the
over-the-top route in the House bill.
MR. ZANE said he hadn't heard any concerns with the language from
the Canadians. He has heard that people were wondering if similar
language could be added to a Senate bill.
MR. SMITH reiterated that there are a lot of moving parts to this
bill and this is one of a whole range of issues. A lot of people
are still presenting their ideas and they need to be watched as a
final package is put together. He agreed with Mr. Zane that
analyses that had been done to date had been pretty careful, but
they all conclude that you have to see what the final words say.
9:35 a.m.
CHAIRMAN TORGERSON said he thought the criticism Alaska is getting
from Canada is on two fronts. One is from the Northwest Territories
on banning the over-the-top route; they would like to see Prudhoe
Bay and the Mackenzie Delta in one line. The other front that is
getting more press is the opposition to opening ANWR from our Yukon
friends and others throughout Canada. He thanked them for joining
the committee.
Canadian Political Reactions
CHAIRMAN TORGERSON asked Mr. John Katz, Director, State and Federal
Relations, and Special Counsel to the Governor in Washington, D.C.
for an update on Canadian political reactions to the ban imposed by
the Congress on the over-the-top route, Prime Minister Chretien's
comments during the G-8 summit when he appeared to be favoring one
route over the other and on the producers' legislation.
REGULATORY AGENCIES
MR. JOHN KATZ, Director, State and Federal Relations, and Special
Counsel to the Governor in Washington, D.C. said that Bob Loeffler
was with him and he would testify on other matters later in the
hearing.
MR. KATZ said:
My testimony today is the product of discussions with
U.S. and Canadian officials at both the federal and, in
the case of Canada, territorial and provincial levels,
discussions with the private sector and various interest
groups. I would like to very briefly give my perception
of the current situation with respect to four or five of
the most important entities and interests in Canada and
then respond to four or five commonly asked questions
about what's going on in Canada in relationship to the
United States.
The first category would certainly be the Canadian
federal government. I think all of you are familiar with
the so called open mike remarks of the Prime Minister of
Canada, Chretien, in which he was heard to say at the G-8
summit to President Bush, 'Well, can't we basically get
on with building the over-the-top route.'
We have since followed up on those remarks in Canada with
our Canadian consultants and also through our means. The
official position of the Canadian government as we
understand it remains route and project neutrality. They
would prefer in the ideal circumstance that the producers
and pipeliners come to them with some unity on how they
would like to proceed in commercializing natural gas in
the U.S. and Canadian Arctic.
There have been presentations at the cabinet level of the
Canadian government. I think it is fair to say there is
some individual ministers who would favor the over-the-
top route or who would favor a Mackenzie Valley route
controlled completely by Canada. There are others who
would favor the southern, the Al-Can route. I think it is
also the case that the Canadian cabinet has been briefed
on this issue and is aware that in the case of the over-
the-top route there would be a significant permitting
process that would be required involving many different
regulatory processes and permits. Whereas with respect to
the southern route, thanks to ANGTA of 1976 and the
ensuing U.S. and Canada decisions, the decision making
process would be much less complicated. But for this
moment in history, I think the official position will
remain neutral while individual ministers certainly have
their own personal predilections.
A second major force in the Canadian political situation
is the position of the various provincial premiers and
territorial premiers. As all of you know, Premier Kakfwi
of the Northwest Territories strongly favors an over-the-
top route or a Mackenzie Valley route. He is opposed to
the Al-Can or the southern route. In contrast, the
premier of the Yukon Territory has expressed her support
for the Al-Can route. British Columbia so far in its new
administration has not been quite as active, but we
expect that as Premier Campbell gets more acquainted with
these issues, our expectation is that he will be a strong
advocate for the southern route, as well.
Premier Klein of Alberta has taken the position that he
does not want to see a so-called 'bullet pipeline'
through his province. That is, he wants to see some
additional commercial value from natural gas production
and transportation and he has speculated about the use of
gas liquids or expanding the petrochemical industry in
Alberta.
The next group to mention is the producers and the
pipeliners themselves. Our information is that thus far,
the North Slope gas producers and their Canadian
subsidiaries and affiliates have not been that active
yet, in the Canadian decision-making process. I think at
least two entities have been quite active. The first is
Continental Oil, which has substantial holdings in the
Mackenzie Valley. Some of you might have seen the recent
comments of their CEO strongly advocating the development
of the gas reserves in the Mackenzie Valley and not being
particularly supportive at all of the southern route or
the immediate commercialization of North Slope natural
gas. His view is that there are sufficient reserves in
the Mackenzie Valley and he would like to see them
developed sooner rather than later.
10:41 a.m.
All of you are familiar with Foothills and their
activities. They have recently confirmed their position
that all of this was settled between the United States
and Canada in the late 1970's and that they have the
exclusive franchise to develop North Slope natural gas by
means of the southern route.
The next set of interests, which I think are very
important in Canada and in the U.S. also are Canada's
aboriginal people. At the outset I should mention that as
most of you know that the North Slope Eskimos in Alaska
have expressed strong opposition to the over-the-top
route. In Canada, there isn't the same population
diversity along the coast. So I'm going to focus on first
the clans and tribes of the Northwest Territory. We're
advised that by and large the issue there is not
aboriginal land claims themselves, but rather ownership
and profit from the pipeline, itself.
Most of the clans started with the position that they
wanted 30 percent ownership interest in the pipeline.
More recently, one clan has advocated 100 percent
ownership in the pipeline and so that's thrown the
situation into some state of fluidity and chaos. The
ownership interests there have yet to be resolved.
There's been some talk about asking for intervention,
perhaps from the Canadian federal government.
In the south, the situation is a little bit different.
Aboriginal claims have not been fully resolved, but
there's only one major tribe or clan to deal with in that
circumstance. We've been advised that it is unlikely
there that the absence of a full settlement at this point
would be an obstacle to pipeline construction. The
feeling is that either there will be a comprehensive
aboriginal settlement or if not, that probably a deal
could be negotiated with respect to pipeline, itself.
Other groups have weighed in to the fray. Canada has a
very active environmental movement as we do. They have
expressed opposition to the over-the-top route, but we do
not detect that there is concerted opposition, yet, or
perhaps a conscious joining of Canadian environmental
groups with Alaska groups and with national groups.
However, I think it is fair to postulate that the
environmental sector, probably in both Canada and the
United States will oppose an over-the-top route.
Moving on quickly now to some of the questions that are
on people's minds about the Canadian situation. The first
question is how did the Tauzin Young amendment [that
would preclude construction of over-the-top route
offshore] affect the situation. Certainly, there were
articles in Canada of when this occurred and some
editorial comment, as well, some to the effect that the
United States ought not to be able to dictate what might
be best for Canada. The reaction was similar to the
reaction when our own legislature passed a relatively
similar amendment.
The second thing I want to comment on is the two-pipeline
scenario. As many of you know, some of the Alaska
political leadership has advocated a two-pipeline
scenario believing that the construction of the southern
route followed by the Mackenzie route represents a
reasonable development scenario for both countries. In
recent times in Canada we've seen some media comment and
some of the political leadership saying, 'Yes, a two-
pipeline scenario is fine, but let's build a Mackenzie
Valley pipeline first to Alberta and then we can build
the Al-Can Highway and commercialize Alaska North Slope
gas after that. The feeling in that scenario is that the
Mackenzie Valley route involves sufficient reserves in
Canada and the ability of the Canadian governmental
process to control the permitting and construction. So,
it would be a reversal of what some Alaska interests
argued earlier.
A third issue is the linkage between ANWR and the gas
line. As most of you know, the official position of the
Canadian government is in opposition to ANWR and Canada
has been active from time to time back here in Washington
in expressing its opposition to ANWR. Some interests have
suggested to the Canadian political leadership that they
link the gas line and ANWR and indicate that they will
only support the commercialization of Alaska North Slope
gas if something to their liking can be worked out on
ANWR. Fortunately, we do not detect that that idea has
spread its roots. There has been a little bit of
speculation about it, but to our knowledge very few
people in the political leadership of Canada have been
willing to create that linkage. They would much prefer to
evaluate each project on its own merits.
Finally, just a couple of comments on the U.S.-Canadian
federal relationship, generally. There was an energy
summit between President Bush and Prime Minister Chretien
earlier on. They talked about the possibility of creating
a North American Continental Energy Task Force that would
include the United States, Canada and Mexico. There has
not been significant follow through there at high
political levels. We are aware that a bureaucratic task
force of U.S. agency people has met with their
counterparts in Canada, but that process has been going
on for years. To our knowledge, there haven't been
significant discussions either focused specifically on
the White House level or Prime Minister Chretien's level
in the aftermath of the summit they held. So, at this
point, our understanding is neutrality on the part of
Canadian federal government and on the part of the U.S.
government, the best indication of where the President
and Vice President stand is the very comprehensive energy
report that was issued by the Administration some time
ago where they directed the Secretary of Energy and the
Secretary of State to remain very much involved in the
pipeline issue and in the relationship between the U.S.
and Canada. With that, Mr. Chairman, I think I'll stop
for questions.
CHAIRMAN TORGERSON said he wrote a letter to Mr. Katz, which laid
out some questions, most of which had to do with FERC issues that
Mr. Loeffler would testify on. He asked if the over-the-top
legislation that Congressman Young had put in damaged our
relationship with our Canadian counterparts.
MR. KATZ answered:
I would have to say from the perspective here, there's
been no permanent damage. I think the Canadian leadership
is calculating all that in their own equation with
respect to the gas line, but we hear loud and clear when
Canada has problems with fisheries, ANWR, etc. While we
speculate and know that there is some heartburn with
that, it hasn't reached the same crescendo at this point.
Recognizing that you will be leading a delegation to
Canada, as well, I think you will get a sense for that
also. When the state administration was there some time
ago, the Canadian leadership did talk about the position
we have taken with respect to over-the-top, but they were
willing to move on to discuss the pros and cons of the
various projects generally.
CHAIRMAN TORGERSON asked Mr. Katz to comment on the producers'
legislation. At a meeting with the Governor's Conference in Juneau,
Charlie Cole asked him questions. The committee received that
transcript yesterday. He asked Mr. Katz why he thought the
producers' legislation favors a particular route over another and
whether it actually pulls provisions from the 1977 ANGTA and puts
them into the Natural Gas Act.
MR. KATZ replied:
Thank you for giving me the opportunity to comment and I
very much appreciated the comments that my friend and
colleague, C.J. Zane, said a couple of minutes ago. I
think we made three or four observations about the
producers' legislation and I'll very briefly summarize
them here. For one thing, I think the legislation puts a
significant amount of control in the producers,
themselves. The entities that control the natural gas
under their amendments have tremendous authority through
the regulatory process and in deciding generally what
projects to pursue. That comes out of the definition of
shipper in there and the fact that the producers control
the gas. Under the formulation in the producers'
legislation, the decision by FERC is made basically on
so-called market placed grounds - that is, they don't
have the authority under the legislation to adjudicate
between competing applications. They look at each
application in terms of three criteria. The first is
rates and charges and the second is control of the gas
and third is meetings, environmental and certain other
standards. If they make positive determinations on those
grounds, they must approve the application. The
application will be filed for the most part by the
entities that control the gas.
Then quickly there are three other things I would say
about it. The legislation in our judgment does not
preempt ANGTA 1976. That remains existing law, but the
producers' legislation would give the producers the
option of proceeding under their expedited process and
under the Natural Gas Act even with respect to the
southern route. So, the question arises, does Foothills
or the pipeline companies [END OF TAPE].
TAPE 01-12, SIDE B
MR. KATZ continued:
...With respect to the southern route, how would ANGTA of
1976 relate to this expedited process whereby Congress
under the producers' legislation would be creating
another process, which in theory could be applied to the
southern route, as well.
Secondly, the producers' amendments would allow the
application of the expedited process to any other
application for a route and project including the over-
the-top route. So, while they're proceeding under
existing law, which would involve a very difficult
regulatory process, the producers' amendments would allow
for an expedited process, less rigorous than existing law
would provide to some extent for a southern route. So, it
doesn't prefer a southern route, but it treats the
southern route for the purpose of the expedited process,
the same as ANGTA did with respect to the '70s southern
route.
It does, of course, modernize some of the expedited
processes. They are not precisely the same as the
processes in ANGTA. They reflect the thinking in 2001 and
then finally, we observed that there hasn't been the same
environmental review, which preceded the expedited
process for the southern route. So, you would applying
the expedited process with respect to the northern route
to a data base that has not been as fully developed as
the one for ANGTA. So, I think in those different
respects there are some similarities and some differences
between ANGTA and the producers' proposed amendments.
CHAIRMAN TORGERSON thanked him and said that Mr. Menge updated them
on congressional actions that may happen and of a hearing in mid-
September. He said the committee would have its regular meeting at
the end of September in Kenai, but he hoped to have another meeting
in Anchorage strictly on this legislation for that hearing. He
asked if he or the Governor had responded directly to the producers
about their legislation, yet.
MR. KATZ responded:
No sir. We are still in the process of analyzing the
producers' amendments on their own in relationship to
ANGTA and to the views of the political leadership in
Alaska and the Natural Gas Council. The Governor has
actually constituted a smaller group of us to complete
that analysis in relatively short order and be prepared
to advise him. That would all be the predicate to
participate constructively in the process that Mike Menge
described earlier.
CHAIRMAN TORGERSON asked if he had a timeline for responding to the
producers.
MR. KATZ replied that they don't have a timeline yet for responding
to the producers or to the Senate Energy Committee. They are aware
of the timelines of the Committee and that they won't be altered
for anyone, having imperatives from Senate leadership. "We are
probably well embarked on our internal process, not finished yet,
but we know the deadlines that are out there in terms of the
situation back here and we must be in a position to meet those
deadlines."
CHAIRMAN TORGERSON asked if he had seen Mr. Cole's proposal [Walker
Walker & Associates].
MR. KATZ said he hadn't had a chance to read it.
CHAIRMAN TORGERSON said he wanted his comments on it. He said at
the last meeting many heard him criticize the administration for
not working very closely with this committee. He said they had made
some "leaps and bounds" in trying to get along together, but Mr.
Katz went overboard in Washington, D.C. "Of any issue we should be
united on when we go before the Energy Committee, it's probably
this proposed legislation...."
MR. KATZ responded:
On the basis of everything I know I think the policy
objectives of the state administration and the governor
with respect to these various routes and projects are
quite similar and I pledge to you the same level of
cooperation from here as we ferret through this together.
Back in Washington, there are very few of us and a lot of
them.
CHAIRMAN TORGERSON said he wanted to continue with Mr. Katz and
that the Federal Energy Regulatory Commission had responded in
writing to the questions he sent them.
11:03 a.m.
REPRESENTATIVE DAVIES said he was also wondering if he had seen the
Walker Walker & Associates proposal and that he would be interested
in his comments on those as well as the producers' amendments. He
said he appreciated Mr. Katz's service to the State of Alaska over
the years.
MR. KATZ thanked him very much and said he would let Mr. Loeffler
answer that question.
Update on FERC Issues
MR. BOB LOEFFLER, Morrison & Forrester, an Atlantic law firm, said
he has represented the state's pipeline issues since about 1974. He
cut his teeth on the first version of the Alaska gas pipeline. He
had sent a nine-page letter to Senator Torgerson addressing the
committee's questions. He asked if that was received.
CHAIRMAN TORGERSON said that they received it and had it on the
back table along with FERC's response to his questions. FERC's
response is 50-pages, but 40-pages are the chairman's letter of
January 18 in response to Mr. Bingaman's questions. FERC responded
with a two-page letter to Senator Torgerson's questions.
It basically says that, 'A number of the questions raise
important policy matters that the Commission should only
address at such time as it is presented with applications
requesting particular approvals. Interested parties
should also have the opportunity to provide the
Commission with opposing points.' They're not answering
any of the questions is the short story....
MR. LOEFFLER said he would try to summarize his positions stated in
the letter:
I'll make one comment on FERC. The staff report - and it
is only a staff report - was issued in January on the
last day of the last Democratic Chairman of the FERC. In
Washington, we're now on our second Republican Chairman
of FERC since January. Several commissioners have been
replaced and we don't have guidance from the
commissioners themselves - staff turns over, general
counsel will turn over. So, while the January document is
a very useful document in laying out the pros and cons of
various positions, it is by no means the last word and,
in many respects, as the recent letter notes, they
haven't even reached conclusions. I hope I'm a little
better, but with the caveat that a lot will depend on the
exact shape of the application that comes before us.
My first point, and I think it's good to bear this in
mind, is that what FERC does and doesn't do for oil
pipelines and gas pipelines are vastly different. In oil
pipelines, FERC regulates only their tariffs and FERC
does not give oil pipelines permission to go into
business or permission to exit. In gas pipelines, the
Congress gave the FERC comprehensive jurisdiction over
interstate gas pipelines and that means that FERC has to
approve a new pipeline, the facilities for a new
pipeline, the environmental conditions that go with it,
as well as the tariffs. Similarly, a gas pipeline does
not go out of business without FERC permission. It's much
more hands-on intense regulation than you find in the oil
pipeline area.
Number two, FERC has been doing gas pipelines since 1938.
It is its daily business along with interstate
electricity issues. They really have taken that oil
pipeline regulation reluctantly. What that really means
in practice is they have developed a lot more law on
interstate gas pipelines, but of course, nearly all of it
has been developed in the Lower 48 context.
Number three, there is a special statute that everyone
refers to, the '76 ANGTA statute, and that created a
process that was designed to get a gas pipeline in
service by 1983. It's important to remember that that
statute is still on the books. Indeed, although there
were recommendations towards the end of the 1980s to
repeal it, Congress chose to repeal only two minor
aspects of it, which reinforces the argument that it is
still extant law, in some respect. The state has some
special rights under that statute that it should make
sure are preserved in any new legislation and we're quite
attuned to that issue.
Let's talk for a minute about the very important issue of
access instate to royalty gas, laterals instate, who
regulates the main interstate gas pipeline and who would
regulate laterals. I will start with the case before us,
which is the interstate gas pipeline, not an LNG project.
I will talk a little about LNG later - but an interstate
gas pipeline, which we believe should go along the
southern route.
Number one, the rights to charge for interstate service,
I think everyone believes will be set by the FERC. I
think at that point, it's important to note that based on
what happened in the 1970s and the division of
jurisdiction between Canada and the U.S. federal
government, there will be pipeline tariffs set by
segments. So, that there will be a pipeline tariff for
the Alaska segment, one for the Canadian segments and one
for Lower 48 segments. I know there is concern that
instate transportation could be burdened with costs
downstream out of Alaska. Under this division of tariffs,
that should not happen. Even inside Alaska, the last go-
round, we litigated for a result that would have Alaska
traffic pay only for the miles and volumes used as a
fraction of the total miles and volumes used in Alaska
and I think there's a very, very strong case that that is
the only fair result and meets the committee's concern
about Alaska gas traffic instate carrying only a
reasonable charge for its usage of the pipeline.
Number two, the Alaska Natural Transportation Act in
Section 13(B) gives the state the right to ship gas on an
interstate ANGTA project and to take the gas off within
Alaska, provided the royalty contract has that provision
and the FERC is ordered to issue all the authorizations
necessary to bring about that shipment and withdrawal and
its jurisdiction is limited to reviewing the fairness of
the rates charged for that shipment. Now that is a
feature of Section 13(B), not a feature of the Natural
Gas Act and I think it important for all our concerns
that those rights be preserved forever with respect to an
Alaska gas project.
There's a question, of course, in how the FERC would look
at a lateral serving Fairbanks or serving other instate
needs. Generally the FERC asked the question, on a
lateral, whether it is part of the integrated system -
that owns it, [is] it regulated by a state commission and
issues like that. Certainly if the lateral were owned by
a separate company from the main pipeline, I think there
would be a very strong case that the FERC would disclaim
jurisdiction and leave it to the Regulatory Commission of
Alaska. Even if you get to the other test, which is
integration with the main system, I think there's a very
strong case also that a lateral serving Fairbanks, for
example, is not part of the integrated interstate system
but they do apply factual tests there and it's not
absolutely clear.
In terms of the question of who would decide where a tap
would be on the interstate system for a lateral, I
believe that would be the FERC but I would point out that
Section 13, to my way of thinking, would require them to
establish a lateral or the tap for a lateral for royalty
gas and I would expect that the FERC, recognizing the
need, would be sensitive to creating laterals or lateral
taps inside Alaska. There is some very, very old law
that allows taps to be placed on interstate gas pipelines
for the benefit of landowners through whose land the
pipeline passes and the idea was farmers who would grant
rights-of-way and they could have gas for their farming
operations. I haven't seen that law cited for about 25
years but it's another basis for recognizing the equity
of allowing instate use.
That is the - quickly - the picture. I know that the
chair of the RCA is going to testify about the
jurisdiction of her agency and how they would set
tariffs. I would point out one aspect of pricing. In
the first go around in the 1970s, the U.S. government
regulated the wellhead price of natural gas. That
jurisdiction was withdrawn from the Congress. Back then
a lot of people felt that it acted to restrain Alaska and
others from receiving fair value for North Slope gas but
that jurisdiction has been withdrawn. The federal
government does not regulate the wellhead price of
natural gas. On the other hand, it's common for state
commissions, including the RCA, to regulate the price for
at least distribution of natural gas and the RCA may have
some jurisdiction over instate prices of natural gas.
I'm sure the chair will address that.
Now, there are questions about could the sponsors of a
project block taps for instate use laterals and the like.
Well, the short answer is you have to look at both the
Natural Gas Act and ANGTA because, as I mentioned, the
state has some pretty powerful rights under ANGTA but, in
any event, the FERC, unless its jurisdiction is modified
by Congress, has the power to require taps for instate
use even if the owners of a project would oppose it. Of
course it would look at why they're opposing it but they
would not control the game unless the jurisdiction of a
commission is modified.
On an LNG project, or an all-Alaska project, we look to
sort of a different point for federal jurisdiction and a
different kind of federal jurisdiction. I reviewed the
Yukon Pacific applications to the federal government in
the 1980s and later for authorization to export and at
that time the projects were very clearly premised on
exports outside the U.S. not coming back into the U.S.
and that gives the federal government a somewhat
different kind of jurisdiction under Section 3 of the
Natural Gas Act. And, what that means in practice is
that the Department of Energy authorizes the export on
certain terms and conditions and the FERC deals with the
export facilities, which [indisc.] the facilities at the
point of export, say Valdez, and on everything behind it
all the way to the Slope and so, in a sense, the pipeline
part of the purely export LNG facility is not regulated
in any comparable sense to an over-the-land route by the
federal government and any of its agencies. If, however,
the LNG comes back into the United States, then you have
the more traditional type of regulation.
And now, a footnote on that - two footnotes. One
footnote is Congress, in 1992, passed a provision which
no one understands involving LNG exports and imports
which limits, perhaps, the jurisdiction of the federal
government. It tells the federal government to just
issue the authorizations for import and export projects.
[Indisc.] this month, sponsors of a project in the
southern United States filed an application with the FERC
telling them why don't you disclaim all jurisdiction over
facilities at the point of import or export and it's not
been ruled on by the FERC but they cite this 1992
statute. Number two - footnote number two - if the gas
went out of Alaska and came back in California, we would
have a rerun of the old El Paso LNG project and then we'd
be dealing with Section 3 and Section 7 - our standard
FERC jurisdiction. If, however, the LNG project went
from Alaska to Mexico and then perhaps went to different
ownership in Mexico and then came into the U.S., it's not
clear what would happen there. At least the U.S.
government would have authority under Section 3, subject
to this new statute passed in '92, and I can't find a
precedent for that. I'll think more about it but I think
I know the LNG cases. I couldn't find a close precedent
for that.
Common carrier status - oil pipeline TAPS is a common
carrier. Gas pipelines are not common carriers. The
FERC, in the late 1980s, went to open access principles,
which are intended to prevent the owners of a pipeline
from favoring affiliated merchant enterprises, which sell
gas that will be shipped on the line. They don't want
interstate gas pipelines tying up capacity to favor the
other half - their production affiliates. There's a lot
of law in that, one spin out of this general open access
concept is that the FERC expects new gas projects to have
an open season in which they entertain applications for
shippers to sign up for a period of time and they use
those sign ups to help sell the project to the financial
community and also it shows the need for the project.
But there is no common carrier status of gas pipelines,
which does raise fairly the issue of owners of the
pipeline entering into arrangements, which could tie up
access to the pipeline for a long time.
Now the open season idea, which is more a policy than a
requirement. If you search through the requirements for
new pipelines, you cannot find today a requirement for
open season but the FERC has said in specific cases that
they expect open seasons for new facilities. But,
anyway, the policy is intended to deal with issues about
tying up capacity to the detriment of future shippers or
competitors. We did a quick run last night and we found
700 different rulings on this from the FERC, so it is not
a simple area. Any project the size of the Alaska gas
pipeline is going to get Department of Justice and FERC
scrutiny. Nevertheless, I think there are valid concerns
about how the open season will operate.
