Legislature(2001 - 2002)
02/05/2002 10:12 AM House O&G
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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
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
February 5, 2002
10:12 a.m.
MEMBERS PRESENT
Representative Scott Ogan, Chair
Representative Hugh Fate, Vice Chair
Representative Fred Dyson
Representative Mike Chenault
Representative Vic Kohring
Representative Gretchen Guess
MEMBERS ABSENT
Representative Reggie Joule
COMMITTEE CALENDAR
CONTINUATION OF ROYALTY-IN-KIND GAS SALE HEARING
PREVIOUS ACTION
No previous action to record
WITNESS REGISTER
MICHAEL HURLEY, Senior Commercialization Specialist
ANS Gas Commercialization
Phillips Alaska, Inc.
700 G Street
Anchorage, Alaska
POSITION STATEMENT: Testified that the state's proposed
royalty-in-kind (RIK) gas sale, as currently envisioned, further
burdens an already economically challenged project.
KEN KONRAD, Senior Vice President
BP Exploration (Alaska) Inc.
P.O. Box 196612
900 East Benson Boulevard
Anchorage, Alaska 99519-6612
POSITION STATEMENT: Expressed concerns about the state's
proposed RIK gas sale as it is currently structured and about
the timing.
RICHARD GLENN, Vice President of Lands
Arctic Slope Regional Corporation
P.O. Box 129
Barrow, Alaska 99273
POSITION STATEMENT: Testified in support of the state's RIK gas
sale efforts and an overland route for a gas pipeline;
emphasized the need for access.
DON MAHON, Vice President
Alaska Power Operations
Alaska Power & Telephone Company
Mile 1314 Alaska Highway
Tok, Alaska 99780
POSITION STATEMENT: Testified in support of the RIK gas sale.
ERIC HANNAN, General Manager
Power Operations
Tok Area Division
Alaska Power & Telephone Company
Mile 1314 Alaska Highway
Tok, Alaska 99780
POSITION STATEMENT: Testified in support of the RIK gas sale,
specifying the benefits to the Tok region.
KENNETH A. BOYD, Lobbyist
for AEC Oil & Gas (USA) Inc.
23650 Sunny Glen Drive
Eagle River, Alaska 99577
POSITION STATEMENT: Provided background information on Alberta
Energy Company (AEC); expressed appreciation for the state's RIK
gas sale; emphasized the importance of having access with
certainty.
ALAN SHARP, Director
Northern Business Development
AEC Marketing (USA) Inc.
3900, 421 - 7th Avenue S.W.
Calgary, Alberta, Canada T2P 4K9
POSITION STATEMENT: Testified in support of the RIK sale and
process.
MARK HANLEY, Public Affairs Manager
Anadarko Petroleum Corporation
3201 C Street, Suite 603
Anchorage, Alaska 99503
POSITION STATEMENT: Highlighted the added value to the state's
royalty gas included in the AEC/Anadarko bid; explained the need
for the state to sell its royalty gas before an open season;
emphasized the need to determine FERC's authority.
MARK MYERS, Director
Division of Oil and Gas
Department of Natural Resources (DNR)
550 West 7th Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Discussed several aspects of the RIK sale;
pointed out that it is not just a "backstopping method" but is
one possible use; emphasized the need for access and for a long-
term, viable gas industry.
BONNIE ROBSON, Deputy Director
Division of Oil and Gas
Department of Natural Resources
550 West 7th Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Pointed out that it will be easier for
those who own the pipeline to expand it than for those who
don't; referred to royalty-relief statutes and encouraged having
the producers open their books to show whether they would be
harmed by an RIK sale, which isn't shown by the state's figures.
ACTION NARRATIVE
TAPE 02-6, SIDE A
Number 0001
CHAIR SCOTT OGAN called the House Special Committee on Oil and
Gas meeting to order at 10:12 a.m. Representatives Ogan, Fate,
Kohring, and Guess were present at the call to order.
Representatives Dyson and Chenault arrived as the meeting was in
progress.