Because I'm running fast on my time, let me take that up
very quickly. If the sponsors of the project are not yet
a natural gas company, the FERC does not yet have
jurisdiction so you could conceive of a situation where
sponsors of a project under a new corporate name would
have an open season and they would set the rules as they
wish and then the capacity would be tied up. If they
were already jurisdictional by the FERC, people would
complain immediately about unfair provisions. In the
situation where they're not yet jurisdictional by the
FERC, anyone would know that these issues are going to
come back before the FERC at a later date and they ought
to act to comply with a fair and nondiscriminatory
provision of FERC rulings in their open season but there
might be a remedy at the instant, as opposed to later, on
that. That's an issue deserving of close scrutiny. On
the other hand, if their future shippers will want
capacity reserved for them or want to make sure the FERC
will be attuned to them, I think in the regulatory
process there's precedent at the FERC that capacity not
be tied up for future shippers and that it be fairly
priced for future shippers.
Let me address for a minute the upstream access questions
beyond the open season issues and there are a couple of
points worth making. Now when Congress, and I believe it
was President Reagan, signed in - but when Congress
passed waivers of law submitted by the President, the
conditioning plant was included within the pipeline
system under ANGTA. A couple points there. Number one,
conditioning plants would not normally be included. Now
there's a benefit to their inclusion, which is you get
the expedited permitting and judicial review and there
was a benefit then that doesn't exist anymore - a second
benefit, which was for pricing purposes when the federal
government then priced natural gas, you could get an add-
on for the conditioning costs. Of course, that's gone by
the wayside. It is not clear what the right result
should be for a new gas pipeline. There may be more than
one conditioning plant, for example. There may be issues
under the state lease and even an RCA jurisdiction over
conditioning plants and, insofar as I know, the
administration does not have a position yet on whether
the conditioning plant should stay as part of the main
transportation system or should - the pipeline should
start at the exit of the conditioning plant.
Some of the issues that are identified in your letter
about access to, for example, the conditioning plant by
new users in the future, remind me of a number of issues
that the state and the commissioner of natural resources
is, in particular, trying to address in the context of
the BP/ARCO merger where there were issues about access
to field facilities and there were some provisions, I
recall, dealing with that.
Having raced through everything I think I will stop for a
minute. I think I'm right on the dime, in terms of time,
and ask if there are any questions.
CHAIRMAN TORGERSON asked Mr. Loeffler if he covered the question of
whether the NGA or ANGTA prevails.
MR. LOEFFLER said he did not, but he covered it a little bit in
writing. He stated the answer is that no one knows. They are both
on the books and the only way that question can be definitively
resolved is through legislation or ultimately, a Supreme Court
ruling. He noted that he commented, in his memo, that while the
ANGTA statute is on the books, at the time it was passed, no one
thought it would be dealt with more than 20 years later. He
pointed out, with both the presidential decision and the treaty,
that the Northwest Project was expected to be in service in 1983.
It is operative because it is on the books. He suggested the best
one could do to answer that question is to look at the January 18
FERC staff report, which weighs out the pros and cons.
CHAIRMAN TORGERSON stated that he believes it was the 1982
amendment that allowed the producers to have part ownership in a
pipeline, but they had to prove that their participation did not
violate anti-trust laws. He asked Mr. Loeffler to comment on that.
MR. LOEFFLER said he has several comments and provided the
following history. When the president's decision was in draft
form, the then commissioner of the Alaska Department of Revenue
objected to the banning of the producers on various grounds but,
essentially, on economic grounds. At that time, it was thought the
producers' financial support, more than debt guarantees, was
necessary to build the project. Sure enough, three or four years
later, when the financial needs for the project were so great, they
came around to that and the waiver of law was passed. He recalled
the waiver of law said the Department of Justice had to rule that
the producer participation would not establish a condition
inconsistent with the anti-trust laws. That was a standard used by
the Nuclear Energy Regulatory Commission and never fleshed out. At
that time, they were looking for 30 percent producer participation
in the equity of the project and in debt guarantees. The gas
pipelines were financially weak compared to the producers. The
concern of the producers at the time was that their 30 percent,
plus cost overruns, could become a higher percentage. Mr. Loeffler
said he thinks there are valid concerns about ensuring that a
project is built, which will require the backing of people with the
financial wherewithal. Mr. Loeffler said he also believes the
state has a counter concern that those who own the pipeline do not
lock it up against independent producers and future shippers. He
expects the state, FERC and Department of Justice to take a very
close look at the open access requirements.
CHAIRMAN TORGERSON asked who would make the anti-trust decision.
MR. LOEFFLER replied it is a double standard. The FERC looks at
anti-trust issues but does not apply the anti-trust laws so anti-
trust concerns are one of the elements of the public interest
determination that the FERC makes. Separate from that, the
Department of Justice will look at that question and has its own
ways of enforcement.
CHAIRMAN TORGERSON referred to page 26 of the transcript of the
meeting in Juneau [August 2, Alaska Highway Natural Gas Policy
Council], and asked if the committee could get copies of Phillips'
proposed amendments to the federal fiscal regime.
MR. KATZ said he would prefer that Phillips explain its own
proposal but said it is fair to say that Phillips' current thinking
is divided into two parts: one is accelerated depreciation for
construction costs. Accelerated depreciation is an issue that has
been framed in some of the pending national energy bills in
Washington, D.C. so he believes that will be discussed as a generic
nationwide issue. Second, Phillips has requested a provision that
deals with a floor on price and remedies that might apply if the
price of natural gas goes below a certain level. He pointed out,
in the context of the pending federal legislation, there had been
proposals to deal with a production tax credit. One proposal
introduced by some democratic members would tie it specifically to
the southern route. Phillips' proposal is route-neutral. He
offered to contact Phillips in Washington, D.C., relay the
Chairman's request, and allow Phillips to establish a direct
relationship with the committee.
CHAIRMAN TORGERSON thanked Mr. Katz and noted a representative from
Phillips would be presenting to the committee that afternoon.
MR. KATZ informed the committee that the [U.S.] Senate Energy
Committee has jurisdiction over all of the issues he discussed
except the tax regime, which is under the purview of the Finance
Committee. That will undergo a separate process and it is not yet
clear how that will relate to the federal energy legislation under
consideration by the Senate Energy Committee. He added that of the
many tax proposals floating around, some do involve the development
of transportation of natural gas so he expects those issues to get
a fair hearing as well.
CHAIRMAN TORGERSON noted that he plans to request of the producers,
Foothills, the administration and of the committee's legal advisors
that each provide sectional analyses of that section. That
information will be distributed to committee members in advance of
the next meeting so that the subject can be discussed then.
TAPE 01-13, SIDE A
REPRESENTATIVE DAVIES stated that at the committee's last meeting
he was pretty dissatisfied with the responses of FERC officials
relative to the open season question. It seemed they were willing
to accept a market-driven imperative for open seasons that would
happen later than the initial open season. He noted Mr. Loeffler
indicated that open season decisions, with respect to FERC, were
set more by policy than law and that FERC has made over 700
rulings. He asked if the rulings were about open seasons at the
initiation of a pipeline or on point for continued access. He also
asked whether Alaska should consider codifying some of the open
season principles in the upcoming law.
MR. LOEFFLER stated that there are rulings for new pipelines, for
expansion of existing pipelines, and rulings in the life of a
pipeline as capacity becomes available for the first time regarding
how capacity should be allocated between users and new users. So,
essentially, there are definitely rulings that deal with "later on"
in the life of a pipeline. He said the question of whether Alaska
needs a particular expression of non-discriminatory access or fair
access for all shippers is an active "hotplate" of consideration,
including the question of whether that expression should be placed
in legislation.
REPRESENTATIVE DAVIES said that he is interested in being kept
abreast of that discussion because his impression is that the FERC
players are not very concerned about that.
MR. LOEFFLER said that as is often the case in Washington, D.C.,
they may need a little education and to be sensitized to the
particular concerns on an Alaska gas pipeline, which is part of his
job.
CHAIRMAN TORGERSON commented that a lot of the open season
questions came from some of the smaller producers that are active
in Alaska. He hopes they will have an opportunity to review Mr.
Loeffler's or Mr. Chenoweth's legal opinions and make
recommendations for congressional action prior to the next
committee meeting.
REPRESENTATIVE FATE remarked that he noticed the producers, in
their proposed bill, say in Section 3 that they would establish a
federal pipeline director position. He asked Mr. Loeffler if he
sees any problem with that relative to the state regulatory
business.
MR. KATZ said he does not know yet. He explained that everyone
sees the need to coordinate the activities of the various federal
agencies and ANGTA of 1976 provided for a federal pipeline
inspector and a very large staff that was designed to provide
coordination and communication among agencies. That administrative
authority now resides in the Secretary of Energy, himself, because
the office of the pipeline inspector no longer exists. He
indicated there are three possible alternatives now on the table.
One is to do what the producers suggest, which is to create a
position in the White House subject to Senate confirmation. The
second is to revitalize in some form the office of the pipeline
inspector. The third would be an alternative implemented by
administrative action. He informed the committee that currently, a
bureaucratic task force of federal officials meets periodically to
discuss pipeline issues but that task force has not moved very far.
He said he believes that everyone who is familiar with the federal
process feels the need for coordination in order to accelerate
pipeline consideration. Exactly what form that will take is still
unclear.
REPRESENTATIVE FATE said it sounds like this position would be more
permanent and would be applicable to other pipelines.
MR. KATZ replied:
It certainly could be. I think that the producers
probably intended that it apply specifically to the
commercialization of North Slope natural gas but there
are some general provisions in some of the pending
national energy bills that refer to a need to coordinate
generically and nationwide with respect to these kinds of
projects. One bill, for example, provides for a formal
memorandum of understanding process so it might well be
that as the Congress looks at this, if they decide that
it's a good idea in one circumstance, they might seek to
apply it more generically.
REPRESENTATIVE OGAN noted that at the last hearing, FERC officials
said they regulate from the wellhead on down if gas is shipped to
the Lower 48. He asked Mr. Loeffler if a statutory scheme could be
designed where the wellhead is moved farther down the line
statutorily, to delineate state and FERC regulation at that point.
MR. LOEFFLER explained that the Natural Gas Act was adopted
following a Supreme Court ruling that suggested that production and
gathering were inherent subjects for state regulation and that
interstate commerce, in a sense, began with the transportation of
natural gas out-of-state. Regarding whether FERC jurisdiction has
been carved back voluntarily or otherwise, to appoint further into
the process, the closest analogy one can come to is the Gulf of
Mexico regarding the distinction between production and gathering
and transportation. Second, Congress only has the power to define
where federal jurisdiction begins. He can see some constitutional
problems regarding figuring out what is interstate commerce and
what is not. Congress could move the FERC jurisdiction point
farther south but he doesn't know whether that will solve all of
the problems that the smaller and independent producers see because
of the question about access to the conditioning plant, before the
gas gets to the pipeline. He said it may not be subject to
regulation by anyone and moving the point of jurisdiction south
really doesn't address the first issue. He noted that is one issue
in his opinion that he said he will have to think more about.
REPRESENTATIVE OGAN asked Mr. Loeffler for the name of the Supreme
Court case.
MR. LOEFFLER agreed to provide it to the committee at a later date.
There being no more questions, CHAIRMAN TORGERSON thanked both Mr.
Katz and Mr. Loeffler. The committee then took a short recess.
11:06 a.m.
Update from Regulatory Agencies
CHAIRMAN TORGERSON called the committee back to order. He informed
participants that he submitted the same list of questions to Mr.
Loeffler, FERC, and others and copies of their responses were
available at the back of the room. He asked Ms. Nan Thompson, to
address the committee.
MR. NAN THOMPSON, Chairwoman of the Regulatory Commission of
Alaska, informed committee members that the purpose of her
testimony is to answer questions posed to her in a letter from the
committee dated July 23. She offered to later submit those answers
in writing.
MS. THOMPSON noted the committee's letter expressed frustration
about the answers it received during the last hearing. She pointed
out that the committee asked great questions, but those questions
do not necessarily have black and white answers. She stated that
if her answer is not solid, it is not because she is trying to be
ambiguous, she is being honest. She believes it is important for
committee members to understand the "lay of the land"; where things
are clear and unclear so that members can make the best policy
decisions.
MS. THOMPSON'S testimony is as follows.
The first section of the letter asked questions about
jurisdiction. It was entitled Background and I'm going
to use this opportunity to throw in a couple of prefatory
comments myself, which is, the letter seemed to - seemed
like at the last hearing there was some awareness dawning
that oil pipelines are really regulated under a very
different legal regime than gas pipelines therefore the
state's experience with TAPS, our large interstate oil
pipeline where we concurrently regulate with FERC, isn't
necessarily the way this line's going to be regulated.
I think it's also important to understand that all of the
federal law on gas pipelines was developed in the Lower
48 and it was based on policies that may not apply here.
This is really the first interstate gas pipeline that's
come from this state and we're different. We're an
island. A lot of the legislation that's been developed
on a federal level in the Lower 48 is based on facts that
are very different here. For example, the current
regulatory scheme that allows contract carriage, or open
access as they call it now, is based on an environment
where there should be an option, not on one where there's
only one pipeline that leaves the state. In the Lower
48, a producer may have several alternative routes to
market so it doesn't necessarily matter that the product
gets on a specific line. But, nonetheless, the federal
regulatory regime, the policies supporting, recognizes
the importance of preventing pipelines from being used as
a tool to discriminate against shippers so I would urge
caution about how the current federal law on gas lines
may or may not be applied here and I think, what I heard
briefly when I joined this group a little earlier this
morning, was discussion about changes in federal
legislation. I think that, in order to develop clarity
in this situation, is the way to go. I wouldn't assume
that it can't be changed because in order to affect the
same policies that the Lower 48 law does here, it may
have to be different up here because of our geographic
location amongst other things.
It's also important to understand - and you probably are
well aware of this by now - that which federal law
applies to this pipeline and how it applies isn't clear.
ANGTA was passed in the late '70s, and it gave from a
regulatory perspective, it gave remarkable powers to the
President to pick the route. But the pipeline that
legislation anticipated wasn't built and the deadlines in
the Act have passed so only the courts or the Congress
can sort out what it really means and how it applies to
this particular situation. The significance of that is
ambiguity in law creates a potential for litigation. It
creates a potential for posturing and delay so any of the
parties who have varying interests in one route or the
other can hire a stable of lawyers and spend years trying
to clarify the ambiguities, or at least threaten to. The
alternative to that is a route that would work through
the federal legislative process to clarify some of the
ambiguities in the law.
The only other background comment I have is about the
track record that FERC and the RCA have. We have
concurrently regulated TAPS over its years and we have a
track record of cooperating to do that. I don't have any
reason to believe that that cooperation isn't going to
still continue. We have a - our relationship with that
agency has changed as the head of the agency has changed,
but I'm confident that the group that's there now is
going to be sensitive to the state's concerns and is
going to work well with my regulatory agency. It is not
a turf battle between FERC and my agency. We have
different concerns. My agency is worried about instate
access and instate rates, and FERC is concerned
principally with the interstate shipment and responsible
for making sure that nothing we do within the state
interferes with interstate commerce but I think, within
those parameters, we can work well together on this
problem.
The first question was about state access for instate
demand and it was: What would the FERC and the RCA's
jurisdiction be over a pipeline along the Alcan route?
The RCA - my agency has jurisdiction under the Alaska
Pipeline Act, a state law, to regulate intrastate oil and
gas pipelines and state law also says that we have
jurisdiction over interstate pipelines to the extent that
we're not preempted. On the federal side, I know you've
heard from Mr. Loeffler and others this morning about the
Natural Gas Act. FERC has jurisdiction over all
interstate pipelines and under the Commingling Doctrine,
if there's one molecule of gas that's transported
interstate commerce it's an interstate pipeline. So, at
first blush, the Al-Can route, carrying gas to Chicago,
would be regulated by FERC but there's ANGTA and its
impact, again, is not entirely clear. Section 13(B) is
the one provision of ANGTA that I think is most important
to focus on here. That gives the state the right to ship
its royalty gas - to use its royalty gas - within the
state of Alaska. It gives the state the right to go to
FERC and say we want to take our share and use it in
Alaska and it requires FERC to accommodate that. The
language - it's one of those paragraph long sentences
that drive me nuts - but I think it could be interpreted
either way. I would argue that it gives the state the
responsibility for setting rates for that intrastate
shipment subject to review by FERC. But, again, that's
one of the ambiguities that would be nice to clear up in
order to avoid some type of litigation over that issue.
I think [Section] 13(B) of ANGTA has another important
provision when you're considering instate access and that
authorized that - 13(A) - I'm sorry - that prohibits the
operator of the gas line and if it's also a producer,
from discriminating against others who want to have
access to the line. So Section 13 of ANGTA, as it now
exists, is very important for delineating state's rights
and protecting state's interests in using gas instate. I
urge you, if you review any of the drafts now circulating
for changes to ANGTA, to look carefully and see what they
say in terms of provisions comparable to the current
Section 13.
The one thing that's important to note is that ANGTA now
requires an instate delivery point just for the state's
royalty gas. So, if the state - if there's other
producers who want their gas to be used instate, they
would have to be protected by another means or perhaps
through this legislation. And I imagine what would be
required of the state, in order to exercise this
privilege under ANGTA, would be some demonstration of
ability to use, or plans to use, its gas instate. I
think under those circumstances it would be very
difficult for FERC to deny an access, even on a FERC
regulated pipeline within the state.
The next question was about generally - a series of
questions - about regulation of instate tariffs and
prices. Under the Natural Gas Act, FERC would set rate
for instate delivery points on a pipeline from the North
Slope to Chicago. Again, under ANGTA, the answer may be
different. It's arguable under that law the RCA's
responsibility is subject to FERC's review for
reasonableness, if the gas taken at those instate
delivery points is state royalty gas.
When we set pipeline rates, we operate under the Alaska
Pipeline Act, again, and we're required to set just and
reasonable rates. Our case history says that means rates
based on cost. So, there isn't one tariff methodology
that we consistently approve. There's a number of them
and what actually happens most of the time is the
producers and the other interested parties negotiate a
settlement and they come to us for review of that
settlement. They resolve issues like how quickly the
pipeline will be depreciated; how DR&R funds will be
accumulated; how the rates change according to different
take-off points. We review those when we come in, again,
to insure that they're just and reasonable, that the
interests of future shippers, as well as current, are
protected and the public interests are protected. But,
we look principally at the cost of delivering service,
Just like any other utility regulation, they're only
allowed to charge their customers what it really costs
them to deliver the service so I can't tell you that
there's one pipeline methodology that we use but it's
generally cost-based and the history on pipelines in this
state is a series of settlements negotiated between
producers and shippers that we've reviewed and approved
as appropriate. What we do when we get them, if we have
questions, we have a hearing, we ask, require further
filings, sometimes negotiate other modifications but
generally they've all been approved that way.
Regulation of an all-Alaska pipeline - there was a series
of questions under this that talked about a hypothetical
pipeline to Valdez and shipments to Mexico and back or to
California via Mexico. Basically, FERC would have
jurisdiction over a pipeline to Valdez if that carried
export gas. The federal government regulates export
pipelines. There are different agencies that are
involved. I think Mr. Loeffler probably hinted on that a
little but it doesn't matter - it's the federal
government, it's not us.
Our jurisdiction is influenced by a couple of different
factors. If there's a pipeline that begins and ends in
the state, that's an intrastate shipment, that's within
our jurisdiction. Other factors that are important are:
what gas is taken off? Under ANGTA, it matters. Our
jurisdiction is influenced by whether or not it's the
state's royalty gas taken off. I think also what type of
processing or handling is done to the gas that changes
its character might influence our jurisdiction.
Last, and this is a difficult one to articulate, but
where the decision is made to ship the gas out of state.
I'll give you a hypothetical to try and explain what I'm
thinking of. I've been asked a lot about, well what
about if - and I think I heard Representative Ogan talk
about it, moving the wellhead down. The hub concept - in
order for us to have jurisdiction over the pipeline to
the hub, assuming that all the very, very complex
economic and processing issues are resolved, there isn't
really any direct analogy currently. The letter talked
about the Gulf of Mexico case but this is really the
reverse. In the Gulf of Mexico, the feeder lines, or
gathering lines, they go into a central facility and go
out. In this case it would be one line coming out and
then splitting out theoretically so, if there was a
pipeline from the North Slope that went to a center - and
I'll say Fairbanks because that's where I'm sitting today
- and in Fairbanks there was some kind of trading center
and gas went either through an LNG line to Valdez for
export or was sold to a local petrochemical facility for
processing or sold to a local utility to generate
electricity or shipped on a pipeline route through Canada
to the Lower 48, then I think we'd be in a situation
where there would be a better reason to argue that at
least that first segment of the pipeline could be
regulated intrastate. Again, it depends on how the
project is set up and designed. That's not inconceivable
but there isn't, like in response to many other questions
you asked, there isn't really a clear path on that.
The next section talked about regulation over hubs. I
think I explained why the Gulf of Mexico example isn't
really analogous because it's an opposite. The question
also talked about spur lines. It's true that any line
that went off of a main pipeline that transported product
to somewhere else in the state, to a utility or to a
processing plant from an off take point, would be
regulated by the RCA. This is another area where it
would be helpful to have clarification over the federal
law if that's what the policy makers decide is the
objective, to have where our jurisdiction begins and ends
and whether or not - I'm not sure it's a good idea to
have us regulate the rates down from Fairbanks but if it
is, that's an area where some clarification of federal
law defining what a hub or a training center or where the
jurisdiction begins and ends, would be helpful.
Regulation as common carrier - that was the next series
of questions. The letter asked if I knew of any gas
pipelines that FERC now regulates as common carriers. I
don't but remember, again, that the Lower 48 pipeline
regulatory scheme was based on a different market
structure. You've got a network of pipelines going all
over the place. In a world where shippers have other
options, the concept of common carriers that's so
important to us, isn't as important. This is going to be
a bottleneck facility, at least for the foreseeable
future therefore I think there's very strong public
policy reasons why common carriage, or some other scheme,
it doesn't matter if you call it common carriage or open
access, some scheme to ensure that there's non-
discriminatory access to the line by producers, any
producer that has product to ship is important. And
that's something that could be best resolved through
federal legislation.
The danger of a contract carriage pipeline is that it
would allow the producers, or some subgroup of them, to
control whose gas got to market. From my perspective,
that's unacceptable for a couple of reasons. The state
as a royalty gas owner is going to want to get its own
gas to market and may be left out of that scheme. Also,
as the owner of lands from which the gas resource is
developed, I'm sure we'd want to encourage development of
our gas resources. ANGTA, again, Section 13(A) talks
about - prohibits discrimination against shippers that
don't own an interest in the pipeline and that type of
model - if there's going to be modifications to that law,
bringing that principle forward I think would be very
important.
It's also worthy to note, when we talk about state
regulations to influence who gets their product on the
line, what some other states have done. In Texas,
they've used some of their right-of-way access procedures
to require pipelines to be common carriers. I know that
provision is in some of the state leases. I have no idea
whether it's in any of the leases on any of the proposed
routes folks are talking about, but that's another option
for the state ensuring that all producers have access to
the line. Another option to think about is the one
similar, perhaps, to what the legislature crafted a few
years ago on HB 290. I know some of you were around for
that effort. There, it was an export gas pipeline at
issue. What happened in the end was a balance.
The problem was the pipeline owners needed firm
commitments in order to obtain financing for the pipeline
and there were users in-state who were not able at that
point in time to make the long term commitments. So,
what the legislature did was carved out, or designated, a
section of the line that would be regulated as a common
carrier and gave the RCA responsibility when the pipeline
project began to come on line for defining how big that
slice was going to be and regulating that one piece of
the pipeline so that in-state users would have access.
That pipeline was never built but that's another - and
that concept is untested but that's another option,
perhaps worthy of consideration if we're thinking about
how the interests of in-state users could be protected.
I don't know of any other precedent for that type of
scheme on a national level. Again, TAPS was - and how we
regulate TAPS concurrently with FERC, was the original
model for that. The thought there was that - again, our
role on TAPS is to protect the interests of in-state
shippers so they pay fair rates even though there's much
more pipeline beyond where they take off.
The next series of questions was about regulation under
the Natural Gas Act, or ANGTA, and it asked about FERC
applications. FERC is really the appropriate agency to
comment on how it's going to handle applications. They
have a statutory obligation to process applications and I
understand that their response today was until the
application was filed they're not able to say a lot. As
frustrating as that may be, that makes sense from a
regulatory perspective. What they're going to be faced
with is sorting out whatever legal challenges are filed
to whatever application they get. The answers are
different depending on the particular application. But
I'd suggest that if the goal is a smooth process at FERC,
that the best model is for all of the interested parties
to sort out their differences and go together to FERC
with an application. That's the model we've seen in our
pipeline cases and I know FERC does the same thing, or
experiences the same thing. It's when the parties are
able to negotiate, all the interested parties, again if
they're not all at the table it's FERC's role to make
sure that their interests are protected, but the best
model is for folks sorting out their differences before
they get there.
On upstream access, I'm not well versed on the first and
open season process but many of the concerns about that
process expressed in the letter are whether the producer
owned pipeline [is] valid. My agency's goals and
priorities are in-state access at a reasonable cost and
that's based on my knowledge and experience with what it
costs to generate power in the state and how it might be
very helpful to have some of this gas to reduce that
cost. I would caution that the cost of constructing a
pipeline is really what's recovered in the transportation
rate so that if you're evaluating alternative routes or
alternative options, whatever minimizes construction
costs is really important. I think I saw a statement in
the press by producers to that effect and I would agree
that minimizing costs is important, although I may look
at costs a little differently. The incentives that they
have to keep construction costs low are different than an
independent pipeline company might have or another owner
and that issue is significant when you're talking about
keeping tariff rates low enough that in-state users can
have reasonable access.
I think the state, in summary, has legitimate interests
in the connection with this pipeline that will be heard
and appreciated at FERC. We have interests in ensuring
state access and use of our gas in-state. We have
interest in getting our gas to market, if that's what we
choose, and a strong interest in pipeline safety. And,
any pipeline permitting process that doesn't take those
interests into account is not likely in the end to be
successful. That's the end of my answers to the
questions posed in the letter. I'd be happy to entertain
more questions. I saw some scribbling up there so I
suspect I'm going to get ....
CHAIRMAN TORGERSON asked Ms. Thompson if she could suggest any
legislation the committee might consider to make the RCA's job
easier.
MS. THOMPSON replied not on the state level because her focus now
is to clarify the federal law, which would benefit all parties if
this project is to move forward.
CHAIRMAN TORGERSON asked Ms. Thompson if she has had a chance to
review the producers' draft legislation.
MS. THOMPSON said she briefly looked at it but has not analyzed or
studied it. She offered to provide specific comments if the
committee so desired.
CHAIRMAN TORGERSON indicated the committee would be interested in
her comments. He informed her that the committee plans to meet in
September for the sole purpose of discussing the producers' draft
legislation. He also said he would provide Ms. Thompson with a
copy of the proposed legislation provided to the committee by
Charlie Cole. He commented that it looks like some fix is
necessary on the federal level and that the committee should
provide suggestions for changes to the federal law and her
expertise would be welcome.
REPRESENTATIVE DAVIES asked Ms. Thompson to expand on her comments
about the need for clarification of the federal law in a memo to
the committee.
MS. THOMPSON agreed to do so.
REPRESENTATIVE DAVIES noted that Ms. Thompson stated that an export
pipeline would be federally regulated but he thought Mr. Loeffler
said that FERC would regulate the export facility. He asked for
clarification.
MS. THOMPSON said she did not hear Mr. Loeffler's comments but it
is her understanding that an export pipeline would be regulated by
FERC or the U.S. Department of Energy. She repeated that [HB] 290
pertained to a case in which some of the gas would be used in-state
so the rates for that portion of the gas would be set by RCA, but
the RCA would have nothing to do with setting transportation rates
for gas sent out-of-state.
11:33 a.m.
CHAIRMAN TORGERSON recalled something he read that said if the port
authority concept went forward or if the pipeline was state owned,
it would not come under FERC jurisdiction. He asked Ms. Thompson
to comment on that.
MS. THOMPSON said she honestly does not understand that concept
well enough to comment.
TAPE 01-13, SIDE B
CHAIRMAN TORGERSON noted that he posed a series of questions to
that group to answer at their presentation that afternoon.
SENATOR KELLY stated that at the last meeting, the committee talked
and heard about FERC jurisdiction if a single molecule of gas was
exported or transported to the Lower 48 and it was his
understanding that RCA would not be involved if that were the case.
He asked Ms. Thompson if her opinion differs since she said that
gas for use instate would fall under the regulation of the RCA. He
asked if she meant from a hub transported to a community in Alaska
or for royalty gas - under what circumstances RCA would be
involved.
MS. THOMPSON said the committee walked away with the right answer
under the Natural Gas Act but the question is: What does ANGTA mean
and what impact does that piece of legislation have on the answer?
The one molecule concept falls under the Commingling Doctrine,
which falls under the Natural Gas Act. That came about because
creative state regulators and creative pipeline companies were
building pipelines to avoid certain state boundaries so federal
regulations were imposed because it didn't make any sense. Alaska
has different factual circumstances. She believes it is arguable,
although it is not clear, under ANGTA, that the state would have a
role in setting the rates under which its gas is transported in-
state. If, under ANGTA, Section 13, the state exercises the right
to take its royalty gas in-state, then the language of that bill
could be construed to give states the right to set the rate to that
off-take point for state gas. She repeated that applies only to
royalty gas.
SENATOR KELLY asked if Ms. Thompson was speaking only to setting
transportation rates to the off-take point.
MS. THOMPSON said that is correct; she was only speaking about
transportation.
SENATOR KELLY asked if "to the off-take point" means to the point
where the end purchaser purchases it or to a hub where it is then
transported from the big pipeline to the communities of the state.
MS. THOMPSON replied:
To the point where it leaves the pipeline and the end
user - I guess there's a number of different scenarios.
If it goes, for example, if there's a spur line that goes
out of Fairbanks down to the Kenai area, then we would
regulate the spur line clearly because that's an
intrastate pipeline. We may, under ANGTA, regulate the
rates that folks who were the end users in Kenai pay for
the portion of transportation between the North Slope and
wherever the spur line starts off the big line. That's
the ambiguity, whether or not ANGTA means that we have
some say in what they pay for their share of shipment on
the big line.
CHAIRMAN TORGERSON asked if that answer differs depending on
whether the application is filed under the Natural Gas Act or under
ANGTA.
MS. THOMPSON asked Chairman Torgerson if he is speaking about the
application that has already been filed when he referred to the
ANGTA application.
CHAIRMAN TORGERSON said yes. He noted the 1977 law clearly
provided for access in-state.
MS. THOMPSON agreed.
CHAIRMAN TORGERSON stated, "NGA doesn't, except for what we heard
earlier, is for some farmers, so we're going to make folks in Delta
happy maybe, if it crosses their property but, you know, what about
everybody else?"
MS. THOMPSON responded that not having looked back at the original
application, she is uncomfortable providing a definitive answer.
She said if Chairman Torgerson is asking whether the RCA has any
control over the in-state rates under either piece of legislation
and whether it makes a difference whether it was the original
application or another one, she guessed the answer is probably no.
She noted this is an area that should be clarified if federal
legislation is passed - that the state has the right to set rates
for gas that's taken off and used in the state and the federal
government can do everything else.
CHAIRMAN TORGERSON asked Ms. Thompson if she has, "any
recommendations that would stop us from chasing our tail and get to
some real answers?"
MS. THOMPSON said she shares the Chair's frustration about having
to absorb a lot of information. She stated in an ideal world, she
would like to see a unified state position that the state could
take to the table to negotiate with the entities that will build
the line. That would enable RCA to better protect the in-state
users. She said she doesn't think anyone has the answer yet, but
anything the committee can do to encourage a unified position would
be helpful to the RCA.
CHAIRMAN TORGERSON thanked Ms. Thompson and asked representatives
from FERC to testify. He noted that he distributed the 40-page
letter to the committee from Mr. Chamblee [dated August 14, 2001]
and the short letter that said FERC did not want to answer any
questions until it received an application.
MR. JOHN KATZ, Director of the Office of Energy Projects, FERC,
informed the Chairman that he noted the concern expressed in his
letter regarding the responses provided by FERC officials at the
last meeting - that the responses were given in the context of the
NGA and not to ANGTA. He explained that FERC officials were trying
to answer the questions as they understood them but no one at FERC
has an expressed preference or negative sense about whether an
application could or should be filed under ANGTA versus under the
NGA. Those statutes coexist and it will be up to the applicants to
decide what they want to file under. The bottom line is nothing
that FERC officials said was intended to cast aspersion on ANGTA or
to express a preference. Second, while FERC officials want to be
as forthcoming and helpful as possible, it is hard to answer all
questions in detail before an application is filed because so much
depends on other factors. FERC will first need to know what is
being proposed and who is asking for what authority, etcetera.
Finally, the questions are also difficult to answer because FERC is
an independent regulatory agency with five commissioners who vote
on matters of law and policy so staff can provide the standing of
the commission's policy and what the commission has done in the
past, but staff cannot predict what the commission will do. He
said he totally agrees with Chair Nan Thompson that an Alaska gas
pipeline proposal is a matter of first impression here and that the
ANGTA certificate, which never became a final certificate may pose
policy and legal issues that the FERC has not dealt with because of
the unique circumstances in Alaska. He said staff does not want to
mislead anyone by suggesting that FERC might reach a particular
decision.
MR. KATZ said that Nan Thompson's answers to the committee tracked
the best answers he could give the committee. He said he agrees
that Section 13 of ANGTA does contain a provision regarding the
transportation of royalty gas and the NGA does not address that.
That doesn't mean such a thing couldn't occur under the NGA. In
regard to the rates that would be charged for such a service, Chair
Thompson spoke on that point. He clarified that Section 13(B) says
the State of Alaska is authorized to ship its royalty gas. The end
of that section says the commission [FERC] shall issue whatever
authorization necessary, "subject to review by the commission only
of the justice and reasonableness of the rate charge for such
transportation." He repeated that this is hypothetical because no
gas has ever been transported pursuant to ANGTA but a plain reading
of that section suggests that the FERC would at least need to look
at the proposed rates for Alaska royalty gas transportation. He
was not sure whether those rates would initially be set by the RCA
and then reviewed by the FERC.
CHAIRMAN TORGERSON commented that they have been talking about the
1977 act and that, in reality, nothing has materialized as a result
of passage of that act. He asked how to account for the pre-build
in Alberta and British Columbia in relation to that act or whether
it shouldn't be recognized. He stated it seems that portions of
the requirements in the law that was passed were accomplished in
the pre-build.
MR. KATZ said the Chairman is absolutely right and that those two
legs of the pipeline were indeed built under ANGTA but no Alaska
portion has been constructed.
CHAIRMAN TORGERSON said it is very frustrating to committee members
to realize that one of the major stumbling blocks it is faced with
today is whether or not NGA or ANGTA prevails over an application.
He said he finds it almost intolerable that the committee cannot
get a decision from anyone. He stated that this issue smells like a
court fight and that hundreds of attorneys on both sides will
represent Foothills and producers if one side doesn't like what is
going on. He said he realizes that FERC's position is to let them
negotiate and hopefully work it out, which he wishes they would do,
but he feels it is a matter of law and a decision on it needs to be
before the FERC so that the matter can be settled. He asked if
there is a way the State of Alaska can put this question before the
FERC and get a ruling on which law prevails.
MR. KATZ said, "I can tell you we are right behind in terms of
wishing we had answers to all those questions." He noted in the
report FERC sent to Congress, staff stated that ANGTA did not
preclude consideration of another proposal under the NGA. ANGTA
says the FERC has to do various things and that once it has
completed the process of a President's decision and Congress's
approval of that decision, the FERC may reject other applications
under the NGA, which staff has interpreted to mean that FERC could
choose to consider them or not consider them, depending on whether
the application is in the public interest. He informed committee
members that in terms of getting an answer from FERC, people do
file requests for declaratory orders, otherwise the state could
request a general counsel's opinion. He said the problem with a
general counsel's opinion is that he is not sure the answer will be
worth much more than the paper it is printed on because any party
could litigate. He did not think another party could litigate a
declaratory order because that would just be an opinion that would
not affect anyone's right to liability until the FERC acted upon
it. He maintained that the issue will probably go to court unless
Congress speaks on and clarifies it.
CHAIRMAN TORGERSON thanked Mr. Katz and Randy Methura (ph) for
their information.
MR. KATZ said FERC staff tries to work with whatever agencies and
legislatures are involved and hopes to do that as this project
moves down the road.
REPRESENTATIVE OGAN noted that he believes the statement that the
easiest way to resolve this issue is to get Congress to speak is an
oxymoron.
CHAIRMAN TORGERSON asked Mr. Katz to clarify what is going on
within FERC regarding staff and Chair changes.
MR. KATZ said that Chairman Hebert has announced that he will
resign as of the end of the month and Kevin Madden (ph), general
counsel, has also resigned. The President announced yesterday that
Pat Woods, who was Chairman of the Texas Commission, and is
currently FERC Commissioner, will be the new FERC chairman as of
September 1. The vacant seat will presumably be filled with a
Republican.
CHAIRMAN TORGERSON asked if anyone else, besides the lead counsel,
has left the FERC.
MR. KATZ said no. He stated that Chairman-designate Wood has an
excellent background in energy regulation and has a strong interest
in gas issues.
CHAIRMAN TORGERSON asked Mr. Katz if he will be the next general
counsel.
MR. KATZ said that he can promise he will not be.
CHAIRMAN TORGERSON asked if the Chairman makes that appointment.
MR. KATZ said it is. He noted the Chairman has someone in mind.
CHAIRMAN TORGERSON asked Mr. Katz if he has looked at the
producers' legislation.
MR. KATZ said that staff supports anything that clarifies under
what authority FERC should consider pipeline proposals and agrees
with the thrust of the parts of the legislation that implies the
need for coordination of federal efforts. But, staff has not yet
done a detailed review of the legislation.
CHAIRMAN TORGERSON asked for a copy of the staff's remarks when
they are available.
MR. KATZ agreed.
CHAIRMAN TORGERSON thanked Mr. Katz and announced the committee
would take a lunch break until 1:00 p.m.
TAPE 01-14, Side A
DEPARTMENT OF NATURAL RESOURCES
CHAIRMAN TORGERSON called the meeting back to order at 1:04 p.m.
He invited Mr. Bill Britt to testify. He asked Mr. Britt if he
believes the state can have, in its right-of-way leases, provisions
to protect access to communities or other projects the state might
want to do.
MR. BILL BRITT, Gas Pipeline Coordinator within the Department of
Natural Resources (DNR), said he hesitates to answer specific
questions without consulting with counsel because there are
limitations to the power, but he believes the Right-of-way Leasing
Act is one of the most powerful tools the state has to affect
policy relative to the question and it is not frequently recognized
as such. He stated that when the legislature chose to preempt the
over-the-top route, the Right-of-way Leasing Act was the tool the
legislature used to do so. DNR can affect very consequential
policy through right-of-way leases; that realm is contractual law
as opposed to police powers. However, the state does run up
against federal preemption issues within certain areas so it
depends on the specific question and what the state wishes to
affect. He said he would like to find out how and what the State
of Texas has done in this arena.
CHAIRMAN TORGERSON said he understands someone will be discussing
that issue with the Alaska Highway Natural Gas Pipeline Council on
September 17 so they may learn more at that time. He commented
that there has been a lot of talk about the hub concept and that
there is a feeling that hubs are created legislatively. The
committee has not been able to find any such animal. It appears
the Commonwealth did something to create a hub and that may be the
only example. He asked if perhaps access to Fairbanks could be put
in a right-of-way and effectively that may become the hub.
MR. BRITT said there are two ways to go. The statute itself
contains mandatory covenants that every right-of-way lease must
include. In addition, DNR negotiates the lease with the owners of
the pipelines, and that includes stipulations and provisions that
vary from pipeline to pipeline. If DNR can figure out how to put,
in plain language, what the state wishes to have happen, it would
be relatively easy to find out whether that can be accomplished
through statute, which is where the mandatory covenants live, or
through the negotiated lease.
CHAIRMAN TORGERSON asked Mr. Britt to comment on the producers'
legislation and the port authority's legislation.
MR. BRITT noted that he only saw the port authority's proposed
legislation for the first time this afternoon but, regarding the
producers' legislation, the administration is preparing comments on
that legislation. His comments to the administration were that:
the definition of Alaskan gas was limited to North Slope gas and he
was unsure what affect that would have on future exploration; that
the return of the office of the federal inspector would be
beneficial; and the preemption to FERC was required to say yes to
applications if three tests were met - those tests seemed slanted
in favor of the producers.
CHAIRMAN TORGERSON asked Mr. Britt if one of the goals of the
federal group of agencies that has been meeting is the creation of
a "super-agency" to look after rights-of-way.
MR. BRITT said their mission is unclear at this time. He was told
in a briefing that they are strictly limited to analyzing federal
approval processes, determining where the bottlenecks are and
making recommendations in a report to be completed in the late
fall.
CHAIRMAN TORGERSON commented that forming a super organization is
consistent with the President's energy policy if the President's
goal is to move mega-projects forward. He thought that the
President said he would establish such an office in his policy
statement.
MR. BRITT said he thinks it is a good idea and that is what his
office is at the state level. Agencies operating on their own
frequently operate on various schedules and at cross purposes. If
everyone is under one roof, the process goes more smoothly.
REPRESENTATIVE FATE asked Mr. Britt if his office has received
enough money from the Division of Legislative Budget and Audit
(LBA) to coordinate and implement some of the activities required
of his office.
MR. BRITT replied the general funds his office received from LBA
were sufficient for him to sign two reimbursement memoranda of
understanding (MOUs) with Foothills and the producers. That seed
money is all his office really needed to begin going forward at a
pace determined appropriate in conjunction with the project
proponents. He has been hiring staff.
REPRESENTATIVE FATE asked if the process was fairly smooth.
MR. BRITT said it happened very quickly. After LBA gave Chairman
Therriault the power to enter into the agreements, a letter was
sent to Commissioner Pourchot the following day. That same day,
the agreements with Foothills and the producers were signed. He
believes working with Chairman Therriault will be very easy.
CHAIRMAN TORGERSON asked Mr. Britt what interaction he is having
with the Canadian regulatory authorities. He asked if they are
forming a joint office also.
MR. BRITT said his interaction with Canadian authorities has been
extremely limited up until now. He has been concentrating on the
federal agencies so the Canadians will be next.
CHAIRMAN TORGERSON asked if we should care.
MR. BRITT said he believes so, simply because ultimately how
quickly something is approved and the expense associated with that
approval occurs on both sides of the border. He thinks everyone
will be better served if the authorities in both countries work
together. He said he also believes it is easier to influence the
approvals of others if the state interacts with and has a
coordinated process with those agencies.
CHAIRMAN TORGERSON asked Mr. Britt if he anticipates a Canadian
member on Alaska's Joint Pipeline Committee and vice versa.
MR. BRITT said he thinks that is entirely possible. He expects the
state and Canada to be wrestling with many of the same engineering
questions and land status and title questions so it makes sense to
learn from each other.
CHAIRMAN TORGERSON asked Mr. Britt if Jack Griffin is his legal
advisor.
MR. BRITT said he deals with the folks who work for Mr. Griffin.
CHAIRMAN TORGERSON asked Mr. Britt to ask for a legal opinion on
the right-of-way issue and provide the committee with the response.
MR. BRITT agreed to do so.
CHAIRMAN TORGERSON thanked Mr. Britt and asked Representative Ogan
to proceed with his questions of Mr. Myers.
REPRESENTATIVE OGAN asked Mr. Myers:
Mr. Myers - I want to have a little discussion about
possible interaction between the producers on what could
possibly be deal killers, or at least slow down the gas
going to market and maybe have an effect on the routes
selected. Kevin Meyer has been on record in the past -
and I'm going to kind of paraphrase it, but basically
saying that this alignment agreement removes some of the
impediments to a major gas sale but - maybe we could talk
a little bit about some of the past things that have
caused problems, like the MI and NGL dispute. You've got
the gas cap owners and BP at odds over that and could you
kind of tell us your knowledge of what happened with that
situation?
MR. MARK MYERS, Director of the Division of Oil and Gas in the
Department of Natural Resources, introduced Bonnie Robson,
petroleum investment manager and informed the committee that Ms.
Robson represented the state as an assistant attorney general on
some of the legal issues so he would defer to her on the fine legal
points.
MR. MYERS stated the North Slope oil field is a very rough
playground. The commercial issues involve large dollars and the
companies are very much competitors in many ways even though they
have a unified interest so that competition is manifested in a
large number of areas. There are cases, not uncommonly, where the
commercial interests of one company are advantaged over another
company and those commercial interests are different than the
state's. There are cases when those commercial interests are
aligned. Those alignments are usually gotten to through a series
of very tough negotiations. Some of the issues are so large that
the negotiations are often protracted and have a very strong legal
and commercial aspect to them.
Regarding the MI-NGL "wars," MR. MYERS said that prior to the
alignment agreement, BP had a majority interest in the oil rim,
whereas ARCO and Exxon had a larger position in the gas cap. In
the case where natural gas liquids were being produced, stripped
out of the gas, there were two major uses for them: one was to
create miscible injectant (MI) to reinject into the fields to
enhance oil recovery; the second was to create a natural gas liquid
and ship it down the pipeline with the oil. Once the oil line had
sufficient capacity in it, there were some engineering safety
concerns that were answered: yes it's appropriate to ship a certain
amount of natural gas liquids down the pipeline. The bottom line
was that the natural gas liquids were dominantly out of the gas rim
acreage that had majority ownership by Exxon and ARCO and therefore
they were at a commercial advantage to see those liquids go down
the pipeline. The state was in a similar position with its royalty
interest. BP felt it was more advantageous to have the MI used for
reinjection to recover more of its oil rim oil. So, essentially,
there was a commercial dispute in terms of value. That commercial
dispute led to BP building separate facilities, which were never
used. That dispute moved into the public sector, with several
agencies on several fronts, including the [Alaska Oil and Gas]
Conservation Commission and the Division of Oil and Gas. Hearings
were held and ultimately a settlement was reached and the
facilities were not used. It was an example of a commercial
dispute getting in the way of the highest and best use of
facilities on the North Slope.
MR. MYERS said, regarding the Gas Balancing Act, the division would
expect the Gas Balancing Act would be needed if a large gas sale
were to occur. It would take 100 percent ownership agreement in
the field for that Gas Balancing Act, which means a minority owner
could block it. Therefore, even though there is alignment among
majority owners, major negotiations would need to occur with the
minority interests regarding the Gas Balancing Act and the
methodology developed and used by the producers. Mr. Myers said to
single that case out as unique is not really accurate, he can think
of a half dozen other mechanisms that could be used if one owner
wanted to block development.
MR. MYERS continued:
We heard earlier testimony by the AOGCC on the issues of
oil production in terms of lost oil production with gas.
Obviously, to mitigate that you're going to want to
modify the reinjection profiles of the field - either
change the gas compositional mix to vary the composition
as you lower pressure for additional recovery, increase
water flood or a combination of that and other
mechanisms. So, that involves significant investment
capital. So, you would need all parties agreement. In
addition, the AOGCC, through their Title 31, would have
to approve it and look at the conservation of the
resource and physical waste. DNR through their
unitization would have to approve that there's no
economic waste and do the balancing between lost gas and
oil.
But in that process, if you have a major owner there that
doesn't want to pay their share, they can kill the
project. Or if you had a major producer that did not want
to sell their gas, they could argue successfully,
potentially, that they need to be compensated for that
lost oil. Therefore, we need to extract this extra value
out of this negotiation. So, there would be protracted
legal negotiations there.
Another issue is the gas in probably a 4 BCF case isn't
Prudhoe Bay alone. It has to be Point Thompson gas. So
now, you've got another separate unit, which will have a
separate unit operating agreement where that balancing
has to occur. In addition, you have other parties like
Chevron and while they have a small percentage in Prudhoe
Bay, certainly less than 2 percent, they have about a 25
percent or so interest in Point Thompson. So, again there
are parties not even involved in this current realignment
that while their position is small in Prudhoe is very
large elsewhere in gas sales. So, anywhere without
agreement from these parties, there are numerous ways
this project can be blocked.
Another issue would be the conditioning plant. If it is a
unit facility within Prudhoe, it has different
implications than if it was part of the pipeline
structure in terms of ownership, regulation and potential
rates of return for it. So, there's another issue where
if someone doesn't want to put the hundreds of millions
of dollars they would have to into that facility, it
would be very difficult to build.
REPRESENTATIVE OGAN asked about a scenario in which Exxon has
significant holdings in the Mackenzie Delta area and the board
decides not to play unless the route goes over the top, whether it
could kill the whole deal.
MR. MYERS answered that wouldn't be an unrealistic scenario,
although the state has some right to have expectations of the
implied covenant to market. If there's a reasonable mechanism to
get that gas, we could force the issue through that, but it would
be a difficult fight. Another issue is that these are not primarily
gas fields; they are primarily liquids fields with significant
amounts of gas. So, you have to look at producing the liquids as
well as producing the gas and there are multiple ways of doing
that. Some of them involve much more capital investment. At 35 TCF
on the Slope, Exxon is the owner of the majority of the gas
reserves.
MR. MYERS continued:
It would be very difficult to see the volumes that you
would need in this type of process independent of them -
if you need a 20 or 30-year supply of gas, to justify the
financing. And even if you could solve all the commercial
issues and they don't want to sell, that's over a third
of that gas. That's a significant amount and would have a
major impact on the project…. Basically, I believe the
producers will try to reach an alignment of their
positions and that's one of the issues of why we're not
hearing a whole lot. They will have to reach that
internal alignment.
Another issue along the line is how much capacity does
each company get. I'm sure that's a very hot subject of
negotiation. It's probably ongoing. Does a company that
has more proven reserves bill a higher percentage of the
project or do they in a practical sense get a higher
nomination versus someone that's willing to take the risk
that they're going to discover more. Someone like
Phillips that has a smaller percentage, a 5 percent
interest in Point Thompson, has a very different economic
scenario than does a company like Exxon that has over 30
percent. There are a lot of internal negotiations and
alignments that have to be reached before they reach
consensus on the size of the project and what their
preferred route is.