CONTINUATION OF ROYALTY-IN-KIND GAS SALE HEARING
Number 0040
CHAIR OGAN announced the only order of business, the
continuation of the royalty-in-kind gas sale hearing. [Alluding
to the State of Alaska's Solicitation for Offers to Purchase
North Slope Royalty Gas] he noted that the bidding process ended
January 1 and bids were opened February 1. The four bids
received were from Chevron [ChevronTexaco Corp.]; a joint
venture between Anadarko Petroleum Corporation and Alberta
Energy Company Ltd.; Williams; and Alaska Power & Telephone
Company. He informed members that a couple of people from
Chevron and Williams were listening on teleconference.
Number 0211
MICHAEL HURLEY, Senior Commercialization Specialist, ANS [Alaska
North Slope] Gas Commercialization, Phillips Alaska, Inc., came
forward to testify as follows:
Simply stated, we believe the department's proposed
royalty-in-kind [RIK] sale of North Slope gas, as
currently envisioned, further burdens an already
economically challenged project.
Let me begin by saying that we understand the state's
goal to ensure third-party access to a gas pipeline.
We understand that goal and the state's desire to
increase the value of their unleased acreage. As the
state's most active explorer, Phillips has taken a
keen interest in ensuring expandability and access in
a new gas pipeline. We do not, however, believe that
the department's RIK backstop proposal is the most
appropriate way to address those goals.
Number 0297
MR. HURLEY referred to an handout labeled "Royalty in Kind
Backstop Sale Example." He said it is an example of what his
company understands to be the backstop proposal of the state,
with the following simplified assumptions: a system that could
carry 4 billion cubic feet (bcf) a day of Prudhoe Bay gas; the
state, at 12.5 percent, would receive 500 million cubic feet a
day; and the state would propose a royalty sale at 70 percent of
that amount, which is about 350 million cubic feet a day.
Number 0453
MR. HURLEY continued with his example. During the initial
stages of the RIK sale, the producers' equity gas would be about
3.5 bcf a day after the state's royalty share was removed. The
state wouldn't sell all of its gas, so the royalty-in-value
(RIV) portion would still "be going forward" at about 150
million cubic feet a day; others would be shipping the 350
million cubic feet a day of RIK gas. The producers therefore
would end up shipping about 3.65 bcf a day. In total, the
system would end up with Prudhoe Bay gas at 4 bcf a day and no
other gas being put into the line. Mr. Hurley told members:
In looking at this, we're not opposed to the RIK sale
itself. The state has the ability to take its gas and
its royalty in kind, and that's not a problem. What
gives us concern is the way the structure works with
them flipping back to RIV after they've sold RIK.
Number 0613
MR. HURLEY explained that after the sale terminates and it flips
to RIV, the non-Prudhoe Bay gas would be 350 million [cubic
feet] a day. The Prudhoe Bay gas would go from 4 billion [cubic
feet] a day down to 3.65 [billion cubic feet], but there still
would be a 4-bcf-a-day line. When the producers' gas was cut,
however, the state's royalty on the Prudhoe Bay gas would go
from the 500 [million cubic feet a day] it started with [at 12.5
percent royalty] down to around 456 million cubic feet a day.
MR. HURLEY noted that in this kind of scenario, the producers -
who are "underpinning this line" - are basically going from 3.5
bcf a day down to 3.2 bcf a day of equity gas they're trying to
sell. He commented:
If you think about that 300 million a day of gas times
365 times 20 years, and a buck an "M" at the wellhead,
... that's a couple of billion dollars' impact. And
that is, in our view, a burden to this project. ...
Now, the other option people are telling you to
consider - and others would suggest - is that we
overbuild the pipeline upfront, so that we could
always keep the 3.5. But let me suggest to you that
that in itself is a burden. ... I can spend $20
billion and have 3.5 billion [cubic feet a day] of
equity gas, or I can spend $21 or $22 or whatever the
number is to build a bigger line and still have 3.5
billion of equity gas. But in either case, it's a
burden to the project - I've had to spend billions of
dollars more.
Number 0846
REPRESENTATIVE DYSON requested confirmation that to increase
capacity for gas pipelines, the strategy is to raise the
pressure.
MR. HURLEY clarified that the end result would be an increase in
compressor stations. The total allowable pressure wouldn't
actually increase.