REPRESENTATIVE OGAN asked if the lack of alignment on Exxon's part
slowing any development.
MR. MYERS answered:
I think we can look at the oil examples of the alignment
even in Prudhoe, but lack of alignment - and this is not
pointed particularly at Exxon, but at the aligned
parties, versus Chevron's interest in some of the
satellite oil development - it has been an impediment in
the past to rapid development of these satellites. That's
again why Chevron's commercial interest in Prudhoe Bay
was only less than 2 percent. Their ownership in specific
smaller satellites might be much higher than that. It
might be 25, 30 or 50 percent. So, the impact on a
particular project is much larger in their overall
interest. The same thing could occur in situations with
gas. That lack of alignment created a problem and we had
to hold a hearing on the application to produce. We had
to make a decision on what was appropriate participating
area. We did not have consensus among the parties. So, we
had to act to basically broker the dispute. I think the
good news is that we reached a reasonable decision, at
least reasonable by our standards and development is
going forward. But not without real fits and starts and
issues involving how much production is the minority
owner allocated and how much do they pay to use existing
facilities. Some of those decisions, even though we've
reached a resolution, aren't fully decided, yet. We often
postpone. We say, 'We'll do a temporary mechanism. You
guys internally fix it, come back to us in two years. In
the meantime, we'll use this mechanism.'
That is a very common way. In the oil field often the
disputes are based on commercial uncertainties,
uncertainties about how much oil or gas underlays a
particular lease, its commercialities, price, etc. Those
are often solved by a temporary mechanism that has to be
fixed later. So, you agree to the methodology, but you
don't necessarily agree to the actual number. That number
is back calculated. There are numerous ways to solve
these disputes at least to the point where you can go
forward with development without fully solving them.
I think the alignment is an example of one of those in
some aspects because it fixed the problem with the
majority owners, but it really hasn't fixed it with the
minority. I hope that answers your question.
REPRESENTATIVE OGAN indicated that it did and asked what his
experience has been with gag orders. He had the impression they
were not releasing anything on the gas pipeline unless all three
agree.
MR. MYERS answered that he wanted to refer some of the legal
aspects of it to Ms. Robson. He said:
There is an agreement involving the allocation of the
leases that is not yet part of the unit or the unit
operating agreement. Because of that, it's confidential
and we can't talk about it. We're hoping to get clarity
on that. If it becomes part of the unit operating
agreement, we would be able to talk about it.
MS. BONNIE ROBSON, Petroleum Investment Manager, DNR, responded:
Basically, the Prudhoe Bay Alignment Agreement was
executed in the wake of the BP/ARCO/Phillips acquisition
merger and transaction. It was received by the state
Attorney General's Office as a confidential document
protected through the FTC proceedings. We believe it does
address a number of issues typically found in a unit
operating agreement and that it doesn't in fact amend
some of the terms of the Prudhoe Bay Operating Agreement.
So, we have prepared a draft letter and forwarded it to
the Attorney General's Office for review in which we will
ask the producers and specifically the Prudhoe Bay unit
operator, BP, to file that as an amendment to the Prudhoe
Bay Unit Operating Agreement and then provide copies to
the public. Again, it's not certain that we will be able
to do that. Our request has to receive legal review and
it may be contested by the producers.
MR. MYERS added:
I think I'd address it a little more philosophically in
terms of I think: a) The companies are reluctant often to
share their commercial disputes or their dirty laundry in
a public forum and you can't fault them for that. So,
that's part of it. Another part of it is, I think, a
unified front to agencies like ours that negotiates
royalty or deals with tax structure has value to them. It
has strength and value in terms of the risk of divide and
conquer and other scenarios. I think those issues have
lead to an approach we've seen recently from the AOGCC
and from us that it has often been very difficult to get
information that in past years has been relatively free
flowing to agencies that are able to deal with
confidential data.
So, we've seen an overall effect of less information
flowing directly to the state. I will say in past years
the lack of alignment and the commercial disputes which
we have had to resolve, and often we have a royalty
interest if we have varying royalty rates, for example on
a lease. The different technical interpretation by the
different companies helps us review our own internal
interpretation and look at other optional
interpretations. So, it's been a value. A unified
interpretation that's a compromise that fits all the
commercial needs often isn't the approach we would really
like to see. We'd like to see the best unbiased
interpretation of the data. Again, that's one of the
reasons we have technical folks that do forensic type
geosciences engineering and geophysics - is to actually
determine where our commercial interests are harmed or
where we believe the interpretation has more uncertainty
or less uncertainty and that affects the bottom line.
That is one of the aspects of when you see a combined
approach and interpretation. We've lost the benefit of
that which, again, I would argue is another argument for
the state to strengthen their ability to do those types
of technical interpretation. It's also a function of a
unified front in that we can expect in these cases to get
a variation of interpretation. I do want to stress these
are variations in interpretation of data with
uncertainty. It's not mischaracterizations of the data.
It's taking a more liberal or less liberal interpretation
of that data.
DEPARTMENT OF REVENUE
CHAIRMAN TORGERSON thanked him for answering their questions and
announced that Commissioner Wilson Condon, Department of Revenue,
would comment next.
COMMISSIONER CONDON introduced Mr. Ed Small, Cambridge Energy
Research Consultants (CERA), to give them a market update.
MR. ED SMALL, CERA, updated the committee:
There has been some significant changes in the past
month. The combination of continued demand softness and
the supply growth that we're seeing has caused us to
revise our pricing outlook downward and downward fairly
substantially. We believe, though, that this more of a
short term situation than an enduring phenomenon and as I
go through the why, hopefully that'll give you an
indication of where we think we're going in the long term
as well.
The current situation is one where the Lower 48 supply is
up. It was up about 500 MCF/D last year. We're expecting
it to be up about 800 MCF/D this year. Depending on how
low prices go, to be up between 600 - 800 MCF/D again
next year. Canadian supply is going to be up about 850
MCF/D this year. So, in total we're in that 1.75 BCF/D
increase for 2001.
What that is causing is out of the 2.5 BCF/D of residual
fuel oil that had come on and switched off gas during the
winter, there's currently only about .5 - 1 BCF/D that is
still on residual fuel oil. We expect that to be gone by
the end of the year. In other words all of that demand
that had switched to residual fuel oil will likely be
gone and be back on gas by the end of this year.
What that does is it eliminates the price floor that we
have seen over the past four to six months. When prices
came down to a point where residual fuel oil was cheaper,
that caused the gas to basically stay at that level or
people would switch back to fuel oil. So, we see that
floor being gone probably in the fourth quarter of this
year. At the same time that we're seeing some growth in
supply, we are seeing continued demand softness. Power
demand in the West has been off 10 percent this summer.
It has been up to flat nationwide in the Lower 48 with
the recent heat wave, but prior to the last few weeks
nationwide power demand had been off. The demand softness
is primarily in the industrial sector, though, power
being one of the things I just mentioned, but industrial
demand is the biggest factor. How much of that is economy
driven is still hard to tell. I think I mentioned that
last time I chatted, but we have revised our GDP outlook
lower for the balance of this year and in 2002 we expect
to see some recovery the second half of 2002. At this
point in time, we are looking for a GDP growth of 1.1
percent in 2001 and 1.4 percent in 2002 with the majority
of that being in the second half.
What that does say is we do expect to see that industrial
demand come back next year. In 2002 we expect to see
industrial demand increase by 1 to 1.2 BCF/D over 2001
levels, but again most of that will occur in the second
half of the year. Currently, ammonia is still down, the
manufacturing sectors are still hard hit, steel is still
off, etc. In 2002 we also expect to see roughly 300 BCF/D
of power growth. So the combination of the industrial and
power should give a demand growth of about 1.5 BCF/D next
year. That suggests that by the end of next year, we'll
begin to see the kind of supply/demand tightness we
experienced in the second quarter of this year.
What's happening now also is impacted by storage. In
spite of last week where storage was basically flat, we
still expect storage to reach anywhere from 3 to 3.2 TCF
by November 1 of this year. Keep in mind that full is 3.3
TCF. So storage is going to be in very good condition
going into the upcoming winter. In 2002 absent a cold
winter, we expect the supply situation to be such that
storage will be closer to that 3.3 level going into the
winter of '02 and '03. So, those are some of the factors
we expect to cause the price softness. To give you a
sense of what price softness we're talking about, when I
chatted with you last we had indicated a Henry Hub price
of $4.41 for 2001. We've now lowered that to $4.24. We
had an outlook for 2002 of $3.53 on average. We have
lowered that to $2.80 Henry Hub.
But as I had indicated, there is going to be an impact of
this lower price. That impact is going to be both on the
supply side and on the demand side. We're already
starting to see indications on the supply side via lower
rig counts. They are starting to show some softening.
We're starting to see indications that rigs may be
leaving the Gulf of Mexico. So, if we see the price we
are calling for the balance of this year, it will likely
have an impact on drilling. That with about a six month
to one year lag means a lowering of the supply growth,
not necessarily going away, but not as strong as it would
have been had we seen the kind of drilling levels we have
seen for the first half of this year. So the lower prices
will have an impact by lowering the supply response. It
also will have an impact in addition to the economic
growth we expect next year. Lower prices should help
bring some of that demand back - ammonia, steel and some
manufacturing.
Where this leads is to the likelihood of 2003 prices
going back into that low $3 level, probably between $3.10
and $3.25. So, the outlook that I have suggested going
out through '05 we still believe is the path we will be
on from '03 through '05 of prices in the low $3, around
$3.25 range. As an indication of that, that's kind of the
level that we expect to see prices by the end of next
year even though the annual average will be below $3. So,
that is the update since we last spoke.
CHAIRMAN TORGERSON asked if he had any information on the
proposed receiving plants around the U.S. for LNG.
MR. SMALL replied:
The only change I think is that there probably has been
one addition to the ones I had indicated before. I think
the answer there is the proponents of those projects are
going to be wrestling with the dilemma of the short term
price softness. I think unless they have a belief that
prices are going to be stronger in the longer term, it
would be difficult to proceed in the short term. But the
prices have not been soft enough long enough for any of
the proponents to say 'No, we're not going ahead.' So,
basically, there's no change on that front.
CHAIRMAN TORGERSON asked who will get scared off first on the lower
prices, LNG or pipeline?
MR. SMALL replied:
That is a very good question. It is one of those
situations of who blinks first. Part of the answer I
think is going to be in which companies have the stronger
price forecast going forward. If they believe as we do
that in '03 you'll see some strengthening again, those
people would likely go ahead. If people believe that
we're going to see softness continuing, those will be the
people that blink and back off. Who goes first is really
hard to tell.
The other factor is obviously the magnitude of the costs
involved. The higher the risk, the higher the cost. I
think those people may have a tendency to blink first.
CHAIRMAN TORGERSON thanked him for joining them and directed the
discussion to Commissioner Condon.
DEPARTMENT OF REVENUE
COMMISSIONER WILSON CONDON said:
Since we started at the end with item 5 and CERA's
update, maybe we can just go backwards and touch on item
4 next and then conclude with item 3.
In item 4 you ask for a discussion, some analysis, some
conjecture about netback values and how the notion of
netback is used to determine values for severance tax and
royalty purposes. I'll talk some about the use of netback
valuation for the severance tax and Bonnie Robson will
address the same set of considerations for royalty.
The first thing that you asked was how crude oil
severance tax values are currently established. And that
really involves basically a two-step process. The first
step is valuing the oil in the destination market where
it's disposed of. When we talk about destination market
or crude oil that's sold by the producer to a third
party, we're talking about the place where that sale
takes place. If the crude oil is not sold as crude oil by
the producer, but instead is transported to that
producer's refinery and refined, we're talking about the
location of the producer's refinery. Today for purposes
of taxation there are three important destination
markets. One of those is the West Coast in the Lower 48
and that really is the refining area in the Puget Sound
and in the Bay area in Southern California. As well,
Alaska North Slope crude is disposed of at tide water in
Alaska and that's treated as a separate destination
market for valuation purposes and finally, there is some
production sold at Pump Station 1 on the North Slope.
In earlier times, when the production level was
considerably higher than it was today, there were
dispositions on the U.S. Gulf Coast, on the U.S. East
Coast, in the Caribbean area, in the U.S. Virgin Islands,
and in the mid-continent in the refineries that exist in
the Northern Midwest. Each of those was treated as a
separate destination market when Alaskan oil was
transported there and either sold there or refined there
by a producer. Then in the '90s for a substantial period
of time Alaskan North Slope crude was transported to the
Far East and sold there to refiners in Japan, Taiwan,
South Korea, and the Peoples Republic of China. The Far
East was also treated as a separate destination market,
in terms of how oil is valued in those destination
markets for that is sold to third parties.
The valuation measure that has been implemented in our
production tax is to use the higher of two measures of
value and those two measures are what the producer
actually sells the oil for a measure of the current
market value in that market, a term that goes under the
label in the tax business here, of prevailing value. With
respect to crude oil a producer takes to its own refiner,
the value measure there is what I call prevailing value,
which is what we hope is an objective measure of value in
that market.
Having determined destination values, we jump to the
second step in the process, which is to subtract from the
applicable destination value in the disposition market
each taxpayer's actual transportation charges from the
point of incidence on the North Slope where the tax
applies to the destination market where we have
calculated this value. Thence for the netback, you take
the destination value and subtract the transportation
charge to arrive at a netback value. That's how values
are determined for severance tax calculations.
Over the years we've had to face a number of issues. Some
of those issues will be resurrected when we talk about
gas taxation. So, I ought to run through those briefly.
First major issue that we've wrestled with for the better
part of 25 years is how to determine this thing called
prevailing value. When we're telling tax payers they have
to pay taxes on the basis of this value, we have picked a
measure that they can know and appreciate when it comes
time to pay their taxes. Today we believe we do have a
system where a taxpayer can and should know what they
should be paying their taxes on. The measure we use for
determining this thing called prevailing value is the
spot price that's published by the third party reporting
services. That is the measure we use for determining
prevailing value both at the West Coast, which is where
that price applies, and we use it to calculate a
prevailing value at South Alaska and at Pump Station 1.
Spot prices for Alaskan North Slope crude have been
published by third party reporters since the 1983-4
timeframe. They actually weren't recognized specifically
in the regulations that apply to the severance tax until
1994. Before 1994, this measure, prevailing value, was
based on the price that would be derived from three sales
contracts selected by the department in each of the
destination markets. That determination was made by the
department at the time it conducted its audits and had an
opportunity to collect some or all of the contracts from
all of the producers. What this meant, of course, was
that producers did not know which contracts were going to
be used. They probably for the most part [END OF TAPE].
TAPE 01-14, SIDE B
COMMISSIONER CONDON continued:
…what other producers' contracts looked like precisely.
So, we did have a situation where sometimes many, many
years went by before we told the producers precisely what
the prevailing value we expected them to pay taxes on
would be. Presumably they did know what they actually
sold their production for. So, today we believe we have a
transparent knowable valuation procedure so that
taxpayers can know what their tax obligation is. We have
to be concerned, not that this hearing is focused on oil
issues, but the spot price that we believe is reliable
today, given the declining production rates. Changing
marketing patterns may not be reliable indefinitely.
That's something we have to be concerned about as time
marches on.
The second issue we've had to face is which deliveries
match which production months. If you stop and think
about that for a minute, you realize that oil comes out
of the ground on the North Slope; it moves down the
TransAlaska Pipeline; it may sit in the terminal for a
while in Valdez; it's loaded on to tankers. Today those
tankers take it to West Coast refining locations,
sometimes including the Cook Inlet, have gone to the Far
East and for a long period of time went to locations on
the East Coast of the United States and it took in those
instances six weeks or longer for oil to get to market
after it was produced on the North Slope. If you're going
to be matching values and determining a higher of some
objective measure of market value and proceeds at
destination and then matching that back to a production
month on the North Slope, you obviously have to figure
out which deliveries go with which production month to
implement the tax value. That's been a complicated
problem that we've wrestled with over the years. We think
we have a good solution now for oil and no doubt the
problem that we'll have to wrestle with on the gas front
will be different than what we've had to wrestle with on
the oil front.
Similarly, where you're using different value measures,
you also have to make sure that you've matched the right
measures in destination market and this gets a little
more complicated than I want to get into today, but in
the oil business, when you hear a spot price quoted
today, that spot price is for deliveries that will occur
next month. Where you have prices quoted in the press, we
talk about the August spot price, but the August spot
price really applies to September deliveries. Again, that
requires that if you're going to have a measure where
you're looking at some objective measure of value and
comparing it to actual proceeds, and you're making
reference to spot prices and you have volatile prices, as
we do, to get a fair match requires some care and
ingenuity. Again, it's a problem which we think we've
solved correctly, but it is not a problem which we
arrived at a solution for easily.
The next problem is determining transportation charges
and for that in the oil area, it's really meant
determining what a fair return on the capital investment
made in the tanker fleet ought to be and then coupled
with that is the question of how you take a bundle of
charges that just occur over time and allocate them on a
month by month basis so that you have a definite figure
that you can subtract for value every month. You've got
to adopt a set of conventions that are knowable by the
taxpayer so they can take their transportation charges
and allocate them the way you expect them to allocate
them to determine a value. That has been another
administrative problem that we've had to solve with
respect to the netback valuation of Alaskan North Slope
crude oil production.
Going forward, how do we see the value determination for
North Slope gas production including the various liquid
components in the gas. As we sit here today and think
ahead to what ought to happen, we have identified three
principals that we stick to today. One of them is that we
believe we ought to continue with the notion of higher
of. We get at least market value and if somebody makes a
particularly good deal, we get the benefit of that deal.
We want to make sure that however we value gas, that we
capture the economic value of the NGL components and we
want to come up with a procedure where it's possible for
the taxpayers to know the right value on which they're
supposed to be computing their taxes at the time they
file their returns or shortly thereafter. If they can't
know it in the month immediately following production,
which is when their taxes are due, that they are able to
get the information in some manner so that they can
figure out what it is that they were supposed to have
paid.
With respect to the problem areas that we're obviously
going to have to address in pursuing those principles,
we're going to have to determine a good objective measure
of market value to determine prevailing value. As we look
at the world today there are some possibilities out
there, but as I'll discuss at the end, I think it's
premature to do anything other than examine those
possibilities. The province of Alberta has come up with a
very ingenious way of deriving what they call an Alberta
reference price. That's certainly a candidate for a
measure of prevailing value, but it's entirely possible
that transportation system that carries North Slope gas
to market would in effect bypass Alberta and carry gas
directly to the mid northern United States in which case
the market peculiarities that are faced by Alberta
production might be bypassed by Alaska gas. So, we don't
know whether that would really be a good measure.
Obviously, in the gas business we need to make sure we
correctly identify what we contend the actual proceeds of
transactions are, if there are incidental charges where
consideration changes hands in terms of the gas
transacting. Should some of those be included in the
value is something we'll have to work through when we see
what the business looks like. We're still going to be
faced with the same issues, although the solutions will
probably be different for matching dispositions to
production months. There may as well be issues relating
to allocating costs of particular production months.
Can we solve these problems today in terms of adopting a
set of regulations and putting it to bed? Our past
experience certainly would suggest no. We're talking
about deliveries that are going to commence if we're
fortunate 8-10 years from now. We're hoping for something
sooner.
But, if you think about the oil business, North Slope
production started in 1977 and back up to 1967 and say
what changed in the world from '67 to '77. In '67 U.S.
crude oil values were the province of the Texas Railroad
Commission; OPEC existed, but hadn't flexed its muscles;
the notion of spot prices simply didn't exist; that's not
how oil was priced. If you look at what the world looked
like when TAPS commenced, you had OPEC in the driver's
seat trying to establish an official price which they
hoped to defend; we were marketing oil on the Gulf Coast
and in the Caribbean and on the East Coast. We wouldn't
have guessed that would happen as we looked ahead from
1967 to 1977. There were some spot transactions that were
occurring in 1977, but there was no transparent spot
market. Then, if you fast forward ahead another 10 years
to 1987, OPEC has given up this notion of an official
price and is simply trying to control prices by
controlling the volume they produced. The NYMEX futures
market had come into existence and there was a reasonably
transparent spot market and certainly spot services were
publishing prices.
In 1987, there was not an agreement or a consensus that
spot prices were the best and fairest measure of value.
That was the state's position, but the producers in 1987
argued strenuously against that position. But, you move
ahead 10 years to 1997, we're shipping ANS to Asia;
there's a general agreement that reported spot prices are
an accurate measure of market value. That notion is
recognized in our regulations. And not to belabor this
point too much, but if you go back 10 years ago and look
at the gas business, again the changes over the last 10
years have been dramatic. That was just the beginning of
a transparent spot price regimen nationwide. The NYMEX
futures prices had just been established; the regional
trading hubs that exist throughout the continent today
were in their infancy in terms of the kind of transacting
we see there today; and who those majors were at those
trading hubs were a completely different kind of company
than is active at those spots today. The point I really
want to make here is that to be able to put together a
workable netback pricing scheme, we're going to have to
see how the realities of the marketplace evolve before we
nail down exactly how we're going to do what we're
supposed to do.
CHAIRMAN TORGERSON asked if that is a chicken-egg deal. "Wouldn't
you assume the producers would like to have taxing stability before
investment versus what you're saying - Let's wait and see what
happens and then set a taxing structure in place?"
COMMISSIONER CONDON answered:
Ideally, they would want us to be able to tell them
exactly what to do 10 years in advance. I'm offering the
proposition that that's just something that's impossible
to achieve. We're certainly happy to work with them. We
have been talking to them about how we go about solving
this problem. It's my sense that they really don't
understand the nuances of what we need to do any better
than we do. They understand that these are problems that
need to be solved, but they're not sure what their own
business is going to look like - whether they're going to
enter the Alberta market or not, whether they're going to
have a bullet pipeline - I could go on and on.
CHAIRMANT TORGERSON said: "We may have to work on guidelines that
are flexible to some degree."
COMMISSIONER CONDON agreed and added: "We have a set of principles
that I have said we wanted to pursue and that is to have a way so
that the producers can know what the tax right value is when they
file their returns.
REPRESENTATIVE DAVIES said that Commissioner Condon had indicated
that there were also prices at tidewater and at Pump 1 and asked if
they were the netback of the transportation costs from the spot
market price.
COMMISSIONER CONDON indicated that was right.
REPRESENTATIVE DAVIES asked if there was anything the state learned
from that in terms of pricing gas at Fairbanks.
COMMISSIONER CONDON replied no and that it is likely to be an
algebraic equation and:
It would be my guess that it could be much easier than
what we have on the oil front, because it very well may
be that the transportation system for gas is completely
covered by regulated tariffs that have been approved by a
regulatory commission and business is built around those
tariffs. That's not the situation we have with respect to
the tinkering part of ANS oil moving to market.
REPRESENTATIVE DAVIES responded:
But we still have, even if you know the tariff perfectly,
you still have the price determination and where that
point applies and what distance you would apply from the
market back to the sale at point, let's say, Fairbanks.
COMMISSIONER CONDON replied:
We don't know today what kind of tariff arrangement -
whether it will simply be a MCF per mile tariff or some
other arrangement. We don't know whether the market
values we'll be selling gas into will be markets where
everyone pretty much agrees on what the values in those
markets are. It would be my guess that that would be the
case, because as time has unfolded over the last 40
years, pricing has become for both oil and gas more and
more transparent. So, I don't believe over the next 10
years pricing will become less transparent, but obviously
anything is possible.
He said he would let Ms. Bonnie Robson discuss the royalty issues.
MS. BONNIE ROBSON said she would briefly discuss royalty issues and
address some differences between royalty and tax and build on some
points made by Commissioner Condon:
I believe the first question you asked is how does the
netback methodology work for both royalty and tax
purposes. It works for royalty purposes much as it does
for tax purposes. There are several exceptions. The first
is that when it comes to destination value, I believe
Commissioner Condon described two measures of destination
value - one being actual proceeds and the second being a
proxy for market value that is called prevailing price.
For tax purposes the higher of those two measures is
used. For royalty purposes it depends on the individual
lease form at play. All of the lease forms provide at
least three operative measures of destination value. The
first is a producer's actual proceeds for the sale of
gas. The second is the average of other producers' in the
field proceeds for gas and the third is market value for
gas. Again, the state is entitled to the highest of those
measures of value. There are other measures that are
either not operative such as posted prices in the field
or measures that apply in certain newer lease forms such
as minimum value.
The second way in which royalty and tax netback
methodology is different is that taxes are typically
implemented through statutes and regulations and may be
changed by the state changing their statutes and
regulations with public comment, but not necessarily
public agreement. Royalties on the other hand are a
function of contractual arrangements with the lessees and
so we do not necessarily have the opportunity to correct
any errors or problems made at a prior point in time.
That is we must live with the lease forms now in
existence and if we were to enter into agreements with
the producers now on valuation methodology, we would have
to live with those throughout time.