REPRESENTATIVE DYSON suggested that the need isn't to build a
bigger pipeline, then, but to build it with the ability to
increase the throughput incrementally, as needed. He asked
whether there is a mechanism by which the producers and the
state can "force the folks who are adding incremental increases
to the throughput" to share in the proportionate costs of
increasing the throughput.
MR. HURLEY said it is reasonable. He indicated the problem is
not building it bigger, but that nobody's stepped up to pay for
that.
REPRESENTATIVE DYSON requested confirmation that it wouldn't be
bigger, but thicker.
MR. HURLEY answered in the affirmative, indicating it would
involve putting more compressor stations along the line,
including [changes in] siting and design - whatever it takes to
get more throughput. He added that the system would be built to
be expandable.
Number 1005
REPRESENTATIVE DYSON asked whether the producers, because they
would finance the first increments and would have to build the
original design to accommodate future expansion, would want
"guys with a big checkbook to help in that."
MR. HURLEY replied, "I think that's reasonable if they want
expanded capacity."
REPRESENTATIVE DYSON mentioned the state's responsibility to get
its own royalty share to market and maybe a larger
responsibility to make sure other gas fields in the area get
developed and commercialized. He asked whether Mr. Hurley was
saying the state needs to determine how to ensure that everybody
pays a fair share, or to help the producers determine it or put
the tools in place.
MR. HURLEY said that is correct.
Number 1102
REPRESENTATIVE DYSON inquired about the open season. He alluded
to previous testimony, mentioning that after the open season a
company is in a less advantageous bargaining position to get a
reserved place in the pipe for its gas.
MR. HURLEY answered that one can propose an expansion at any
point. With expansion comes additional open-season
opportunities because it is governed by the same open-access
requirements for the original open season as far as
nondiscriminatory access.
REPRESENTATIVE DYSON replied that he has heard a different
perspective, however. He then mentioned two alternatives:
ensuring that this transportation route for gas is like a common
carrier or doing it in a way that isn't detrimental to those who
took the risk to build and finance it in the first place; he
suggested "either end of the problem" could be worked.
Number 1294
MR. HURLEY returned to his presentation, emphasizing that the
RIK backstop proposal "will decrease revenues to us" and
increase the level of uncertainty for the project. He added,
"We have a hard time envisioning how to move forward on the
project with this kind of situation unchallenged, where we can
end up getting arbitrarily cut back or being forced to pay for
additional capacity upfront." He closed with the following
remarks:
We share the state's desire for equitable pipeline
access. We're committed to fair and open access to
any gas pipeline in which we participate, consistent
with the regulatory requirements and direction of the
Federal Energy Regulatory Commission [FERC]. They
have a regulatory structure in place which requires
open, nondiscriminatory access for both initial and
expansion volumes. And we believe their regulatory
oversight will ensure, as it does throughout the U.S.,
that all potential shippers are treated fairly and
that economic burdens are distributed equitably.
We encourage you to look carefully ..., as you
consider this proposal, at the impacts it has on the
economics of the other potential shippers whose long-
term shipping commitments will underpin the financing
of this project.
Number 1407
CHAIR OGAN pointed out that some don't share the viewpoint that
FERC will regulate this as fairly as Mr. Hurley said, because of
the belief that FERC's power is a little more limited regarding
the regulation of open seasons than how the producers
characterize it; Chair Ogan said he would like to have that
verified [by an expert on FERC].
CHAIR OGAN referred to testimony that this would be not a
common-carrier pipeline but a contract pipeline. He suggested
it would be in the state's best interest to encourage smaller,
independent companies to come to Alaska to do business. He
asked Mr. Hurley what he thinks.
MR. HURLEY answered that FERC regulates the gas pipeline
business throughout the U.S. There is a longstanding regulatory
structure in place; it regulates access both for initial open
seasons and expansions. He noted that the initial open season
happens before [a company] even files an application for a
certificate; it is subject to FERC review and to challenge by
any people who feel they have been treated unfairly.
CHAIR OGAN requested confirmation that someone who finds gas
later couldn't make the producers or anyone else add gas into a
contract pipeline.