I believe another question that you raised was what
specific problems do you see with regard to the
implementation of a royalty valuation methodology. I
think the primary problem is that the producers have
approached the administration and asked the Department of
Natural Resources to enter into negotiations and in fact
complete those negotiations this calendar year on a
royalty valuation methodology and on whether the state
will take its royalty share in kind or in value. Quite
frankly, we have advised the producers that we do not
believe we have sufficient information at this point in
time to even commence those negotiations. We feel that
the situation is somewhat different from the oil
situation in that yes, we do have royalty oil settlement
agreements, but those were reached in 1991 after
approximately 14 years of litigation and an opportunity
to review a decade's worth of contracts for the sale of
the state's royalty oil.
We are now being asked to enter essentially a settlement
agreement on the valuation of gas without having seen any
gas sales and certainly no gas sales contracts. So, there
are basically four areas where we are short of
information.
· One is we do not know what the actual destination
for this gas will be.
· Two, we do not know how this gas will be marketed.
· Three, we do not know what the actual
transportation costs will be.
· Four, we do not know how the world will change between
now and the actual time of gas sales.
I'll just comment briefly on each of those four points.
In terms of us not knowing what the actual destination
will be; of course, one element of the netback
methodology is destination value. It's quite possible
that this gas will go to multiple locations in the Lower
48 via Canada and specifically Alberta. There is in fact
a trading hub in Alberta. North Slope gas may be traded
in Alberta, but certainly that is not its ultimate
destination, at least to the dry gas. Maybe it will be as
to the liquids.
We do have a concern that our gas not be valued in
Alberta, because that is a market in which supply we
think will always exceed demand and that is a formula for
a low price. We think it should instead be valued, even
if first traded or sold in Alberta, in its actual market
or destination, which we expect to be the Lower 48 where
demand will equal and possibly exceed supply, which is
the formula for either a fair or high price.
We do not know how the gas will, in fact, be marketed. As
I mentioned, we have not seen gas marketing contracts for
the Lower 48 states. We have in fact advised the
producers that as a starting point we would like to see
some of their actual gas sales contracts for the Lower 48
states. We would like to see, for example, as a starting
point, their 10 largest gas sales contracts for a
representative month; their 10 smallest contracts; 10
contracts that they believe are representative of the
spectrum of their actual transactions; 10 contracts if
not included in the above for field sales; also if not
included in the above, 10 contracts for sales at hubs.
We'd like to see 10 processing contracts; and we'd like
to see 10 straddle plant contracts. We would also like
additional information on how they market gas. Again, we
think this information is a starting point on some of the
information we believe necessary to intelligently enter
an agreement on valuation.
I mentioned third, I think, that we do not know what
actual transportation costs will be and one area in which
we are particularly deficit is that we expect by the time
natural gas flows to market the estimation of recoverable
resources will increase above its 35 TCF and this matters
for a determination of the useful life of the pipeline
and the conditioning plant. Right now, if we have a 4
BCF/D pipeline, we would expect that the known reserves
of 35 TCF would move to market in 23 years and the
producers may in fact argue for a useful life of 23 years
or less. In fact, we would expect that the facilities and
pipeline would have a longer physical life than that and
we would expect with additional activity in the Foothills
area, in NPRA, possibly with gas hydrates and elsewhere
on the North Slope, that number would increase and
increase substantially, therefore, supporting a longer
useful life.
The fourth point is that the world will change in ways we
cannot predict. It makes us extremely hesitant to now
enter an agreement, particularly if there's not any
ability to revise the terms of that agreement. We have in
the oil settlement agreements, and I think we should have
in any gas valuation agreement, a provision that allows
the reopening of those agreements to account for changes
in market conditions in the future.
With that, I know time is tight and I would be happy to
answer questions you have now or at a later point in time
on any royalty issues.
CHAIRMAN TORGERSON asked how the producers had responded to her
request for agreements.
MS. ROBSON replied that she had just provided the list to the
producers one week ago today. The department had not received a
formal response from the producers. "They have asked for the list
in email form so they could distribute it more extensively."
CHAIRMAN TORGERSON said the producers had asked them to assist in
tax stability type questions and to work with her and the
administration to expedite some of this. He said the legislature
would need a lot of the same information if they were going to
help. "For those that are listening, they best share data to
everybody."
REPRESENTATIVE DAVIES said:
On the reopeners, you had indicated that one of the
substantial differences between tax and royalty was the
contractual nature of a royalty. When you first
characterized that, it was pretty fixed. But then you
indicated at the end that we do have some reopeners in
the oil situation. Is that something we need to be
looking at in terms of providing better flexibility to
meet uncertain future conditions than we have in the
past?
MS. ROBSON replied:
I think it's very much in the state's interest to provide
for a reopener. The lease forms, themselves, do not
specifically address a reopener. However, they do call
for at a minimum payment on the basis of market value.
So, as market conditions change, accommodations can be
made. The problem becomes as we enter an agreement that
market value will be measured by for instance the spot
price at a particular hub, that may not in fact be
indicative of market value in the future. And so, we need
a mechanism to get back to market value if we enter any
new agreement now.
REPRESENTATIVE DAVIES asked if that was in terms of any royalty
arrangements, something we have to watch pretty carefully?
MS. ROBSON answered: "Absolutely!"
COMMISSIONER CONDON said:
On item 3 you asked us some questions about modifications
to the taxes portion of the fiscal system and your letter
states that you assume we have looked at property tax,
accelerated depreciation versus regressive systems. Let
me briefly review what we have done. With respect to the
state fiscal system and how it would impact the economics
of a gas commercialization project, we certainly looked
in detail during the 1995 - 1998 period with respect to
an LNG project as a part of that being HB 393 enactment
and our employment of Dr. Van Meurs' report he did and
the recommendations he made. At the conclusion to that
process we ended up with an analytical model developed by
our staff working with him that was appropriate to an LNG
project. It was a model that we reviewed with
representatives of the producers both prior to and
subsequent to some of their participation in the LNG
sponsor group.
We also reviewed the model with staff folks from Yukon
Pacific. Following the LNG project activity, there was a
brief period of time when GTLs were pressing to be the
lead candidate for North Slope commercialization project
and we actually spent a fair amount of time with the
folks. First, we modified the model to make it useful for
a GLT project. Then, the staff analysts from Exxon were
generous enough to spend a fair amount of time with us
critiquing our model and we ended up with a model that
it's my sense, although I never spoke to them directly,
thought fairly represented what we needed to be looking
at if that was the direction North Slope gas
commercialization was headed.
Now, of course, we have the proposal for a pipeline from
the North Slope to mid North America. We have not yet
calibrated that model and you've certainly had an
opportunity to play with it and see what it does. We need
to sit down with the producers and their study team to
make sure that the way we've calibrated the model makes
sense. We have not been able to do that yet. We have,
however, looked at some elements that you posit we must
have looked at. In terms of using the model and others,
we have not. We have looked at what would happen if you
did not impose the 20-mill property tax during the
construction period and over a wide range of project
costs that makes about a two-tenths of a percent
difference in the rate of return of a project. What that
really is going to mean in terms of whether it matters,
we need to have much more definite information about what
project costs are likely to be and where the projects are
going to go. What we have done is really a rough look-
see. I don't think getting a rough look-see is a
particularly valuable result. Obviously, such a change
would leave local governments without a revenue source,
which they're not going to feel particularly keen about,
because the time when such a project is likely to most
affect the provision of public services is going to be
while the project is being constructed. Similarly, it
would deny some revenue to the state government. Such a
change in the state's fiscal system would have minimal
effect on the federal government and it would improve the
rate of return for the project.
With respect to accelerated depreciation, that's a
possibility. Exactly what affect it's going to have on
the project and whether it really helps the project
depends on who owns the project. If the project were all
owned by third party providers and not by producers, the
accelerated depreciation probably wouldn't affect them
very much, if they could pass their costs on directly to
the producers. It might, however, increase the value of
the gas at the wellhead by reducing the tariff.
With respect to the question of progressive versus
regressive systems, that's an issue, which we've talked
about in generalities and have no specific analyses that
we have done. We have talked to Dr. Van Meurs about
helping us. He's not going to be available until we've
reached the winter months and in terms of having the kind
of information we need to have to even begin to do this
analysis, I'd be surprised if we have it much before
then. So, we're not ready to recommend changes that you
should consider adopting. We need information and at
least this point in time it would be our strong
recommendation that we continue to rely on the consultant
who helped us as we looked at the LNG project and who is
already familiar with the ins and outs of our fiscal
system. That's the end of my presentation, Mr. Chair.
CHAIRMAN TORGERSON asked about Mr. Katz' testimony on page 26
saying, "It's not secret that one of the three producers, Phillips,
has proposed amendments to the federal fiscal regime, i.e. the tax
regime. Exxon and BP are not implicated in that proposal."
He asked if Commissioner Condon if he was familiar with that
proposal.
COMMISSIONER CONDON said he was familiar with it and has talked to
Phillips about it. They wanted to have the honor of making it
available to the committee. He didn't have any comments on it at
this time.
CHIARMAN TORGESON said it was his understanding that they were
trying to get downside protection if the price was to bottom out
and asked if a regressive tax system that reflected the price, like
Dr. Van Meurs told us we ought to do ever since he came on board
years ago, wouldn't that also offer them some downside protection?
COMMISSIONER CONDON replied that it would offer them some downside
protection, but it would be quite small compared to what they would
like to achieve in their proposed legislation.
CHAIRMAN TORGERSON asked if he thought they would be amenable to
looking at a progressive tax system.
COMMISSIONER CONDON replied that he didn't know.
CHAIRMAN TORGERSON thanked the Commissioner and Ms. Robson for
their presentations and announced that next they would have Mr.
Richard Peterson give his presentation.
ALASKA NATURAL GAS TO LIQUIDS COMPANY
MR. RICHARD PETERSON, CEO, Natural Gas to Liquids Co., addressed
their gas to liquids proposal, how GTLs can help a gas pipeline
project and a little about misconceptions of GTLs and Petroleum
Alternative Liquid (PAL).
Our proposal initially was to build a 50,000 barrel per
day (BP/D) world scale GTL plant that would use
approximately .5 BCF of natural gas and batch that
product down the oil pipeline. We were going to work with
the state and third parties, primarily not the majors, to
obtain the gas for this particular project. We are also
going to work with Moss Gas and Alaskan companies,
primarily for their expertise in the GTL field. We want
to use existing proven technology so we could get lower
costs on financing and we want to batch the syncrude down
the oil pipeline. We want to be able to market this
product on the West Coast where it would get the most
exposure for environmental concerns and market the
naptha, which would be about 20 percent of the product in
the mid East. That is basically our proposal. We still
believe today that it's an alternative to other projects.
It's also something that could work very well with a gas
pipeline.
I would like to say for the record that I'm not here to
oppose the pipeline; I'm not here to support the
pipeline. The pipeline will have to make itself on
whatever the market is going to determine the value for
the natural gas.
What I wanted to talk about, then, is what are the
benefits we see of a GTL plant. We see quite a few
benefits GTLs can have for a gas pipeline, but I want to
focus on one thing only. If you look at the CO2
extraction plant that you're planning to build and the
NGL plant, if you combine them into one facility on the
North Slope and you're able to use the batching
facilities for GTLs, you can batch those NGLs down to
Valdez. So, you can locate the entire structure in
Alaska. We think it would be a much more economic way to
do it.
The other thing we see is with the batching you can take
any NGL and run it down to Valdez where you can process
it and market it for other materials. The other thing we
looked at is if you operate a dense phase gas pipeline,
every single take off point that you're talking about in
Alaska, you're going to have to put treating there to
remove those liquids. If you operate a single phase
pipeline, you're going to have more capacity and you're
going to have less cost and more ability to take gas off
at the various locations down the system. I think it's
fair to say that a single phase pipeline will have
greater capacity using the same diameter for natural gas
than if you ran it on dense phase. Probably the last
thing that we say is if you put this facility on the
North Slope, a hundred percent of the cost of the NGL
processing facility, which I've heard is $2 - $3 billion,
is in Alaska. All the processing jobs are in Alaska. So,
it's a major benefit for Alaska and Alaskans.
I want to briefly talk about what I call misconceptions
on the GTL side. Is the process proven? Is natural gas
the only fuel? Do we need some sort of super federal
support to make it work? Are GTLs economic?
The first thing I want to say is that if you look at GTL
plants world wide, which have been announced, roughly
Shell has announced seven plants world wide, [indisc.]
has two more. There's over 600 BP/D of new GTL plants
being announced in addition to the 300,000 barrels of GTL
plants already on line. GTLs are not some sort of
technology that has yet to prove itself. It is a well
proven technology. It's a matter of how you market [END
OF TAPE]…
TAPE 01-15, SIDE A
MR. PETERSON continued:
…in Cook Inlet or not. If we're running out of gas, coal
gasification makes sense. Especially with a combined
cycle of electric generation facility. If we're not
running out of gas, GTLs will work there.
The other point I want to address was the federal
financial support. Many people have said that a program
as we proposed is uneconomic and needs massive federal
support. What we've said is if you're going to build a
50,000 BP/D GTL plant, you need roughly about 1 MB/D of
batching capacity to eliminate any sort of cross
contamination problems you have. That will support 800,
900, or 1,000 1 MB/D GTL plants. The first 50,000 BP/D
plant cannot afford to pay for that. It would be akin to
saying you build a gas pipeline to the Lower 48 and only
put a .5 BCF of gas in it. So, what we proposed to the
federal government was to come up with a different way to
pay for that infrastructure to allow batching to occur
and they recover their money at a later date. We actually
looked at three different proposals with them and one is
the federal motor fuels tax credit, which we don't
particularly want to use, but it's one way to get it. If
you take the example of gasohol, the ethanol gets 54
cents a gallon. It's been going on for 21 years and could
possibly go on for another nine.
The other way was to look at an environmental credit,
which seems to be the way a lot of senators and
congressmen that we've talked to on the federal level
like to go. The third way that Senator Stevens suggested
in one of our meetings was the possibility of a
government pilot program where they pay for the
infrastructure and they recover it as more GTL plants are
built.
The next issue I want to talk about briefly was - and
here's where I think the problem with GTLs arises. When
you talk about GTLs, we talk about FT, or Fisher/Trop,
synthetic diesel and California has raised this point for
the last couple of years with us. Nobody focuses on the
Fisher/Trop synthetic part; they focus on the word
diesel. As a result, when they look at that, they think
diesel - petroleum products - and their mind is then
fixed in this kind of a format. We found even with the
majors, it's very difficult for them to think of anything
else other than petroleum based product when you say
diesel. So, we like to say, 'Is it diesel or is it a
petroleum alternative liquid (PAL)?'
The reason we do that is because we like to say, 'My PAL
is clean and odorless. It is biodegradable and non-toxic.
It has no sulfur, no aromatics. These are some of the
environmental qualities synthetic fuel has. If you can
get your mind off diesel, you can think about it
different ways. Probably the biggest consideration is
that this FT fluid is a natural gas based product.
In our country we have two basic ways to tax motor fuels.
One is a petroleum-based product and one is a natural gas
based product. CNG, LNG is taxed at a natural gas base.
Diesel gasoline is taxed as a petroleum base. Where we
say this is important, if you go back into the motor
fuels tax on diesel, the federal tax is 24.3 cents per
gallon and in California it's 18 cents a gallon on
diesel. If you look at the motor fuels tax on CNG, LNG,
etc., the federal tax is 4.3 cents per gallon and in
California the tax is roughly 7 cents per gallon. It's
actually a range that goes up and down. So, if you look
at those numbers, you say that if you think synthetic
diesel from a GTL process is a natural gas based product,
the current federal tax is $13 per barrel less. This
means $13 per barrel higher netback to the gas supplier.
There's a lot of other types of programs out there that
if you get away from petroleum products and starting
thinking about this as a natural gas product, it improves
the economics of GTLs tremendously. You also have tests
running in California right now for NOX reduction, which
ranges between 12 - 15 cents a gallon. You have the
ability to put in CNG avoidance premium. CNG requires
massive capital upfront investment. To do it where it's
PAL synthetic diesel does not require that. So, you use
the same existing infrastructure. So, we like to say if
you consider GTLs as a natural gas based product, you're
going to have a situation with far more value than you
have given it in the past. It needs consideration.
But, the primary purpose for me being here is to talk
about GTLs from Alaska. It's a pristine fuel from a
pristine environment, but GTLs can help improve the
economics of a gas pipeline. We believe that by going
ahead with the GTL option on a small scale, putting in
the batching facilities, you can put the NGL processing
facility with the CO2 extraction facility on the North
Slope and keep all of that work here…keep the value;
batch that down to Valdez and maybe do something else
with it at that location.
2:44
CHAIRMAN TORGERSON said he read something saying the federal
government recognizes GTL as an alternative fuel and the tax
proposals that are pending in congress have a 25 cent tax credit
for GTLs or alternative fuels.
MR. PETERSON responded:
No, I wouldn't say that. The alternative fuels tax
definition that was put in at the help of Congressman
Young and Senator Stevens places GTLs into that status of
alternative fuel. By being an alternative fuel, you make
yourself available for clean cities programs and it just
so happens that every single other alternative fuel has
some sort of a tax subsidy etc. What we're saying is that
GTLs are gas based. If you tax them based on a gas base
only in the motor fuels market, in some states you have a
31-cent advantage for a higher netback (higher or lower
in some states).
MR. PETERSON commented if the boat that sank in Prince William
Sound had been using PAL, this would have not been an issue. "PAL
has been approved by the EPA as non-toxic, biodegradable, can be
dumped into the ocean and you don't have to worry about cleaning it
up.
2:50
ALASKA GASLINE PORT AUTHORITY
CHAIRMAN TORGERSON announced a three-minute break before going to
the Port Authority for the rest of their presentation [CONTINUED
FROM THE LAST MEETING]. He said that Fairbanks is a part of the
Port Authority concept, having placed that issue before the voters.
The North Slope Borough and Valdez are also active members.
MR. DAVE DENGLE, Interim Executive Director, Port Authority, said
Mr. Rigdon Boykin, Special Counsel for the Port Authority, Mr. Burt
Kodel, a board member, and Mr. Dave Cobb, Secretary were also
present. He said that Charlie Cole was called away on a special
assignment by the Governor and he would take up where Mr. Cole left
off discussing some of the benefits of the Port Authority financing
and tax exemption status and answering the committee's questions.
MR. RIGDON BOYKIN, Special Counsel to the Port Authority, said:
The first slide goes into the base case assumptions we
used in our financial model. This is a model a great
amount of detail of which we gave to you at the last
hearing in Anchorage. I have selected a few slides from
that to illustrate the base case used and what the
results from that base case were.
You may recall that the Port Authority model is based on
a combination project of both the Foothills project and
basically the YPC project, because we get a tremendous
amount of economies of scale by combining both projects
into one project along the common 550-mile corridor down
to Delta Junction. Consequently, we're ending up putting
6 BCF into the pipeline. In order to do that, you need to
process 8.7 BCF on the North Slope. We have assumed for
the purpose of this model that the Port Authority would
own and construct that conditioning plant on the North
Slope. That may be quite a difference from some of the
other models or theories that you've seen.
From that 8.7 BCF, we will extract 2 BCF of CO2 and other
elements. That will be returned to the producers for use
as miscible injectant. We will actually buy,
consequently, a little over 6.7 BCF of gas and we will
pay for that gas a split payment, 30 cents base price and
45 cents, which will be an additional subordinated
payment for the feed gas for a total price of 75 cents
per million BTUs.
We will produce 15 million tons of LNG. That will
basically be three trains of five million tons each.
Those trains will come on line at six-month intervals. I
think the initial train will come on line 49 months after
the start of construction.
We have assumed a price for the LNG of $2.5 per million
BTUs at Valdez. If that were shipped to Japan and the
shipping were 60 cents, which we believe it would be at
or less, that would equate to a delivered price in Japan
of $3.10. We have assumed a $3 per million BTU Chicago
price. Based in the assumption is $1.20 per million BTU
assumed tariff for the Alaska border to Alberta to
Chicago section of the line.
As I mentioned earlier about 6 BCF will enter the line;
approximately 2.7 BCF will go into the LNG plant in
Valdez; and a little over 3 BCF will go down to Canada.
This will be a dense phase, high-pressure line. That
means we'll be carrying propane and butane down the line
in a gaseous form. I cannot overstate the benefit of
these liquids and the value of those liquids to the line
in terms of amortizing the cost of all of these
facilities.
Eighty-one thousand barrels of NGLs will be extracted on
the North Slope; 119,000 barrels of LPGs will be
extracted in Valdez; 141,000 barrels of LPGs will be
extracted from the gas that's going down to Canada. That
will be extracted either in Calgary, our assumption is,
or in Chicago if it ends up going down the Alliance Line
to Chicago. We have assumed an LPG price of $12.50 per
barrel and an NGL price of $16.50. We believe all of
these numbers are relatively conservative.
The benefits to the producers: basically they get $811
million from the gas sale at the base payment of 30
cents. They get another $1.2 billion from the
subordinated gas payment of 45 cents per million BTUs for
a total amount of just over $2 billion per year.
The benefits to the state and municipalities of Alaska:
$371 million per year in royalty and severance tax; $81
million per year in royalty and severance tax on the
NGLs; $148 million per year if they're paying corporate
income tax. (I don't know whether they're taxpayer or not
due to consolidation, etc.). One hundred and fourteen
million will be the payment in lieu of taxes to the
municipalities along the route; that equates to
approximately a 10 mill tax as opposed to the current 20
mill regime for the oil line.
The project was designed to throw off $370 million per
year, which would go $220 million to the state and $148
million to the municipalities; $111 million of that would
be in the form of direct money based on a per capita
allocation. The other $37 million would be used to lower
energy costs for communities that could not readily
access gas along the corridor.
Because we're only paying 75 cents for the gas from the
producers in this example and because we need a very
healthy debt service coverage ratio, in this case it ends
up being over two times debt service, we have a lot of
excess cash that's generated by this project. Basically,
it generates $1,750,000 of excess cash; of that $1.2
billion goes to the producers (that's the 45 cents
subordinated payment); that leaves $532 million, which
can be used to increase the netback for reserves, to
accelerate debt payment, a whole host of different things
including potentially building in incentives for whoever
the operator of the pipeline etc. and the Port Authority
might be.
What I've done at the bottom of this is include a
sensitivity table for the use of the committee.
Basically, what that does is show you what happens if
various things happen to the price of gas, to interest
rates, price of NGLs, etc. So, basically, a 10 cent
increase in the price of the gas will increase the amount
of revenue by $200 million per year. A decrease in
interest rates of .5 percent would increase the amount
available by $120 million per year. An increase in the
sales price of the NGLs and LPGs of $2.50 would increase
the amount available by $300 million per year. A
reduction in the EPC construction cost of $1 billion
increases the amount available by $120 million per year.
We thought it would be useful for you to have some kind
of sensitivity, but I think what this also illustrates is
that because of the $532 million per year cushion that we
have, we could actually absorb and decrease in the sales
price at the Chicago, for example, of about 20 cents and
maybe more (40 cents) if the decrease is only on the
Chicago price and not on the LNG side, as well.
There has been a lot of discussion as to what the
benefits of this Port Authority are and what difference
would be if this were a private project versus a Port
Authority project. What this slide is designed to show
you that basically the private project would pay $516
million in taxes; the Port Authority doesn't pay those
taxes. That money would be used to increase payments to
other people or to pay debt or what-have-you. Also, you
can because the Port Authority isn't paying taxes, its
unlevered project return is 12.9 percent. For a private
project, its 6.8 percent and that's only by decreasing
the amount of payment to the producers to 69 cents as
opposed to the 75 cents in the Port Authority case.
This slide is basically one of a group of slides at the
end of the financial presentation that we gave and the
primary reason I wanted to put it up there was to give
you an idea of the liquids in this project. In the third
column second line, you can see that the liquids are
producing approximately $1.5 billion of revenue per year.
That's a lot of money.
What I'd like to do if it's alright is start with the
questions that were posed by the committee to the Port
Authority. The first question deals with the benefits of
the Port Authority concept and why is there a difference
between what we're saying and what the producers (sponsor
groups) are saying. We don't know why they don't believe
this structure provides any benefits. We've had limited
discussions with them; they have not had any significant
discussion with us that would explain to us why this tax
benefit has no value. We will give you where we see our
value coming from. In the first place, we do not pay
federal income taxes and money that would otherwise be
used to pay those taxes can be used to pay debt and
increased payments to stakeholders.
We've just gone through the slide, which shows you the
producers in our example of a two-project line would pay
approximately $516 million in taxes; they can use that
money to increase the netback to do other things that
would be a benefit to the producers and the citizens of
the State of Alaska. We have heard it said that if we
gave all of that money that's the difference between the
revenue that's generated by the Port Authority and the
revenue that would be generated by a private individual
to the producers, they would end up having to pay taxes
on that money and they would be left in the same
situation. That's not exactly true, because if they owned
the pipeline, they would pay $516 million on the
pipeline. If we gave them that $516 million, for example,
they would only pay a tax of 35 percent roughly, not the
entire $516 million. I don't understand that particular
argument, at least.
In addition, one thing you should know that the income
taxes for a private project will increase over time as
debt is paid, because of the increased debt payments,
interest will not be a deduction and you're payment of
taxes will increase.