MR. HURLEY affirmed that there is no provision for FERC to force
an expansion. He suggested, however, that it isn't desirable to
have a regulatory body, which is subject to political pressure,
forcing people to do things in the economy.
Number 1560
CHAIR OGAN proposed that how much gas can be produced is based
upon how economic it is to draw down from the existing fields,
including the effect on oil production. Referring to the
Fairbanks meeting in 2001 of the Joint Committee on Natural Gas
Pipelines, he said the Alaska Oil and Gas Conservation
Commission (AOGCC) testified it was looking at that and revising
the models because previous assumptions were based on 2.5 bcf [a
day]; it was uncertain what an approximately 4.5 [bcf a day]
drawdown would do to [oil] production.
CHAIR OGAN asked how much that factors into [the producers']
decision regarding how much gas to produce from the existing
fields. He added that it isn't an issue at Point Thomson, for
example; gas in the foothills and gas that independents are
producing, however, might ultimately affect the amount of oil
produced. He asked how much that drives [Phillips'] decision
regarding how much gas will go through the line.
MR. HURLEY responded that it is a hard question to answer, but
many things come into play regarding the initial design rate.
Those include oil losses, market estimates, and technology. For
example, it would be a technological challenge to build a system
big enough for all the gas that Prudhoe Bay could produce
instantaneously, "8 bcf a day or whatever it is we're currently
recycling."
Number 1705
CHAIR OGAN asked Mr. Hurley whether he has studies regarding the
relationship between drawdown of gas and [oil] production. He
indicated he'd like to see such a study from the AOGCC. He
offered his understanding that the producer group hasn't agreed
to fund a study with the AOGCC and mentioned possible funds
there to do that.
MR. HURLEY replied that he was "at a loss" about the funding of
the AOGCC to do that. He added:
I know they have been looking at some models, as we
have internally. All the companies have got reservoir
models of Prudhoe and are looking at what the
potential is for oil losses based on mitigation
measures, based on when gas sales start and the volume
that gas sales begin at. All of those things have an
impact on oil losses, and it's a relatively complex
model to try and do that.
Number 1783
CHAIR OGAN expressed his understanding that there was a meeting
set up between the producers and AOGCC. He asked, "How much of
that information are you willing to share with them?" He
suggested that [Phillips'] showing the AOGCC its model might
help the AOGCC with an independent analysis. He pointed out
that legislators aren't petroleum engineers and must rely on
others for information. He offered his belief that it is a
"driving factor" in this whole issue.
MR. HURLEY agreed it is an important factor, but said he isn't
aware of the status of those discussions with the AOGCC and
couldn't comment on how they were going. He added, "Our
reservoir folks have been talking to the AOGCC off and on."
CHAIR OGAN requested that Mr. Hurley pass on to Phillips'
managers that Chair Ogan would appreciate as much cooperation as
possible.
MR. HURLEY agreed to that.
CHAIR OGAN asked whether there were further questions, then
thanked Mr. Hurley for his testimony.
Number 1870
KEN KONRAD, Senior Vice President, BP Exploration (Alaska) Inc.,
testified via teleconference, noting that he is the vice
president in charge of BP's gas interests in Alaska. He told
members BP supports the following: the state's right to take
gas in kind; "exploring for new sources of gas that could be
produced into a gas pipeline"; and expansion of gas pipeline
capacity on open, fair, and reasonable terms. He stated:
BP, ... Phillips, and Exxon are in the process of
completing ... a major feasibility and engineering
study on a possible gas pipeline. An essential
premise in that study is designing a pipeline system
that can be easily expanded, and we have been
successful in achieving a design that has higher
expansion capability at lower cost than any other
proposal that we've seen. We firmly believe that
efficient pipeline expansion can benefit both existing
producers and explorers as well as ... the State of
Alaska.
We understand the state's desire to see additional
development of additional gas beyond the existing
known resource. Indeed, the feasibility study we have
undertaken this year assumes that additional gas will
be found beyond the 35 trillion cubic feet [tcf] of
currently known gas. We currently assume at least 50
trillion cubic feet of total gas will be needed during
the project life.