One of the biggest benefits of the Port Authority is that
they are seeking a much lower return on the project than
would be required by the sponsor of a private project.
The return requested by the Port Authority is $370
million, which equates to a negative 2.6 percent. The
return is negative because the $370 million doesn't start
until five years out in the project. If you take into
account the time value of money, it basically erodes the
principle that you would end up recovering.
Typically, a company like BP requires 14 - 15 percent
unlevered return in order to invest in a project of this
type. There is no way we believe they would get that kind
of a return if they owned this project. Consequently, it
becomes very difficult for a private company to build a
project like this, we believe.
The next benefit that we feel addresses a lot of this
committee's concerns is the fact that the Port Authority
project would be exempt from FERC regulation. This would
give Alaska an ability to better control capacity, usage
and rates. Some of the companies the Port Authority has
talked to believe the FERC exemption could substantially
increase their interest in the pipeline.
Some of the debt could be financed with tax exempt bonds.
The Port Authority believes that between $3 - $6 billion
of debt can be financed with tax-exempt bonds depending
on how the contracts for the sale of gas are structured.
Tax-exempt bonds basically sell for 2 percent than
taxable debt on average for a project like this.
The project will not cost the producers any capital and
will be non-recourse to the producers, the state or the
Port Authority. This project will be project financed.
That means that the banks will not lend money to the
project unless they believe that the contracts which form
the basis for this project - the contract for the
construction of the project, the contract to buy the gas,
the contracts to sell the gas, the operation contracts
for whoever is operating the pipeline - all of those
various contracts have got to be sufficiently precise
that the banks will rely on them to lend the money
required for this project. It's sort of a self policing
mechanism, because if the contracts aren't good enough,
you can't borrow the money. If they are good enough, you
can borrow the money.
There are also benefits to the State of Alaska. I
mentioned earlier the $370 million; there's also much
more certainty for gas for instate usage. The Port
Authority will ensure that a spur line will be built to
allow Anchorage, etc. access to the gas. The Port
Authority can use retained earnings to develop LNG
transport to other communities accessible by road or
water. There's also more control over price to the
consumer of instate gas usage - for example, gas to
Anchorage or Fairbanks could be in the $1.80 per million
BTU range. That's a little bit simplistic; the actual
price will probably be over $1.80, because you'll have to
add on the costs of tapping into the line and all of that
kind of thing, but it shouldn't be substantially above
that at the wholesale level. Although, probably a private
entity might look at pricing that at the marginal cost of
other fuels as opposed to just subtracting off what the
transportation cost might be for the distance the gas
didn't have to travel.
There's no need to give up tax revenue, royalties, etc.
to subsidize the project. We modeled this and found out
that the benefits from the tax exemption substantially
exceed the benefits, if they were given the maximum
benefits permitted by HB 393. And if in addition to those
benefits, you eliminated royalties, this benefit still
exceeds that amount.
The second question posed was the ability of the
Authority to operate outside the municipal boundaries of
the initial founders of the Port Authority. Basically,
the short answer is that there's no limiting language in
the enabling statutes that precludes the Port Authority
from doing business or owning assets outside the
boundaries of the member utilities. The only limitation
is we do not have condemnation authority outside the
boundaries of these communities, but within the
boundaries we do have that authority.
The third question deals with cost over runs with respect
to the construction contract. First of all, the total
contingency contained in our design and financial model
for this project is $2.7 billion - $1.8 billion of
contractors' contingency and $900 million of owner's
contingency. Bechtel obtained two or three quotes for
most of the equipment in their design study. A critical
feature of this project is that it will be 100 percent
financed on a project financed basis. In order to do
that, the construction contract must be for a fixed price
with a fixed delivery date and meet certain performance
criteria. Failure to meet the performance criteria or
delivery date will result in liquidated damages, which in
this case can be quite substantial.
Only a few companies in the world are capable of forming
a consortium to take this kind of risk. Bechtel is one of
them. Basically, the bottom line is that banks will not
finance the project if the contract does not adequately
address over run risk. If the project is late, does not
meet performance criteria, or has over runs in excess of
the contingencies, Bechtel and any partners it has in the
project will be responsible if they end up being the
contractor.
The next question deals with the value of LPGs. I
mentioned a little bit earlier that that value including
the NGLs on the Slope amounts to about $1.5 billion per
year. The gas that's produced on the North Slope contains
a substantial amount of propane and butane; however,
these liquids are too volatile to be transported in TAPS
to Valdez. Consequently, over 100,000 barrels of these
liquids are reinjected into wells on the North Slope
every day.
In the past, gas pipeline design and technology did not
permit the transport of propane and butane. However, the
new designs and technologies that are being proposed for
the transportation of North Slope gas will enable the
pipeline to transport propane and butane in a gaseous
form. This propane and butane is very valuable as I
mentioned earlier and depending on the sales price can
generate sufficient revenue to basically pay for both the
conditioning plant and pipeline.
The propane and butane in the Lower 48 branch of the line
will probably be extracted in Alberta or Chicago. If the
instate consumption in Fairbanks and from the spur line
to Anchorage is large enough, it might be economical to
extract the propane and butane from that gas in the
Fairbanks or Glennallen area. At the price of $12.50 per
barrel, the LPG from the two branches of the line
generates $3.25 million of revenue per day or about $1.1
billion per year. A price increase of $2.50 would add
approximately $200 million of revenue per year.
The fifth question, the committee heard testimony about
the problem of dealing with FERC for sizing the line for
instate gas usage. As I mentioned earlier, a Port
Authority project would not be subject to FERC
jurisdiction. In addition, the line would be owned by the
Port Authority. Facilitating instate gas supply is part
of the mission of the Port Authority. The line has been
designed to supply up to 500 MCF/D of instate gas usage
at relatively little incremental cost. If instate usage
expands to a higher amount, the Port Authority has every
incentive to add compression stations, etc. to enable
increased delivery.
The sixth question had to do with whether Bechtel
reviewed the cost estimates for other routes including an
over-the-top route. We've heard a lot of estimates for a
lot of different projects. Most of the estimates don't
specify what's comprised in the estimates. Do they
include contingency money? Do they include the
conditioning plant? Do they include working capital? Do
they include a debt service reserve? So, it's very
difficult to compare these projects, in fact, it's pretty
much impossible. The only things we did do is when the
arc numbers were first announced for the over-the-top
route, we asked Bechtel to give us a back-of-the envelope
estimate of the all end costs of a similar project and
basically the conclusion we reached was that all the
costs were not included in the arc numbers, because the
difference in the numbers were very substantial.
The next question deals with the CERA presentation; in
particular, we focused on the answers to the questions
that CERA gave in written form to this committee on July
17 of this year. The questions posed to CERA indicate an
interest by the state to promote instate usage of gas for
residential, industrial and petrochemical use and reserve
in some fashion capacity on a line should a large demand
develop in the future. There's also considerable interest
in natural gas liquids that could be transported in a
high-pressure dense phase line. On the whole, the CERA
answers to the questions in these areas we felt were not
very encouraging.
However, the answers might be more favorable if the
questions were not so limited in scope. Most of the
question limit the answer to only a Lower 48 project or
only an LNG project. It is almost as if there's a silent
agreement to only talk about a Lower 48 pipeline with a
possibility of a limited use spur line to carry liquids,
for example, to tidewater or only an LNG line.
The proverbial elephant sitting in the corner of the room
- a combination of both an LNG and Lower 48 line - is
ignored. Inclusion of this elephant in the questions
might lead to more favorable answers to a number of
issues critical to this committee and the citizens of
this state. Basically, the two-project line will deliver
6 BCF along 550 miles to Delta Junction; then 3 BCF 156
miles to the Canadian border and 3 BCF 250 miles to
Valdez. This concept should have more benefit than the 4
BCF minimum suggested in the answer to question 16 by
CERA for a $15 billion pipeline. It also avoids having to
take over 3 BCF through Canada, which some testimony in
Anchorage indicates might be a problem. It enables the
extraction of gas liquids in Valdez for export or instate
use. The liquids in the economics of a larger size line
to Delta Junction makes the LNG competitive in Asia
especially when one considers security of supply issues
and it gives Alaska LNG a very substantial competitive
advantage over other LNG resources to delivery to the
West Coast of the United States and Mexico.
We've outlined in our statement a couple of examples of
the effects of limited answers to limited questions. The
first is CERA question 11 - capacity for instate gas use
expansion. CERA discusses the problems and cost of
expanding the use of instate gas only in the context of
the Lower 48 project. In short, a concern is expressed
that if the amount and timing of the expansion are not
fairly predictable, the producers might design the
pipeline to maximize delivery to the Lower 48. In such a
case, use of the Alaskan portion of the line for instate
gas could result in underutilization of the more distant
parts of the line. A two-project line might afford a much
greater degree of leeway, because the North Slope to
Delta Junction portion of the line will be very large
diameter pipe, 56 inches, to which adding more
compression at existing stations will add substantial
capacity at a relatively small incremental cost. Most
instate usage is likely to occur at or above Delta
Junction and along the Valdez branch of the line and,
thus, should not affect the Lower 48 branch from Delta
Junction, if instate usage is increased to as much as 500
MCF/D.
CERA's question 6 asks how much gas needs to go through
the line to make it economically viable and second
whether there will be sufficient capacity in Canada to
deliver that amount of gas to the American markets.
CERA's answer is basically that a $15 billion pipeline
will require at least a 4 BCF/D throughput and a Chicago
price of $3 to offer a netback in the range of 74 - 95
cents per thousand cubic feet. However, testimony at the
Anchorage hearing indicated that there may be Canadian
resistance to permitting a throughput of over 2.5 - 3
BCF/D. Clearly, CERA recognizes that the larger the
throughput for a green field pipe, the cheaper the gas is
to transport on a per unit basis. A two-project line that
splits at Delta Junction achieves these economies of
scale. The main trunk line carrying 6 BCF to Delta
Junction only requires 3 BCF to transit Canada, because
the other 3 BCF goes to Valdez for delivery of LNG to
Asia, the West Coast of the United State or Mexico.
The CERA question 8 basically asks what changes would
make a stand-alone Alaskan LNG project delivering its
product to the Asian market economic. Here again, we
agree with CERA. The possibility of a single project to
Valdez just for LNG without the Y-line, probably at best
is marginally economic. It's the Y-line, the combination
of the two projects that makes the LNG economic, as well
as the value of the liquids. CERA really didn't go into
much analysis of the value of those liquids in terms of
offsetting the cost of making the LNG in the pipeline.
The CERA question 2 and 3, regarding petrochemical
industry possibilities - basically, CERA's view is that
the liquids to service a petrochemical industry would
basically have to be delivered to a coastal location and
instead of assuming this might be combined with an LNG
branch of the line to Valdez, they assume that basically
just a pipe would be put in to carry the liquids only to
Valdez and they concluded that would be fairly
uneconomic. They are probably right on that, but the
combination with the LNG project, taking the liquids out,
which will be from a very substantial volume of gas
there, changes the equation and would probably change
CERA's answer.
Lastly, you've asked for our view of the Lower 48 and
Canadian gas markets. We don't have a view of the
Canadian gas market. We didn't do any research on that;
we haven't asked any people to do research on that -
other than to look at the issue of whether they thought
Canada would permit large volumes of Alaskan gas to
transit Canada. We do believe that Canada is not going to
embrace the transit of gas through it to the United
States, which may preclude or reduce their ability to
market additional Canadian gas.
Frankly, we think, were it not for ANGTA we would have a
serious problem here. We do believe that if the Foothills
project is implemented as part of this overall scheme, it
would be pretty difficult for Canada to stop the transit
of 2.5 BCF, at least, and probably 3 BCF. But we believe
additional volumes will be very problematic.
With respect to the Lower 48, the Port Authority believes
this market as it relates to Alaskan gas is critical to
both the Lower 48 line and LNG to the West Coast. Some of
our research indicates that the sheer volume of new gas-
fired electric generation has been planned over the next
4 - 5 years in the Lower 48 will substantially increase
demand. Conversations with gas marketers in the United
States indicate they have seen shortages in certain areas
of the country over the next 4 - 5 years. This shortage
is so serious that independent power producers are now
integrating into the gas market because they believe that
they may have a better ability to protect themselves
against gas shortages if they go in and start buying gas
reserves and perhaps building gas pipelines. A good
example of this is the gas pipeline that Calpine, one of
the leading independent power producers in the United
States, has announced it's going to build in the
California area.
A number of companies have also stated to us that they
are working on LNG regasification permitting issues with
respect to a number of sites in California, as well as
Mexico. We have also researched the Asian markets with
respect to LNG. It is believed that demand in this market
is largely dependent on three factors, which for the most
part are all interrelated, because this market is rapidly
becoming a global market. The factors are the pace of
economic recovery in Asia, especially as it may be
affected by the United States. Second, the pace of
deregulation of the electricity and gas markets in Asia
and the consequent growth of independent power producers,
especially those that integrate into the fuel sector. And
lastly, the growth of the Indian market and the [END OF
TAPE]…
TAPE 01-15, SIDE B
MR. BOYKIN continued:
The Indian market has the potential to absorb a very
large amount of LNG over the next decade. I would note
that recently a contract for 7.5 million tons per year
was recently signed for an Indian project. It was
announced not long ago. To give you an idea of scale,
that represents basically 10 percent of the entire Asian
demand in one swoop, roughly half of the 15 million tons
that this project would produce in Valdez.
We believe, based on the research that the Port Authority
and its consultants have done, that the market is there
for Alaskan gas, particularly at the prices set forth in
our financial model. The Port Authority agrees with CERA
that there's a window of opportunity now, but the Port
Authority also believes it may be extremely difficult or
a very long time before the window reopens for the size
project that is required by the economics of an 800 mile
pipeline through Alaska. As announcements to build lines,
announcements of drilling discoveries in the Gulf of
Mexico and off the coast of Canada, announcements for the
LNG terminals in Mexico, the Bahamas and the West Coast
of the United States, those announcements are not going
to wait for Alaska to get its act together.
All of these facilities require contracts for the sale of
gas or LNG to get their financing. Many of these
negotiations are taking place today. An example is the El
Paso letter of intent to buy LNG for delivery on the west
coast of Mexico from Phillips from a yet to be
constructed facility in Australia. If this contract is
realized, it takes away an opportunity to sell 5 million
tons of LNG to a location, Mexico, where Alaskan LNG will
have a substantial transportation cost advantage.
The bottom line is there are two projects that are at
least partially permitted. Endorsement of both of these
projects by the Alaskan government may be the only way
North Slope gas can meet this window. We believe this
window is a lot shorter than most people believe; people
are contracting for huge amounts of gas and LNG right
now. It would be nice to have a perfect project, nice to
have perfect legislation and perfect protection of
Alaskan interests. I think if we wait for all of that,
Alaska will miss the current window.
4:35
REPRESENTATIVE OGAN said he shares his frustrations watching the
different projects. He would love to ship gas to Mexico. He asked
how you get the producers to sell the gas.
MR. BOYKIN responded:
I think we stated in our earlier testimony that we have
sort of given up on the producers doing something
themselves in a short timeframe. We don't think that's
probably going to happen. So, we've focused instead on
trying to get big users of gas interested in putting
something on the table for the producers up here. That
means going to the Enrons of the world, the Dukes of the
world, the El Pasos, etc. and try and get them interested
in putting an offer on the table, because we believe
without an offer on the table, it will be probably
difficult if not impossible for the state to get the
producers to do anything. But, if there is a bonafide
offer from a credible player, such as an Enron, Duke or
El Paso, or a consortium of those players, then it
becomes very difficult for the producers to say, 'Hey,
we're not building it and by the way we're not going to
sell it to those guys either.'
At that point in time they've got to decide, I think,
either we will build it or we'll sell the gas to that
consortium. I think it places a lot of pressure on
something to happen. Whether that's a realistic goal, I
don't know, but it's the only game in town that I see.
REPRESENTATIVE OGAN agreed with that and said if there were any way
to help, he would be glad to assist.
MR. BOYKIN responded that there was something that could be done to
assist that and that is:
The state government needs to get together. These
companies have come to us and said, 'Where's the state on
this? Will the state support this? What's happening in
the governor's office? What's happening at the
legislature? Where is all of this?
I think that whole effort would be helped immeasurably if
there is sort of one unified stance within the state that
would encourage this effort.
CHAIRMAN TORGERSON asked why Enron, Duke or El Paso weren't here
today to talk to them. "We haven't been hiding from them."
MR. BOYKIN said he understood that, but he thought they had talked
to individuals in the legislature and the state administration.
They believe rightly or wrongly that they have been
getting some conflicting messages. One sort of thought
they were being told, 'Don't meddle in our business.
We'll get this all squared away and the pipeline will be
built by the producers eventually.'
Whether that is an accurate view of what they were told
or not is another question.
REPRESENTATIVE OGAN noted the Duke was there, although they weren't
testifying. He said they are producing Scotia gas and shipping it
to the east coast and he thought it would be advantageous to get a
presentation from them on some issues shipping from Canada into the
U.S. He knew that El Paso had been at a meeting in the past. He had
spent some time with them at a conference in Whistler a couple of
weeks ago. He said that the Japanese and Pacific markets view us as
dysfunctional because the governor says one thing, the legislature
says something else. The governor does not want to consider LNG,
but he thought with the two projects piggy backing on each other
made the economies of scale possible.
CHAIRMAN TORGERSON said he wasn't commenting about people
physically being there taking notes, but proposals that are laying
in front of them for review.
MR. BOYKIN responded that he thought there were a number of
companies doing the due diligence that is required to make such a
proposal.
CHAIRMAN TORGERSON responded that he understood that, but Mr.
Boykin said that the legislature is not listening or talking to
them. "They're not putting anything on the table…When they get
their act together, they're welcome to sit where you are too, and
tell us they want to buy a couple billion feet a day. An then there
may be some action happen!"
MR. BOYKIN replied that in putting their proposals together, they
are making assessments now as to where the state stands and there
is some concern that they can't determine that. "Perhaps they
haven't been talking to the right people."
CHAIRMAN TORGERSON said, "My guess is that it's happening in board
rooms in the Lower 48 like the producers are doing. Decisions
aren't necessarily made within this state. Do you agree with that?"
MR. BOYKIN agreed.
REPRESENTATIVE FATE explained how gas utilization was applied as a
throughput LNG plant to Valdez, gas to Canada, etc. and extraction
of LPGs, etc. He then went in to instate use and asked for a
clearer picture: "If the state wanted to embark in a petrochemical
industry, which is being driven offshore in the Lower 48, and fill
that vacuum, how would you go about releasing enough gas for that
industry without harming the throughput into the LNG plant or, for
that matter, another spur to the Cook Inlet, which we all know is
going to require some in about 12 years."
MR. BOYKIN responded:
The petrochemical industry that would probably best be
put here, if that's what you wanted to do, would probably
be based on propane or butane and that will be taken out
at Valdez. So, it could be used very easily.
REPRESENTATIVE FATE said he was talking cash back, not utilization
of those by the state or any other part of the gas in state usage.
MR. BOYKIN responded:
The propane and butane that's produced in Valdez, whether
it's used instate or out of state, the price should be
the same for it. So, the economics of the project are not
adversely affected. It just makes those liquids available
there in Valdez without damaging the LNG at all, because
the propane and butane would not be used to make the LNG.
The plant is designed that way and everything. There's a
possibility you could use some of the ethane, as well. We
really didn't look at ethane; we basically only looked at
the propane and butane and assumed that the ethane and
methane would be sold as LNG. But, the line has been
sized to also permit a substantial amount of gas for
instate usage making ammonia, perhaps, as well as power
generation or what have you at very minimal cost.
REPRESENTATIVE FATE said he was speaking in generic terms and other
presentations have a finite idea of what royalty gas, for an
example, would be in instate usage. He didn't get that feeling from
his presentation. "What was their requirement going to be at the
LNG plant in Valdez?"
MR. BOYKIN replied:
The highest estimates we've heard so far for instate
potential usage out into the future is .5 BCF/D. We
believe we have designed that so that it can be delivered
with minimal incremental cost. The liquids can also be
used instate and it's immaterial to us whether they are
used instate or out of state, because it doesn't affect
any of our downstream operations.
REPRESENTATIVE DAVIES asked if he knew what the sale price was for
the 7.5 contract in India he referred to.
MR. BOYKIN replied that he didn't know; he guessed that it was more
of a commodity type price rather than a basket of oils, which is
the historic way of pricing. He said there was an excellent report
on LNG by Deutch Bank prepared in May that gives a very good
background on what's going on in the LNG markets.
CHAIRMAN TORGERSON thanked them for testifying today and said they
would take a short break (3:47 - 3:50).
3:50
PRODUCER GROUPS
CHAIRMAN TORGERSON said they would next have presentations from
producer groups.
MR. ROBBIE SCHILHAB, Alaska Gas Producers Pipeline, said Mr. Joe
Marushack was with him and he had addressed them at the last
meeting in Anchorage with Ken Conrad of BP. He said:
Today, what I would like to do is address primarily the
question that you sent to us, Senator Torgerson, to give
an analysis of the proposed legislation. With that, let
me start. Since July when we last met with you there's
one thing I'd like to stay in the forefront, our team has
continued to progress and work. We've got about 100
company employees and about 400 contract employees that
are working through the engineering and environmental
work we've talked about. Hopefully, in the near future,
we'll be wrapping up a phase of that and be able to come
back to you with some information on that on an interim
basis.
Thus far, our analysis indicates that a project is not
economic. I think we've heard a lot of information that's
related to that today. So, that's probably not a
surprise. With that we continue to look at ways to
develop and create an economic project. Because we have
not found an economic project, obviously we've not made a
decision on route either.
Many of the issues that are being evaluated by the team
include looking at the optimization around a pipe size,
around the pressure, the volume that we could handle in
the pipeline, construction techniques, both in the
Beaufort and in the terrain going through the mountain
passes through Alaska and into the Yukon area of Canada
and then, finally, the route center lines which is
critical for us to have that so we can continue to finish
our environmental work. We're still targeting for the end
of the year for both the engineering and the
environmental work to be concluded and at some point,
we'll then be able to come forward with maybe some more
firm decisions.
As I mentioned, my presentation today will really focus
on the proposed federal enabling legislation that is
summarized on the next page of the handout. In general
terms, this proposed legislation seeks to enhance the
existing FERC processes to provide a simpler, more
efficient process for permitting an Alaska gas pipeline
project or projects. Absent this legislation, parties
wanting to build a pipeline could do so under the normal
FERC process in 7(c) in the Natural Gas Act.
This legislation creates a market driven expedited
regulatory process for any viable Alaska pipeline project
or projects. The project would still be subject to the
FERC regulations including the fair and reasonable terms
and provide for an open access consistent with the FERC
rules. The project would be subject to all the
environmental laws and regulations with an environmental
impact statement completed within 18 months. It creates
the Office of Federal Pipeline Director in the U.S. in
the White House to coordinate all the related government
activities and provides for timely judicial review.
Finally, in summary, the legislation helps mitigate the
uncertainty in the risk associated with what could be a
protracted regulatory approval process for a high risk,
high cost project. That's really the essence of the
proposal.
Before I go into the details of the proposed legislation,
a commonly asked question is how does this relate to
ANGTA. Let me go through a couple of points and then we
can talk about them later. First, the proposed
legislation does not alter ANGTA. ANGTA remains in place
and a project can proceed under it. ANGTA is a specific
statute for a specific project passed in the 70s where
certain permits were given to specific parties, rights
now held by Foothills and TransCanada. ANGTA is not
something anyone can file under, only the holder of the
permits can use it.
I'd also like to point out that a lot has changed since
ANGTA was passed 25 years ago. Relative to today's
market, we have a deregulated gas market, which really
has changed the pipeline industry. FERC has moved to a
market driven climate, technologies have greatly changed,
the modern environmental standards are higher than they
were 25 years ago, and finally, ANGTA has obligations and
liabilities that were probably appropriate at the time
they were made 25 years ago that could be a significant
drain or downside to a modern project. And finally, it's
also not route neutral.
Let me turn to the next slide. This is an outline of the
contents of the sections of the proposed legislation. The
essence of the bill is really contained in sections 5 -
9, so I'd like to just go through those five sections and
give you some of the background behind them.
First, under section 5, FERC would be required to issue a
certificate for the Alaska portion of a pipeline to
Alberta if three criteria are satisfied. First, the
applicant must have reached an agreement with a shipper
of Alaska natural gas for the transportation of that gas
with the intent that all or a portion of that gas
ultimately be delivered to the Lower 48 states. Second,
that FERC is satisfied with the shipping rates and terms
and conditions including access. Third, that FERC is
satisfied that the project will comply with all
applicable environmental laws. FERC would be directed to
act within 18 months of receiving an application. And
finally, FERC may issue a certificate for an Alberta to
the Lower 48, what we all B to C, segment by following
their normal FERC procedures. So, in effect, this bill
separates the two large segments, the Prudhoe Bay to
Alberta and then Alberta into the Lower 48 markets.