Separately, BP is working on a major study with the
Department of Energy and the University of Alaska
Fairbanks to study a possible way to produce the
enormous gas hydrate resource known to exist in and
around existing North Slope fields. This resource
alone has been estimated at nearly 50 trillion cubic
feet. This is really a long-term possibility with
many technical challenges, but it's indicative of our
active support for new sources of gas supply.
We certainly support the state's right to take gas in
kind. This is clearly a choice ... the state should
make on its own. Our sole request is that the state
do so in a predictable manner that is consistent with
how a "contract-carry" gas pipeline would operate.
So we fully support the state's ability to take in
kind, we fully support pipeline expansion on fair and
reasonable terms, and we fully support finding new
sources of gas supply. And it's in our best interests
... for all those things to occur.
Number 2030
MR. KONRAD continued:
We do, however, have concerns over the proposed state
sale of "take-in-kind" gas as currently structured,
and also with respect to timing. We've openly
discussed our concerns with DNR [Department of Natural
Resources] over the past several months.
The state has frequently indicated that this proposed
RIK sale is being driven by the perception that the
Alaska Gas Producers Pipeline Team may hold an open
season for pipeline capacity in early 2002. We do not
foresee any possibility of holding an open season
anytime during 2002.
As we've talked about previously, for a gas pipeline
to attract investment there first needs to be an
economic project. And further, to reduce project
risk, there also needs to be a predictable and viable
government framework in place to support that
investment. Both federal regulatory legislation and
clarity around fiscal terms are important pieces of
this government framework, and to date, neither of
those vital ingredients is currently in place.
According to the DNR, the state's proposed RIK sale is
being pursued primarily to provide a capacity-access
option to explorers without currently proven gas
resources, the idea being that the explorers could use
the state's RIK gas to backstop their own bids for
[firm] transport capacity on the new-build line, and
then release that RIK gas back to the state, should
they find their own reserves.
The ability of RIK purchasers to return gas to the
state on a relatively short notice period places a
significant additional burden on our overall project
economics by increasing the uncertainty on the amount
of equity gas the major producers would be able to
ship. That translated means uncertain cash flow.
This burden on an already marginal project is a clear
step in the wrong direction.
Number 2147
MR. KONRAD offered an example similar to Mr. Hurley's: a
pipeline designed to transport 4 bcf a day, with the state
taking one-eighth in kind - 500 million cubic feet a day. An
RIK purchaser could use its purchased gas as a backstop for
making a long-term firm transportation (FT) commitment on a gas
line; the balance of the commitments to get the line built would
need to be made by the known resource owners. If an RIK
purchaser discovered its own resources, however, it could cancel
its purchase contract with the state and substitute its own gas
into its firm transportation commitment. The state's gas would
then revert back to the known resource owners in the form of
RIV, thus reducing throughput by 500 million cubic feet a day,
"reducing our own gas production that the resource owners had
already made financial commitments for."
MR. KONRAD advised the committee that this reduction in cash
flow against the binding financial commitment is clearly
negative from an investment point of view. The state's RIK
proposal seeks to transfer benefits from long-term investors to
new participants without transferring the risk, he said. Those
subsidies are at the expense of those who ultimately will
underwrite any new-build pipeline. That is unfair. More
important, from the state's perspective, it will reduce the
chances of developing an economically viable project. He
pointed out that obviously there is no access to a pipeline that
never gets built.
Number 2237
MR. KONRAD summarized his earlier points:
BP firmly supports the state's right to take gas kind.
We support pipeline expansion on fair and reasonable
terms. And we support vibrant exploration for gas.
We believe FERC will ensure fair and open access to
any gas pipeline. And in any event, it's in our best
interests.
However, we cannot at this time support the ...
state's proposed RIK sale as it's currently
structured. We're deeply concerned, if the state
tries to fix this perceived problem with economically
burdened solutions, that that cannot possibly be in
the best interests of the state.
Number 2270
CHAIR OGAN referred to earlier discussion regarding [gas]
drawdown and its effect on pipeline throughput and the oil
companies. He then referred to an e-mail from Cammy [Oechsli
Taylor] of the AOGCC; he noted that it offered the understanding
that the funding for the reservoir study was coming from the gas
line appropriation to DNR, but that the companies have not yet
covered those costs. He asked whether that is accurate, to Mr.