The next page discusses section 6, which requires
separate environmental impact statements for the Alaska
to Alberta segments and for Alberta to the Lower 48. It
designates FERC as the lead agency for both segments. It
sets the deadline for completing the draft environmental
impact statement to within 12 months of the filing of the
completed FERC certificate application and the final
environmental impact statement within 18 months. It
requires consistency between the scope of the EIS and the
scope of the FERC certificate application. This means
that the EIS would focus FERC's jurisdiction on the U.S.
portion and the Canadian's portion would be reviewed by
the Canadian agencies, which is consistent with FERC's
purview today.
Section 7 on the next page would establish the Office of
Federal Pipeline Director. The director would be
appointed by the President and confirmed by the U.S.
Senate. The responsibilities of the Federal Pipeline
Director include coordinating the expeditious discharge
of all federal agency activities on Alaska gas projects
including all environmental and other studies. This role
includes the coordination with federal, state, local and
tribal agencies as well as coordination with the Canadian
agencies. This section authorizes the funding and
requires regular reporting to the U.S. Congress.
Section 8 directs the federal agencies to expedite their
handling of all Alaska gas project actions. It requires
the federal agencies to cooperate and coordinate with one
another to expedite the decision making process doing
this through MOU's, joint documents, joint meetings or
the like. It prevents federal agencies from including
discretionary terms in the permits if the federal
pipeline director finds that such terms would prevent or
impair the expeditious completion of an economically
viable and environmentally sound system.
Finally, under section 9, challenges to the action of the
federal agencies or officers under this act must be
brought forward within 60 days of such actions.
Challenges would be brought directly to the D.C. Court of
Appeals, with the court directed to provide expedited
consideration of these. The judicial review would be
limited to claims of constitutionality and statutory
authority of FERC.
So, in summary the enabling legislation has five keys: to
provide for expedited review and approval of the
applications, it authorizes the appointment of a federal
director, expedites the resolution of disputes, focuses
on the North Slope to Alberta segment, and specifies FERC
as the lead agency. The proposed legislation is an
essential step to the market based effort to bring Alaska
gas to consumers in a manner consistent with today's
environmental standards. We see this legislation as a
positive step to expedite getting Alaska gas to market
and we hope you see it the same way and will support the
legislation.
Before I close, let me address two other questions that
you had in your letter. First, in the area of Canadian
legislation, we have not proposed any legislative changes
in Canada, nor do we see a need to do so. We don't see
the need for that forthcoming. Finally, in the handouts
of the last meeting, we had included a commercial issue
on gas valuation for royalty and taxes and I think we
heard some of the testimony earlier about that. At this
time, we do not have a specific proposal to offer up.
Again, what we're trying to do is initiate some
discussion around this so we can start identifying the
issues that would then lead to specific proposals. That
concludes my prepared remarks.
MR. MARUSHACK, Alaska Gas Producers Pipeline Team, said it's
important to talk about his enabling legislation. He said:
If you recall, the three companies came together under an
MOU in December. It took us a while to get there because
the companies had different views, but a project like
this requires huge assets and huge commitments and it
made sense to come together. In February, I believe, we
met with both the legislative hearings and in it we said,
'Here's where we're going and here's what our timetable
is; here's what we're trying to do.'
The legislature came back and said, 'What can we do to
help?' and our statement at the time says, 'Please let us
do our work. Let us figure out what we've got. Let me see
if we've got an economic project. Please just let us do
our work. We'll be back when we need help.' So far we've
been on our plan; we're on our timeline to do all our
engineering work, figure out if we have an economic
project, make route decisions by the end of the year.
We're starting to get more and more engaged with the
state on the fiscal plans, on the tax requirements, on
setting up what is the wellhead value as well as trying
to get more information out now, now that we're getting
some information, out to groups such as yourself.
Currently, we have a very tight thin project. Even as we
work the economics and work the technology, it's going to
remain tight. So, what does that cause us to do? That
means we have to reduce the uncertainty. So, we're
focusing on technical aspects and now we're moving into
how do we reduce that uncertainty. The risks are
associated with the market and the costs. The costs, we
can work that ourselves; the market, we have no control
over, although every company will do its own marketing
and there are different things you can do there. But,
timing is also an extremely important issue. Our plan is
to systematically address how we reduce risk and improve
the economics.
The first step is to address timing issues and permitting
issues. What we're trying to do with this enabling
legislation is achieve a known and as rapid response as
possible. We are going to apply and make a modern EIS;
there's no shortcuts; there's nothing in here that we
think is damaging. In fact, we think it ought to be very
much supported by Alaska. It is route neutral at this
point in time. There is no question about that and we
understand there is an issue there. However, I do not see
any way that we do a project eventually without the state
supporting in anyway. So yes, it's route neutral; we
don't know which way we're going to be going yet; we do
not as a team spending all this money, we don't know the
technical aspects well enough of the Beaufort Sea versus
the South, yet to make that decision.
What the proposal does, it works for any pipeline - ours,
others, Foothills. It doesn't affect ANGTS; it could
still be used by any party that wanted to use the ANGTS
proposal. It does not affect state control of the gas
resource, of native rights, of subsistence, and I don't
know why I'm saying this other than I'm getting feedback
from our team that there's been all these claims out
there. It doesn't affect any of those things, which
brings me quickly to the start. You asked what the
legislature could do to help us move this project along.
This is the first time we asked for help. It's difficult
to see how any project can go forward without the state's
support and without this enabling legislation. We think
it's good for the project; it's good for Alaska. It
improves our chances of success and we can get this
enabling legislation done, but I think it's going to
require help from Alaska to see it done. With that I'm
ready to respond to questions.
CHAIRMAN TORGERSON said he appreciated them talking to the
committee.
Our own John Katz and Robert Loeffler don't agree with
your assertion that this has nothing to do with enabling
'77 legislation…I just read you the basically three
things. One, is it could be seen as an alternative to the
1976 with respect to the southern route because it takes
some of the provisions of that - the limited judicial
review and some others - and applies it to any route. The
amendments would give the applicant the control of the
gas a significant leg up in a modified FERC application
process, which you're asking for that to happen. The
other comment that he made is what the enabling
amendments do, for example, with respect to the northern
route, would be to apply the expedite process to that
route and possibly to the same expedited project would be
applied under that amendment to the southern, or in the
case of Foothills, using the expedited process to ANGTA.
So, clearly the two sides don't necessarily agree and
we'll hear from Foothills next to see what they say. I
just make that as a statement; if you want to respond,
you can.
MR. MARUSHACK responded:
I think the first one; you're right on the southern
route. It is potentially something different rather than
being ANGTA. That's a clear statement; hopefully that
came out in here. It works for both north and south. On
your third statement: yes, it would provide enabling
legislation for the north. On the second statement,
though, I don't buy into that one. We worked the language
for several months and tried to come up with something
that we thought was palatable to all the parties out
there. We're not in love with all the language. People
think there's something in there that precludes someone
else from being able to use that. We're open to working
on that. In fact, we expected that there would be changes
made to the language. It's just a matter if I write it,
it's going to have one thing, if you do, it's going to
have another. But, the provision was never to give the
guys who owned the gas a leg up other than to say right
now we're the guys trying to do the project. We're also
trying to do a pipeline and we believe it allows us to
get some sort of certainty and clarity in that permitting
and time process, but if there's something in there that
looks like it doesn't work other pipelines, that wasn't
the intent.
CHAIRMAN TORGERSON said the committee had not had a chance to
debate the issue, but they plan on having a meeting in mid-
September on the legislation. "…We hope to work that with the
administration so that we'll have a unified voice when we go back,
if Senator Murkowski is successful in getting hearings before the
committee, but we haven't had a chance, yet. What you'll hear now
will be individual remarks on it."
5:10
REPRESENTATIVE FATE had two questions based on things he saw under
current analysis, which indicates the project is not economic. It
says that they are still targeting the end of the year for
engineering studies. He asked when they first testified, they had a
project that cost $10 - $12 billion and then "all of a sudden it
goes up to $15 - $20 billion without the engineering completion and
now I see here that it is not economic, at least at this point your
analysis says that. How did we ever arrive at these figures at this
late date?"
MR. SCHILHAB answered:
Let me address that because the danger there is numbers
and we heard it earlier today. Numbers come out and you
really have to understand what's in the numbers. Earlier,
when we talked a $10 - $12 billion project, those numbers
weren't including a gas treatment plant, NGL plant; it
may not have even included some of the lines all the way
into the Lower 48 and some of the development costs. We
talk about a higher cost and it really includes a ringed
fence around the entire project. Unfortunately, as we
start talking about these other numbers, we really need
to be explaining that these aren't any different because
we really are working off the preliminary numbers that we
were sitting down and talking with you in the April
timeframe. We're starting to refine some of those
numbers, but a lot of that is around adding or taking
away compressor stations, doing some modification to the
gas treating plant or getting a little bit firmer numbers
through the engineering. Those numbers still haven't been
modified. Those are the numbers that we really feel like
that by the end of the year we will have modified and
then be able to look and make a decision of whether
there's an economic project. In today's terms it's really
not too much different than it was in the spring when we,
again, didn't have an economic project that we felt was
robust and we could go out and start sanctioning and move
forward. I would think that by the end of year before the
end of the year, we're going to be in that position of
where we can do that.
REPRESENTATIVE FATE said he hope as they refined their figures that
it would lower and become economic.
MR. MARUSCHACK said that was their hope, too.
Just to be clear. The reason that Ken mentioned the $15 -
$20 million last time is because people are out there
with all sorts of numbers and we talk that number, we're
talking about the gas treatment plant, the pipeline all
the way to the Alaskan border, a brand new pipeline all
the way to Chicago and the NGL system. So, that's a fully
integrated project that has all the pieces in it and
there's a lot of things we're trying to do in order to
make that more economic. One of the things we can do is
address timing uncertainties and that's part of the
legislative enabling action that we're looking for.
REPRESENTATIVE FATE said he had one more question:
The next page over says that enabling legislation would
be market driven, expedited regulatory process for any
viable project, then under that it says it's subject to
FERC regulation, fair and reasonable terms, open access,
which leads me to another question. If one of these third
parties, and we've mentioned Enron and Williams and
Foothills. If one of these third parties came to you and
said I'm ready to buy your gas and I'll buy it at the
wellhead that gives you a heck of a profit. Would you
sell that gas?
MR. MARUSHACK replied, "We do things like that all the time,
Representative Fate. Most of our gas is sold at the wellhead, so
that would not be unusual."
REPRESETNATIVE FATE said that was a hypothetical answer and asked
if he wanted to build a pipeline and own the gas and build a
pipeline or would he sell to some other project group?
MR. SCHILHAB answered:
What you're getting into is the individual companies as
opposed to a joint project team. A joint project team is
together to try to come up with the lowest cost solution
to get gas to market so that we can sell it. If somebody
came in with an alternative and had a better mousetrap
that would be lower than something we have on paper that
we're looking at, I think the answer is yes. As long as
you felt like they would control it, they were going to
maintain that at that lower cost and they had the backing
to ensure a high degree of confidence that it was going
to get built. If somebody came to you that you never
heard of, that you don't know whether or not they really
understand the pipeline business at all and said they
were willing to buy your gas, you would probably think
twice. Because what you're trying to do is market that
gas at the best price, lowest cost to market so that we
can compete and compete against all these other
alternatives that are going to be in the market place.
REPRESENTATIVE FATE said the parties he was thinking of certainly
qualify under the criteria he presented.
CHAIRMAN TORGERSON asked if anyone had made an offer to buy the gas
on the North Slope, like Duke or Enron?
MR. SHCILHAB answered that to his knowledge no one has made an
offer to Exxon Mobil.
MR. MARSHACK said:
A proposal is a difficult thing to say. Let me tell you
what has happened and then you can interpret that. We
talk with marketers all the time. We talk to the ones
you're talking about, we talk to other ones. We have
talked about his project, too. We have talked about the
possibility of long term fixed, we've talked about the
possibility of spot, we've talked about buying it at the
wellhead, down in the Chicago, all these other places. We
have not done any firm deals on it, yet, and there's a
whole myriad of reasons for that. It really gets into
anybody has got the same dilemma that we've got right
now. But we're exploring all those sorts of things. Do we
have a bonafide offer on the table, but could you sign a
contract? No.
REPRESENTATIVE OGAN said he wanted to talk about the congressional
statement of purpose in section 3. "It looks to me like subsection
(a) they are relying on competitive market forces to determine
which set system or systems can be built and operated in an
economically viable manner."
He said it sounds to him like an end run around a law the
legislature passed last year saying the only thing that's legal is
an Alaska Highway route. He asked if he was wrong.
MR. SCHILHAB answered:
I don't think the intent was to fly back in the face of
the state. The intent was to try to get legislation that
would allow a project to go forward. That's through this
legislation or to have just an open market driven type
process that would allow a project that's economic to
move forward and compete with other projects. If other
projects want to move forward, there's competition and
the one that's going to be the strongest will probably
get built.
REPRESENTATIVE OGAN said if the northern route is the one that's
economic, and it's in the federal law that this is what happens,
that could supercede state law and they could build the northern
route. He asked if that's what this legislation would do.
MR. SCHILHAB responded:
As I mentioned earlier, before a project is going to get
built, there's going to have to be full support from the
state that they would want the project to go forward.
That would be a northern route, a southern route,
whatever that project is. At that time, they would have
to address legislation or other rules that are there.
There will be other things we'll have to work out. We'll
have to change the field rules.
MR. MARUSCHACK interrupted:
Representative Ogan, the intent was not to specifically
find some way of getting around the state 164. The
procedure is route neutral right now. That was not our
primary…We weren't trying to take a hammer to 164.
REPRESENTATIVE OGAN said he was confused and asked if the federal
legislation, as written, enabled them to build a northern route.
MR. SCHILHAB said, "It doesn't preclude it."
TAPE 01-16, SIDE A
4:19
[THE FOLLOWING 14 MINUTES OF TRANSCRIPT WERE DONE MOSTLY WITH THE
HELP OF NOTES, BECAUSE OF RECORDING DIFFICULTIES]
REPRESENTATIVE OGAN said he was glad to hear that, because the
state doesn't support the northern route.
CHAIRMAN TORGERSON said he wasn't sure there wasn't another barrier
with Representative Young's amendment. "You're not going to get
them both in the same bill."
SENATOR KELLY asked what their assumptions were for pricing.
MR. SCHILHAB replied that it wasn't the same as CERA's testimony.
They used an interest free number.
CHAIRMAN TOGERSON asked what the timeline was on these projects.
MR. SCHILHAB replied that they are still committed to finishing the
interior and environmental studies by the end of the year.
MR. MARUSHACK replied that to do the work they needed to do and
have an open season so people could try to respond to it, and then
do a filing pushed them back three months. "There will not be a
hard yes or no on this thing. I hope that we will see continued
progress to try to get this thing on line…decade."
REPRESENTATIVE OGAN said their legislation seems to preclude any
LNG project that specifically addressed gas to the Lower 48 and
asked if they would consider adding LNG to it.
MR. MARUSHACK said he didn't think it was necessary…
There were continued questions from Representative Davies and Ogan,
with answers from Mr. Schilhab and Marushack.
4:34
[TAPE RESUMES]
FOOTHILLS PIPE LINES LTD.
MR. ELLWOOD, Vice President, Engineering and Operations, Foothills
Pipe Lines Ltd., said:
FERC had no preference for receiving an application under
NGA or under ANGTA and while that may be so, I think the
truth is that there is no provision in ANGTA for anyone
to apply for a certificate of public convenience and
necessity. That statute is specific to the ANGTS project
and can be used in the same way the Natural Gas Act can
be used.
Turning, then, to the proposed legislation, we have had a
look at this and we have reached the conclusion that
legislation of this type is required. It is not needed to
provide the legal and regulatory framework to expedite
the construction and operation of an Alaskan natural gas
pipeline. That legal and regulatory authority or
framework already exists in the Alaska Natural Gas
Transportation Act (ANGTA) and the proposed producer
legislation in our view contradicts the very purpose of
ANGTA. If enacted, it's our view that it would create a
very chaotic and confusing parallel procedure for
authorization of a natural gas pipeline from Alaska.
Clearing up that very confusion and chaos was the very
purpose of ANGTA in 1977.
We believe that the enactment of that producer
legislation as drafted would be justified only if
congress desired to accomplish two objectives. One of
those would be if congress desires to revisit the
previous careful and deliberative selection of the Alaska
Highway route as the most economical and environmentally
sound route and if congress desired to allow for
consideration of other routes including the over-the-top.
The second provision would be that this might be the kind
of legislation one would enact if you wanted to authorize
a filing of new producer sanctioned applications that
could exclude any independent pipeline participation in
the ownership and the governance of the Alaska pipeline.
Our evidence to support those conclusions is found in the
legislation itself, in that each of the major provisions
designed to expedite construction and operation of the
pipeline is copied almost directly from the existing law,
the ANGTA.
As you are aware, ANGTA engaged the regulatory expertise
of the federal agencies, the international expertise and
jurisdiction of the president and the public decision
making process of congress before selecting the route and
the project to deliver Alaska gas to the Lower 48. In
contrast, this legislation would appear to place
responsibility for those critical judgments in the hands
of the North Slope gas producers. In our view, this
raises profound public policy issues, not only for
congress, but also for natural gas consumers and for
Alaskans.
Finally, we would note that the proposed legislation is
not needed because the parties already authorized to
construct and operate the Alaska Natural Gas
Transportation System, that is ourselves, Foothills,
TransCanada and West Coast, we are ready willing and able
to build that pipeline as soon as the producers decide to
market their gas. In this regard, Foothills continues to
explore avenues to establish a collaborative dialogue
with the ANS producer group and we urge this committee
and through it the legislature to publicly encourage all
stake holders to initiate some real and substantive
collaboration and discussion regarding the proposed
Alaska Natural Gas Pipeline.
One more issue that I would like to comment on here -
there's been a suggestion from time to time that
proceeding under ANGTA is some how a way to shortcut the
environmental process or circumvent it or fail to proceed
in an environmentally sound manner. I want to assure you
that in our view that is absolutely false.
Proceeding under ANGTA will provide the same degree of
environmental protection as under any other statute. The
laws of the country are the laws and we will obey them;
we will meet or exceed all standards.
I would like to say a few words about the withdrawn
partner issue. I'll be very, very brief here. We just
want to inform the committee that the remaining partners
in the Alaska partnership - the ANNGTC (Foothills and
TransCanada Pipe Lines) - we are making progress towards
eliminating any potential future contingent liability to
the withdrawn partners. Discussions with the withdrawn
partners have commenced and although the specifics of the
matter is being discussed, it must remain confidential
until resolution is achieved. We do fully expect that
these discussions will lead to removal of issues that are
perceived to impede implementation of this project.
Finally, I would like to say a few words about where we
stand relative to the Mackenzie Valley project and how we
see both Alaska gas and Mackenzie Delta gas being
developed. Firstly, we are strongly of the view that the
market can absorb production from both Alaska and the
Mackenzie Delta. We have publicly advocated a two-
pipeline approach. In our view it is important to
acknowledge that the long-standing concern of the
government of Canada about possible stranding of
Mackenzie Delta reserves. That is an issue for our
government; we think it is a legitimate issue for them to
consider and we are trying to address their concern. From
a historical perspective, that's the same concern that
existed when ANGTA was passed. In the context of a recent
question on how to expedite that Mackenzie development,
shareholders of Foothills have suggested to the Canadian
officials that they focus on a stand alone Mackenzie
Delta project, separate it from any combining or over-
the-top route. Similarly, we would urge Alaskans to focus
on committing to get the Alaska gas to market and we
believe that the way forward here is for Alaska to
endorse ANGTA and the ANGTA process and openly support
the Alaska Natural Gas Transportation System. That's the
end of my non-controversial remarks.
CHAIRMAN TORGERSON said, "You kept it pretty clean. I have to give
you credit."
REPRESENTATIVE DAVIES said the previous group testified that they
had discussions with a number of independent pipeliners and asked
if that included Foothills.
MR. ELLWOOD answered yes, they are talking with the North Slope
producer group and they intend to continue that.
REPRESENTATIVE DAVIES said they also heard from them that there is
no bonafide offer on the table that one could sign tomorrow if the
sanctions were given and asked why that was the case.
MR. ELLWOOD replied:
I believe that discussion was in the context of an offer
to purchase their gas and that's not our business. We are
transporters of gas, not purchasers. So, we would not put
an offer forward to buy gas. Marketers will do that or
end users might do that. But we are the trucking company
of the gas business and we don't own the goods that are
in our truck.
To put forward an offer, to jointly develop such a
project is a long and complicated process and is not
something that we could envision putting forward an offer
that they could simply sign. We need to understand their
objectives, where the markets are and all these matters,
which are a matter of some lengthy discussion between the
parties before a commercial deal could be written up on
paper.
REPRESENTATIVE DAVIES asked, "But if you're a trucking outfit,
can't you give them your tariff?"
MR. ELLWOOD answered:
The tariff is one thing, but the toll when you don't know
how far you want the goods to travel is a different
matter, or what volume of goods. All of those matters are
of crucial importance, of course, to the producers and
that just needs to be worked out over some time.
REPRESENTATIVE DAVIES asked if they were basically a by-stander in
the process?
MR. ELLWOOD answered:
No, I don't think that we're a by-stander. We're an
active participant here. We are in discussion with the
producer group. We are in discussions with marketing
companies, with end users, to see where and how the
various parties could come together and what that
commercial arrangement might look like.
CHAIRMAN TORGERSON said he wanted Mr. Ellwood to talk a little more
about the Mackenzie Delta reserves, because they are competing
projects and he didn't disagree with his assertion that they should
be looking at two, but he is in the camp that the first one ready
to go is going to be the winner and the other may be stranded for a
few years.
Clearly, you said from the historical perspective, they
recognized that in the '77 law when they put the Dempster
lateral in as part of that, but now we're suggesting not
to do that and have two stand alone projects. What's
their timeline for moving Mackenzie Delta versus what you
think you think our timeline is in Alaska?
MR. ELLWOOD replied:
I only know what we read in the papers about the timeline
for the Delta producers and that's quite vague. They are
in a similar position as producers are here. They have a
study group; they are looking at what the economics of
the project might be. Our shareholders have their own
view of that matter and I have seen some of their numbers
that suggest that it would be economic. With respect to
the stranding issue and which one goes first, most of the
discussion that I have heard to date would center around
a flow of gas from the Mackenzie Delta between 800 MCF/D
and 1.5 BCF/D, which is a very small quantity to absorb
in the market. I think we heard from CERA today that they
are expecting the market to grow about 1.5 BCF/D. So,
that's half enough to perhaps fit the growth in the
market next year and, in my view, would not strand Alaska
gas at all. Likewise, I think the market growth in the
timeframe in which one can do these fairly large projects
is such that if Alaska gas were to reach the market
first, the Mackenzie Delta gas would not be stranded
either by the time we could get that project to go, by
"we" I mean the industry, there would be room in the
market for it as well.
CHAIRMAN TORGERSON commented that he had mentioned to some of his
staff that the withdrawn partners is a bigger issue than he thinks
from what he heard back in congress.
Foothills has a $4 billion price tag on it before they
even start throwing dirt around. So, it is a major issue
and they all seem to be vaguely familiar with the
withdrawn partners and the debt that has accumulated over
a period of time. Somebody suggested that's the
conspiracy theory going with the producers; they've run
around flopping this rumor all over the capital, but at
any degree, it's all over and you need to, I believe at
least, get this thing settled so you, once and for all,
come up with a number of what it's worth or where you're
starting from or what you have to offer for sale, besides
the $4 billion.
The other one is, and I think you heard the remark that
the committee is going to be looking at this legislation
soon and I'd like to request that you give us a little
bit more detail, section by section, if you would, on
your remarks about if it's an identical section to ANGTA,
if you would reference that section and just some general
remarks about what you think those particular sections do
and I hope to get that from the producers and then sit us
all down and work through this a little bit at a time.
We'll be dealing section by section when we go through
this and word by word, more than likely…
REPRESENTATIVE DAVIES said they also heard that the producers'
legislation could be passed and leave ANGTA entirely in tact.
"Assuming that were to happen and that a project were to go forward
under that new legislation, it seems that you would be in the
position where a considerable grant of privilege will have gone by
you. Do we then get into protracted court battles?"
MR. ELLWOOD replied, "That's one possible outcome, yes."
CHAIRMAN TORGERSON asked if they had similar issues surfacing with
the NEB (National Energy Board) that we do with FERC on the treaty
or on any of the access questions or things that we have been
wrestling with our regulatory commissions.
MR. ELLWOOD answered:
To my knowledge, Mr. Chairman, our National Energy Board
has not really indicated whether they believe that they
could hear an application under the National Energy Board
Act as opposed to the Northern Pipeline Act. I know that
they are asking themselves that question and it may come
forward as it has with the FERC. I don't know their
answer at this stage.
REPRESENTATIVE FATE asked if he had any idea of what state of
development the Mackenzie field is and off shore of that? He has
heard that they are not ready to transport that gas out, because
they aren't in the state of development that Prudhoe Bay is.
MR. ELLWOOD replied:
That's clearly the case. There has been some exploration
done in the Mackenzie Delta. There was one well drilled
this winter. Prior to that, all of the exploration had
been done 15 - 25 years ago, somewhere in that timeframe.