Konrad's knowledge, and whether "you guys are willing to step up
to the plate with that." He requested clarification about the
funding.
MR. KONRAD said he wasn't aware of a funding issue. He expanded
on his answer:
The Prudhoe owners have met on a few occasions with
the AOGCC, and I know their work is continuing kind of
on a parallel path with our work. ... We're set to be
finished up with our study the end of February, and
I'm not sure exactly what the exact status of the
subsurface work is, but I do know that there was an
intent ... to share results of ... that work with the
AOGCC and have a discussion. But I don't really know
exactly where it sits. We certainly factor that into
the equation as we look at it.
I would just point out that certainly the producers
are quite aligned with the state in the regard of oil
losses. It is, clearly, a potential burden to the
project if you produce less oil, and that's why we're
looking at mitigation measures and investments to help
reduce that. But nevertheless it is there and
present. But, clearly, we're aligned with the notion
of maximizing the total value of the resource, so
that's inherent in our analysis. But I haven't seen
any final work out of the Prudhoe group, but I would
imagine ... they'll be finishing their phase of work
here in the not-too-distant future.
Number 2410
CHAIR OGAN agreed it is one area where the producers and the
state are aligned; all will lose revenues if there isn't as much
oil. He asked that Mr. Konrad pass along to BP's manager the
same request asked of Phillips, that Chair Ogan would appreciate
as much cooperation as possible. He acknowledged that much
information is proprietary, but emphasized that the more
information the AOGCC can have, the more independent an
evaluation the legislature can have, and the easier it will be
to make a decision.
MR. KONRAD responded that he hadn't heard from [Ms. Oechsli
Taylor] in a while, but said he would contact her to check on
that. He would also check with "our Prudhoe folks."
CHAIR OGAN asked whether there were any questions; none were
offered. He requested that Mr. Konrad fax his written
testimony, if available.
Number 2492
RICHARD GLENN, Vice President of Lands, Arctic Slope Regional
Corporation (ASRC), testified via teleconference. Noting that
he had e-mailed several pages of written testimony, he offered
to summarize. He informed members that ASRC, which represents
more than 8,000 Inupiat Eskimos in northern Alaska, owns surface
and subsurface title to more than 4 million acres of North Slope
lands; by virtue of that ownership, he said, "we represent the
largest private landowner on the North Slope." He noted that
ASRC has millions of acres of "high-value resource potential"
lands in the central Arctic foothills. Therefore, he said, "We
believe that our interests are closely allied with the state
with respect to natural gas from the central Arctic."
MR. GLENN spoke in support of the state's royalty-in-kind gas
sale efforts. He explained that without such a program, ASRC
believes there is a potential for a "foreclosure of the resource
potential" of the central Arctic lands. He said ASRC recognizes
that the gas resources at Prudhoe Bay, Point Thomson, and the
surrounding fields are what began this discussion. He told
members:
For us, it's kind of a mixed blessing. It's a huge
resource potential. It needs to be recognized, and we
do recognize that. ... We are partners with the oil
industry. We have a future with them, and we don't
want to spoil that. We recognize that, and we want to
continue [a] productive working relationship. Yet we
recognize that we have to speak up for our interests.
And we do not wish to shut off the exploration and
development of additional North Slope natural gas
reserves.
In addition to achieving the larger goal of getting to
the nation and helping the state with its revenue
derived from resource wealth, we ... speak to protect
the economic interests of our people, and that
economic interest centers around access.
Number 2654
MR. GLENN continued:
We want access to capacity. In addition to that, we
require access to opportunity and to the planning
process of a North Slope natural gas line.
We strongly encourage the Alaska legislature to make
every reasonable effort to ensure access to future gas
owners on a North Slope natural gas pipeline. We know
that one way to do this is through the royalty-in-kind
gas sale. This can act as a backstop for future
access into the gas pipeline. ASRC feels that the
royalty-in-kind sale is a necessary placeholder to
maintain pipeline capacity for nongas owners.