There is some uncertainty and different numbers floating
around as to what is the size of the reserve - somewhere
between 6 - 9 TCF as opposed to 35 TCF proven for the
North Slope area. There is one small bit of production in
the Mackenzie Delta right now. There is one well that is
in production and is delivering gas through a very small
pipeline a few miles into the town of Inuvik, but there's
no real production facilities of the scale that would
support a pipeline as there is on the North Slope. So, in
terms of the infrastructure that will be needed there,
the North Slope is clearly more developed than the
Mackenzie is right now.
REPRESENTATIVE FATE said: "As a comment for those of you who hadn't
seen his picture, he makes a very good director of the FBI."
4:52
CHAIRMAN TORGERSON thanked Mr. Ellwood for joining them and
announced they would take a short break before calling the
committee meeting to order in which they would cover their brief
agenda.
5:00
JOINT GAS PIPELINES COMMITTEE MEETING
CHAIRMAN TORGERSON called the Joint Pipeline Committee meeting to
order. The first item is a discussion of the official protocol trip
that is next Monday and to get that information disseminated to
everyone. The rest is to set dates for the next two meetings - one
for the draft sponsors' legislation and the other one for the next
regular meeting and then general discussion on the schedule.
MS. RONDA THOMPSON, Special Assistant on International Trade Policy
for the Alaska Legislature, asked them to look through the
itinerary she gave them for the Western Canadian Protocol Mission
on August 20 - 25, 2001.
CHAIRMAN TORGERSON thanked her for all her work and discussed the
committee's agenda.
RERPESENTATIVE DAVIES said there was a letter from Commissioner
Pourchot and asked what was the process for coordinating with the
Governor's Office for a united front on this issue.
CHAIRMAN TORGERSON said the Policy Council is meeting in Anchorage
on August 17. He had asked Foothills, the producers and John Katz
for a side by side sectional analysis so they could see where the
real conflicts are and, at this point, will have to invite the
administration to be there. John Katz and Bob Loeffler would be
there.
REPRESENTATIVE DAVIES said it would be helpful to have the Governor
designate someone to be at that meeting.
CHAIRMAN TORGERSON said he thought it would be good to have a
meeting on the same day as the Council since he thought they would
be taking up the same issue, although their functions are
different. He said that he firmly believes Alaska needs a unified
front.
PUBLIC TESTIMONY
MS. KARA MORIARTY, President and CEO, Fairbanks Chamber of
Commerce, thanked them for having their second meeting in
Fairbanks. She said:
Commercialization of our natural gas resources is a
massive undertaking. As we have heard for the past two
days and as we heard in Anchorage as I attended those
meetings, this project is very much a work in progress.
Our chamber put together a gas line committee about nine
months ago to begin the process of learning and
understanding the dynamics involved with this project.
Obviously, it's a lot for community volunteers to get
their arms around, but our goal is to be able to
communicate with all the parties involved including your
committee to be able to make sure the needs of our
community and state are met. As the committee has met
over the past several months, we have definitely learned
two things. One, we have lots more to learn and two, all
Alaskans need to work together on this project.
The chamber sees much potential and benefit for our
community with the development of this resource and we
just wanted to stress publicly and on the record our
willingness to work together with all involved that this
project comes together…
MR. GORDIE LEWIS, Golden Valley Electric Association, said they are
a cooperative serving over 90,000 interior Alaskan citizens and
they fully appreciate the value and importance of open public
participation. He assured the committee that they, "stand ready to
provide the power necessary for any potential future opportunities
throughout the construction, operation and maintenance life cycle
of this most important and far reaching initiative."
He said further that:
We're convinced that this project must be integrated into
a state sponsored 50-year long range energy plan that
creates the vision and goals for addressing the state's
energy needs and use of our resources for the next 50-
years. Such a plan should at a minimum should direct free
and open access to gas as stipulated in 18 CFR, governing
U.S. gas transmission infrastructure, create common
carrier status under a State Certificate of Public
Convenience, insure access to state gas royalties in-
kind, which provides a real and lasting price point
benefit for state residents, develop a price for royalty
gas used in state and designate royalty gas proceeds for
the creation of a state energy fund charter that insures
future development of renewable energy supplies.
Fairbanks already has the infrastructure and trained and
ready workforce needed for such an undertaking and such
routing in turn makes the possible establishment of a
Fairbanks-based gas hub a reality. This hub with ready
and easy access to cost competitive fuel can serve as a
cornerstone of renewed economic development creating
opportunities for new industrial, commercial and personal
value adding enterprises. Ready access to this most
efficient and cleaner burning fuel, when added to our
current energy mix at Golden Valley will help us
demonstrate responsible, responsive leadership in meeting
increasingly stringent air quality standards while
supporting an on-going responsibility of serving today's
citizenry while meeting the future needs of the interior.
Your crucial and timely decisions will ensure that all
involved are remembered as visionaries and leaders that
responded to this moment in history. With business and
government working together, we can develop a plan that
results in a more robust and diversified economy that
insures current and future generations the ability to
continue to live and work in our great land.
MR. PAUL METZ, Department of Mining and Geological Engineering,
UAF, said that he was testifying on his own behalf. He said:
The economic analysis of mineral and energy projects is
very sensitive to the quantities of the resources and the
commodity prices, as you all know. We're dealing here
with an energy resource that there's considerable
substitutability for, and therefore, the prediction of
prices over the expected life of this project is a
monumental task. We've seen how volatile the prices of
energy commodities have been over the last year and
projecting that over a 20-year life makes it a very great
challenging to the engineers and economists dealing with
this problem.
As important as price is the quantity of the commodities
and we've heard a lot about the 30 - 35 TCF of proven
reserves on the Arctic Slope of Alaska. These proven
reserves have been found without the expenditure of a
dollar of exploration dollars for gas. This is a
byproduct of oil exploration and development. I think
this is very significant. What we haven't heard over the
last couple of the days are the producer's projections
that there's an additional 60 - 65 TCF to be discovered
once there is an economic incentive to do exploration for
gas on the North Slope. This brings the sum total to 100
TCF, plus or minus.
Again, what we haven't heard in either the discussion
today or in the debate with respect to ANWR is the
quantity of gas that the U.S. Geological Survey estimate
in the coastal plain of ANWR. This again is based on
limited drilling data and limited seismic work that has
been done many years ago. Again, the best median
estimates of both the U.S.G.S. and State Geological
Survey are 60 - 65 TCF. This brings the sum total of the
resource on the Slope to 165 - 170 TCF, which is
equivalent to all the natural gas in the United States in
the form of proven reserves. I think this is really an
important issue, both with respect to the economic
analysis of the project, the various routes, and of
course with respect to the decisions on royalty and
pricing issues, but also with respect to the debate on
the opening of ANWR for development. I encourage the
committee here to examine that.
Those are conventional gas reserves. The unconventional
gas reserves on the North Slope are much, much larger.
The Chair very pointedly made some important comments at
the Chamber meeting yesterday with respect to competing
resources in Canada, particularly in Alberta. The total
gas resources of Canada exceed 500 TCF, which is
extremely large [END OF TAPE].
TAPE 01-16, SIDE B
MR. METZ continued:
Those resources are relatively small compared to the
other energy resources in Alberta, though, and I would
encourage you to look at those on your visit there.
There's 300 billion barrels of recoverable oil and the
Athabascan tar sands. There's huge coal resources similar
to the huge coal resources we have here. So, in terms of
total energy resources in North American, Alberta and
Alaska have very large potential resources that need to
be considered. We need to be considering these resources
not in the terms of oil or tar sands or gas or coal, but
in the gas equivalent that may be transmitted through the
pipelines, whatever routes are finally selected.
The important thing here is that there are huge
quantities of gas hydrates in the Canadian Arctic Islands
as well as in Northern Alberta and the Northwest
Territories and Yukon Territories, but there's even
larger quantities of gas hydrates here in Alaska.
Estimates of 1,200 TCF have been published by the U.S.
Geologic Survey. So, these gas hydrate resources dwarf
our conventional gas resources. The coal resources that
could be converted - either the extraction of coal by
methane from those coal resources or the conversion of
those coal resources to gas - dwarf the gas hydrates that
are available. So, in terms of the resources and the
quantities and the valuation of the economic feasibility,
we need to look at certainly those resources that can be
recovered within a reasonable time period - 20 years from
an economic standpoint. But from a policy issue point of
view, we need to look at those larger resources -
unconventional gas, gas hydrates, coal bed methane, the
gasification of North Slope coal and other coals in
Alaska.
CHAIRMAN TORGERSON said they had the MMS at their last meeting had
run through about a half hour of known reserves and potential
undiscovered reserves on the North Slope as well as all over the
federal jurisdiction of the state. "One of the interesting things
you mentioned, hydrates, they estimate that we have 170,000 TCF of
hydrates in Alaska."
SENATOR TED STEVENS
CHAIRMAN TORGERSON then welcomed Senator Ted Stevens.
SENATOR TED STEVENS said he was glad to have the opportunity to
visit with the committee. He said that Congressman Young had done a
terrific job on the energy bill with the help of a lot of people,
particularly Jerry Hood of the Teamsters. He said:
That bill has a very uncertain future right now with the
opposition of the majority leader in the Senate. Under
our procedure only the majority leader can call up a
bill. Senators can offer amendments, but calling up a
bill is another matter. So, we're going to have a tough
job trying to figure out what to do about that. Clearly,
the gas pipeline has another set of facts. Members are
after us all the time asking when will Alaska's gas be
available to the South 48. So, I don't think if there's
anything that has to be done by the Congress that there
will be this problem at all with regards to the gas
pipeline.
There is a draft that has been submitted by the
producers. I'm not too happy with that bill, so far. I
think there's a lot of explanation we have to have before
we think about that. Frank's staff has that and I don't
know what they've told you, but they are reviewing it. I
really didn't have a chance before I left on the second
of August to really read it. I had some explanation of
it. Justin [Stiefel] probably knows a lot more about that
than I do right now. I'm still convinced that the highway
route is the best route for us and I congratulate the
legislature for making that clear. Clearly, that's the
option we need to bring the gas down to where we can use
it not only to meet some of our needs, but also in the
future if it's as great as we think it is, to use it as a
commodity. And clearly we have the option to go to Valdez
and Anchorage, as well as the South 48, if it comes here.
As these people have come to my office, we have made it
very plain that that's the case.
As a matter of fact, I had a visit with some of the
producers' representatives here recently and they said
the economics didn't look too good if the gas price goes
down and asked me what I thought Alaskans would do if
that's the case - if the economics require a higher
sustained gas price to pay for this extremely long
pipeline. And I said, 'We'll wait. We've waited this long
so far. I don't think there's any rush to take our gas
out by a pipeline that crosses the top of the state and
leaves and doesn't answer any of our needs.'
The people that propose that will tell you that it'll
mean a massive increase in our Permanent Fund, if that's
the case, but that massive increase won't offset the
increased cost of energy that we all predict out into the
second decade of this century. So, I don't see any reason
for us to even consider the other proposal. I've told
them very seriously that we would do everything we could
to join the state legislation in getting the Congress to
prohibit them from taking that gas across the Arctic. As
you know they plan on taking it out in the ocean and take
it through over to Canada and pick up the Canadian gas.
The Foothills people have been in to see us and they are
very disturbed with that proposal as we are, but clearly
what we're doing now is trying to work with Frank and the
Energy Committee as they review the energy bill. I hope
it will not be necessary for us to take any action to
assure the gas pipeline comes through Alaska, but I think
it may be possible.
That bill, by the way, I should speak a little more about
that. As you know, I was chairman of the Appropriations
Committee and now I'm ranking member of the committee.
Senator Byrd confers with me quite often as I used to
with him, but clearly we have not sent to the President
any one of our 13 bills. We have 13 appropriations bills;
we have the patients' bill of rights bill; we have the
bill that deals with campaign reform; we have the bill
that deals with issues of Medicare particularly with
payment for prescription drugs and we have about 12 weeks
of actual session left when we go back into session
before Thanksgiving. I don't think it's possible for us
to contemplate the energy bill will come up and be a
cause celeb in that time. I don't know what their tactics
will be, but I'm sure they're going to try to take some
action to defer at least the subject of ANWR in the
Senate and deal with some of the other issues involved in
that bill. Frank will have to tell you what his strategy
will be with regard to the energy committee. I'm just
assessing the situation from the point of view of the
time left on the floor this year.
Under the Senate procedures, as you know, there would be
three or four possible filibusters against one bill. I
don't see any reason for us to stand back, if they're
going to filibuster if ANWR's is in the bill. I told
them, 'Okay, we'll filibuster if it's not in the bill.'
We'll just have to see what comes from tugging at this
subject as far as the new majority of the Senate is
concerned. Clearly, back to your subject, I think that
the future is very great for gas in our country. The
demand is increasing. Supplies aren't that available. I'm
not sure how high the gas price has to go and stay to
justify building that gas pipeline, but it's going to be
very interesting to see the economics, which as you know
are now being prepared.
Incidentally, they are doing the study of the route
across the Arctic, but that is a necessary thing from the
point of view of complying with National Environmental
Policy Act. In order to be able to deal with the EIS,
they would have to show that they've examined all
reasonable alternatives. I looked at it as a RA study, in
terms of studying across the Arctic. I do believe some of
the producers would rather have that route, as you know,
but I'm convinced a great majority of Alaskans will stick
with us and say it must take the Alaska Highway route.
CHAIRMAN TORGERSON explained that this committee would convene
again in Anchorage on September 19 along with the administration
and they would look over that legislation in more detail and
prepare unified comments for Senator Murkowski. He asked:
Just one question I had on ANWR, just in case your
filibuster approach doesn't work, a couple of years ago
it came across in the budget reconciliation act, is that
a possibility that there'll be another similar bill that
provisions could not be filibustered that this might
surface next year?
SENATOR STEVENS replied, "There won't be one this year; there will
be one next year. We've had our reconciliation act for this year
and it contained the tax bill, as you know…"
CHAIRMAN TORGERSON asked, "Even if we lost the debate in the Senate
this year, there is still a strong possibility that that would be a
fallback position to try to put it in the reconciliation act for
the beginning of next year?"
SENATOR STEVENS replied:
It's still a possibility. Senator Conrad, Chairman of the
Budget Committee would probably oppose that because his
colleague, Senator Daschle, opposes bringing it up on the
floor in any manner, but it would still be possible to
offer this amendment to that bill when it got to the
floor. That's sort of one of the last resort measures
that I see it might be possible to get it within this
Congress. The President is for it; the House has voted
for it and I think the Senate ought to at least have an
opportunity to vote.
Back in the days when we got the old pipeline, there was
sort of a gentleman's agreement that any issue that
involved national security would not be filibustered and
we were able to reach the position that building the oil
pipeline was a matter of national security, although the
vote was very close, it would have never passed if there
had been a filibuster.
REPRESENTATIVE DAVIES asked what the timeframe was in the Senate
for the producers' bill and was there a need for legislative
attention to the National Gas Act or ANGTA?
SENATOR STEVENS responded:
Senator Bingaman is chairman of the committee that Frank
used to chair and the producers are a very powerful
organization in our country. If they decide they want
that bill brought up in spite of our opposition, and I
would opposed that bill, it's going to be an interesting
situation. I don't think that bill will pass without our
support in the Senate. As it stands now I would oppose
it. There has to be some substantial changes on it. If
it's a bill to really accelerate the capability of the
producers to get final approval to build the pipeline,
that's good motivation for us to get a bill passed. But
if it's one that going to assure that they alone will
have the decision as to what route to take, then I'm not
in favor of it at all.
The timeframe is going to be up to Senator Bingaman. I
think we could get it to the point where it does do what
I said, it accelerates the ability to proceed with all
other clearances that are necessary and hopefully we
would get to the point of one-stop shopping in terms of
the approvals that are necessary other than court review,
which I think will be inevitable. That could be done very
quickly, if that's what the producers want. They did
discuss with us that problem, the problem of the myriad o
of applications that are necessary to proceed.
REPRESENTATIVE DAVIES asked if he thought that would preempt ANGTA?
SENATOR STEVENS replied:
No, I don't see any preemption involved in the bill that
would be the kind of thing I'm thinking about. The
timetable is such that the building of it doesn't have a
short timeframe for design and construction. So, we're
not to the point of crisis yet the way we were in the old
pipeline days when we had to get a bill passed in order
to start, because we had been delayed already for four
years by the environmental litigation. Should we ever get
to that point, I think the bill would have a different
characteristic than the one I envision right now.
CHAIRMAN TORGERSON asked: "We heard today that one of the producers
is floating the idea of having the downside protection guaranteed
by the federal government basically if the price of gas got down
too low, that they might receive some royalty credits for future
federal things - sort of sharing the risk a little bit. Do you see
any chance of any proposals or any incentives like that passing in
the Senate?"
SENATOR STEVENS answered:
It would really come in the point of view of a tax issue,
you know. If you look at that from that point of view of
saying that the gas price falls below a certain level,
then there's some special consideration of taxes for the
producers, that might be possible for a project of this
size. One of the considerations, of course, is that
Canada is going to get a sizeable payment for the use of
a pipeline that travels 2,000 miles in their country.
There's so many things involved in this economic study
that we really don't know for sure how to quantify them,
yet. I think it is possible that there could be some
escape hatch for this pipeline in the event the price
dropped down below a level that there would be special
tax considerations for the producers as they sold their
gas to assure there was a market price for that gas
coming through. On the other hand, I'm also sure that the
people who produce gas in the South 48 now wouldn't like
that too much, because it would mean that this enormous
supply would engulf the market at a price stabilized by
tax incentives, whereas the others do not have that. It's
not going to be an easy fight for the producers to get
that unless it's something that is worked out with the
gas industry as a whole in the United States.
REPRESENTATIVE FATE said:
Taking up where Representative Davies left off on both
the Alaska Natural Gas Transportation System and Act, it
was suggested today that a reconfirmation of both that
system and that act either be undertaken by either FERC,
and there was a question of whether they had that
authority, or the congress, itself. Have you got any
comment on that, Senator?
SENATOR STEVENS said:
I haven't crossed that bridge, yet. We have discussed
that in several sort of think sessions with the
producers, but they have been unwilling to spell out what
they are willing to take on as far as a burden of
legislative effort to assure the early construction of
the pipeline. I don't think there's a great hurry. They
don't appear rushed in terms of proceeding with the
pipeline. We all know that. It's been a long time since
that gas was discovered and they haven't moved forward,
yet. There is no urgency from the point of a penalty for
not moving forward and I don't think it would be possible
to create one that would be acceptable. I think we'll
have to wait and see how the route they want to proceed
with to see what has to be done to comply with federal
law and determine whether we can modify any of those
requirements to accelerate the pipeline's construction. I
haven't formed an opinion on that yet, mainly because
they haven't asked us to consider any option, yet.
CHAIRMAN TORGERSON said:
One of the confusions is if they file an application
under the Natural Gas Act, if they could do that over the
top of the Foothills application, which is filed under
ANGTA. We've been fencing with FERC trying to get an
answer from them of which one of these federal laws
prevails in Alaska. We had the El Paso proposal in '77
and the over-the-top, which is the ANWR proposal, we had
almost the same thing as we do today and the President
made a decision under the Natural Gas Act and Congress
passed the ANGTA. Foothills believes and is ready to
defend that in court that they have the only authorized
route, which is the highway route down. FERC has
basically said that if somebody gave them an application
under either act, they are required to respond. What
Representative Fate is talking about is today they said
maybe the quickest fix would be a congressional fix, to
have congress look at this and decide which one of these
acts prevails today and if there's any cleanup because of
the 20 - 25 years since the old act passed, then congress
should maybe look at that instead of a regulatory agency
such as FERC.
SENATOR STEVENS replied:
I think you can come to the conclusion that congress made
a decision when it responded to President Carter's
request and passed the act that accompanied the treaty. I
really think Foothills has, literally, a foot in the
door. On the other hand, the other project going across
the top of our state was not contemplated at that time
and I don't think we could say that project is prohibited
by existing law. I do think that Foothills is right that
as far as Canadian law is concerned, they have all the
rights they need to proceed to construct a pipeline and
transport that gas once it comes into their country. The
problem is in our country and I don't think FERC could do
other than just give an off the cuff opinion right now. I
hope we don't see that day, because I think it's going to
be a bloody day. If the producers file an application for
a northern route, we're at a stalemate as far as we're
concerned. I'll be very surprised if we get to that
point, because they are part of our economy and they are
going to have to live with us just like we have to live
with them. I do not expect to see that come.
CHAIRMAN TORGERSON said hoped they wouldn't see an application for
the over-the-top. It is banned in the energy bill, also:
It's no longer just the state of Alaska that has passed
legislation. We have half of the congressional part
passing it and we certainly have plenty of testimony from
the North Slope Borough that they won't settle for that
and the Whaling Commission and everything else.
SENATOR STEVENS said that could come through the committee if the
bill is reported. "On the other hand, they are very strong people."
He said he would just as soon not have that fight.
We need all the cooperation we can. These producers are
the producers of our oil, too, and are the potential
bidders on ANWR, if it ever gets to the point where we
can issue leases. It is open now, but the bill has to be
passed to give the approval of congress to the
environmental finding under the EIS that there be no
permanent harm to that area. We ought to work together.
That's been my attitude…I've told them what I told you. I
think Alaskans would rather wait than have the pipeline
go across the top and it's very clear that our state's
position that you all have expressed is a firm one and we
don't intend to waiver in congress on that.
CHAIRMAN TORGERSON said he appreciated that and that this committee
has told the producers and Foothills that every time they get a
chance.
PUBLIC TESTIMONY
MS. DEB MOORE, Northern Alaska Environmental Center, said she
wanted to present their policy on natural gas development of
Alaska's North Slope:
The Northern Alaska Environmental Center believes that
the United States as a member of the world community must
aggressively reduce its dependency on fossil fuels
through energy conservation, transition to cleaner
burning fuels and increased development and use of
renewable sources of energy. To prompt this transition,
the Northern tends to believe the State of Alaska should
adopt an aggressive policy of energy conservation
standards for new building construction and vehicle
purchases and should launch a new program using state
funds to support rural alternative energy development
emphasizing renewable energies.
The Northern Center also recognizes that natural gas is a
cleaner burning fuel than are others used in the
Fairbanks areas and in many parts of the world. As such,
the Northern Center considers natural gas a transitional
fuel source in the move toward reduced and more
conservative use of fossil fuels in favor of renewable
energy sources. The Northern Center recognizes that
energy is a strategic resource required by all Alaskans
and is essential to their physical and economic well
being. With this consideration, the Northern tends to
believe that the development of North Slope natural gas
reserves to be a reasonable certainty. However, unplanned
and poorly conceived development as abetted by
comparatively low energy prices can cause significantly
long-term environmental, economic and health damage,
particularly for the pollutant prone Fairbanks bowl and
the fragile interior Alaska environment. Therefore, the
Northern Center wishes to remain as involved as possible
in the public debate and dialogue on natural gas and its
impacts on the Alaska and Fairbanks North Star Borough
environs and seeks to participate and provide assistance
throughout the process of permitting and construction.
If Alaska's proven North Slope gas reserves are
developed, the Northern Center believes the following
conditions should be met:
· Any project must minimize deleterious impacts on local
communities and traditional life styles and respect the
basic human right to a clean, safe and healthy
environment
· The pipeline should remain as close as possible to the
present utility corridors, excluding RS 2477 rights-of-
way
· No pipeline development should traverse wilderness
frontier areas including off shore of the Arctic National
Wildlife Refuge (ANWR)
· The State of Alaska should develop a comprehensive energy
production and management policy as a precondition to its
issuance of a permit for construction of a pipeline.
· The state and federal government should conduct studies
that assess all reasonably anticipated impacts accruing
from natural gas pipeline including the degree of
pressure on the Arctic Refuge that may be expected from
the addition of a pipeline from the North Slope
· The project must go through a new EIS process.
· There must be no regulatory shortcuts in the issuance of
permits.
· Any project must include best available technology and
best management practices including where environmentally
appropriate, seasonal construction techniques.
· There must be a permanent adequately funded and
independent formal citizens' advisory council for the oil
and gas pipelines that includes representation by
conservation organizations as well as local citizens that
reports directly to the governor
· The project must escrow sufficient funds for dismantling,
removal and restoration of all project facilities and
impacts in a way that regulatory agencies can insure that
the original eco-characteristics of the corridor have
been restored as facilities are taken out of service.
This return to the original condition standard and the
escrow's of DR&R funds must be stipulated in all permits
and reviewed in the EIS.
CHAIRMAN TORGERSON thanked her for testifying.
MR. KEN FREEMAN, Anchorage, said he would work with John Katz to
make sure that he and others in the administration are available on
September 19 and he would definitely get the word out to the gas
policy council, as well, to talk about the proposed federal
legislation.
CHAIRMAN TORGERSON said he might come up on September 17 and work
with whatever they have put together. He noted that Lisa Robinson,
Community and Economic Development Coordinator, had written a
letter for the record instead of testifying. He said that concluded
the meeting and adjourned at 6:02 p.m.
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