This access to natural gas pipeline capacity is
critical. If we cannot be assured of reasonable
access to space on a pipeline, then our industry
partners in the central Arctic will not explore for or
develop natural gas outside of the Prudhoe Bay, Point
Thomson, and related fields. And in doing so, this
would, in effect, condemn more than 11 million acres
of highly prospective Native- and state-owned lands to
future exploration potential for many years to come.
But in addition ... to pipeline capacity, we think
that there are other things that the state should be
cautious about. We know, for example, that the
Prudhoe Bay gas is enriched, for example, in carbon
dioxide, CO2. And we fear that if secondary services
of gas processing are bundled together, ... any other
gas found outside the Prudhoe Bay area that, for
example, is not enriched in CO2 might be burdened with
this gas-treatment cost.
Number 2734
MR. GLENN urged the legislature to consider researching whether
unbundling secondary services such as gas conditioning would
allow a fair tariff structure to be set. He explained that all
gas that leaves the North Slope will require processing in some
fashion; every field has a different chemistry and a different
pressure, so the processing for each field is different. He
explained:
We just do not want fields that do not need additional
processing to be burdened with that cost. As you
know, with centralized facilities and a single
pipeline leaving the North Slope there's going to be
sharing of these facilities, and we urge the
legislature to assure that there's a fair sharing of
these facilities. ... The current producers need to be
recognized and compensated for their investment. On
the other hand, we don't ... want to see excessive
charging ... resulting in an unfair tariff structure.
Number 2792
MR. GLENN outlined ASRC's concerns regarding the current
producers. First, the current producers may attempt to include
excessive capacity "holdbacks" - setting aside more pipeline
capacity than necessary for their own internal purposes.
Second, they have the opportunity to make transportation
capacity on the pipeline either completely unavailable or
unreasonably expensive to shippers who aren't able to secure
firm capacity under the initial open-season process. Finally,
they can force new shippers to sell their "stranded gas at
distressed prices to those who are controlling the
transportation." A further possibility is that the producers
may forestall or delay expansions that would provide additional
capacity. He told listeners:
These are things we are worried about. It's not just
a matter of how much gas can fit in the pipe, but it's
how all of this capacity and gas processing is going
to be monitored and regulated. We don't want to see
it regulated out of business. We don't want to see an
overburdened pipeline project. On the other hand, we
need the access.
Number 2884
MR. GLENN noted that his written testimony, which discusses
access to opportunity regarding pipeline construction, was
provided to the governor's [Alaska] Highway Natural Gas Policy
Council. Pointing out that it also discusses access to the
process, he emphasized that ASRC, as "a neighbor and a resource
owner," wishes to be at the table when decisions are made
regarding the gas pipeline, including ownership, construction,
and operation.
MR. GLENN spoke in support of having an overland route for the
gas pipeline, saying it would benefit all Alaskans. He
encouraged the committee to review "all the issues, and not just
the interests of a few gas owners," to better understand the
impacts of North Slope Alaskan natural gas development. He
concluded by saying, "We believe that the State of Alaska and
the North Slope Inupiat people have much in common with respect
to natural gas, and we can work together to protect the
interests of all Alaskans."
Number 2903
CHAIR OGAN expressed appreciation for Mr. Glenn's testimony. He
added, "I don't think it's a secret around here that we share
your concerns about a northern route and are working to try to
get that line to go south, for a number of reasons." He asked
if there were questions; none were offered. Assuring Mr. Glenn
that the committee was giving it full attention, he noted that
the legislature must decide whether to approve the RIK gas sale.
TAPE 02-6, SIDE B
Number 2924
DON MAHON, Vice President, Alaska Power Operations, Alaska Power
Company & Telephone Company, testified via teleconference as
follows:
Alaska Power [& Telephone] Company has been providing
regulated electric services to several rural villages
along the route of the proposed natural gas line.
Alaska Power [& Telephone] Company has been issued a
Certificate of Public Convenience and Necessity by the
Regulatory Commission of Alaska [RCA]. ...
Under the terms of our certificate we are obligated to
provide safe, affordable electric energy, free from
unreasonable interruption. Pursuant to this, we have
investigated the potential savings to our rural
customers by converting our existing diesel power
plants to use natural gas as fuel.
Natural gas provides many advantages over alternative
fuel sources. It is easy to use, clean-burning, and
cost-effective. Natural gas is increasingly a fuel of
choice in areas where it is available. According to
the 2000 Supplemental Census, natural gas is the
number-one choice for home heating, with 70 percent of
new homes completed in 2000 equipped with natural gas.
According to the Department of Energy's Representative
Energy Costs for 2001, natural gas is a highly cost-
effective energy source as compared to alternatives.
All review thus far shows that fuel-cost savings are
sufficient to cover the investment and create a
significant economic benefit to the residents of the
area. Another economic benefit would be realized by
the State of Alaska in that the power cost
equalization received by the community would be
reduced.
Further, we determined that purchasing of royalty gas
directly from the State of Alaska enhances the
economic benefit and increases the likelihood that the
project [would be able to secure] a tap on the
mainline and offers some standing when having
discussion with the pipeline company and regulatory
agencies.
MR. MAHON noted that after Mr. Hannan discussed the benefits to
Tok and the surrounding area, he himself would provide a
conclusion.
Number 2804
ERIC HANNAN, General Manager, Power Operations, Tok Area
Division, Alaska Power & Telephone Company, testified via
teleconference as follows:
Our intention is to demonstrate a real demand for
local use in Alaska as well as the business
[proposition] for fulfilling that demand. We chose to
look specifically at [the] economics of placing such a
service here in Tok. We currently serve our
communities with both power and telecommunications.
The first business enterprise we examined was a
natural gas local-distribution company, which will tap
into the trans-Alaska natural gas pipeline and
distribute the gas to our [residential], commercial,
and industrial customers.
We have also studied using natural gas in the
production of electricity. Currently, we burn diesel
fuel to generate electricity in Tok. The presence of
natural gas in the area would provide an opportunity
for [Alaska Power & Telephone Company] to switch over
to the more efficient, environmentally responsible
natural-gas-driven generators. This will also pave
the road for new forms of electrical generation, i.e.,
microturbines, fuel cells, and whatever new technology
has in store for us in the future. [Mr. Hannan's
testimony cut out briefly, but his written testimony
said the result would be that cost savings would be
passed back to the consumers and the state in the form
of lower electric rates].
The cost of gas is a critical variable to the success
of both proposals. If we assume a wellhead price of
gas of $1.00 per Mcf plus transportation costs of $.80
to $.90, the FOB cost would be $1.90 Mcf less the cost
of tap and removal of liquids. If we assume all-in
costs of $2.56 Mcf, the cost per mmBtu is $2.56. The
cost of diesel fuel [at $1.00 a] gallon is ... $7.25
per mmBtu - significant savings to our customers of
approximately $294 per annum per customer. The key
element, of which we must remain cognitive, is the
cost and affordability of the gas.
Number 2712
MR. MAHON concluded his company's testimony as follows:
It is crucial that FERC does not limit the RCA's
ability to set tariffs and conditions that will allow
in-state gas purchases to be affordable for Alaskans.
Development of an affordable natural gas
infrastructure is vital for future economic
development. An excellent example of future
development along the path of the pipeline is the
mining industry. We must make every effort to keep
the costs of all future development feasible. Alaska
Power & Telephone is in full support of the royalty-
in-kind gas sale.
Number 2680
CHAIR OGAN referred to discussion during the interim, in the
Joint Committee on Natural Gas Pipelines, about the issue of
RCA's having a place at the table. He remarked:
We've looked at a number of ways to try to keep FERC
out of it for the intrastate gas use and, quite
honestly, haven't been able to come up with a way to
do it. And I was looking at maybe trying to
statutorily move the wellhead down to a hub concept or
something to keep in-state regulation to a point where
people can hook up and FERC regulates it from there
out. And all the feedback we've gotten from the
"legal beagles" is that ... if one molecule of gas
goes to the Lower 48, FERC regulates the whole thing.
I think maybe the best approach that we can hope for
is that ... RCA and FERC [allow] kind of a joint
committee. ... That might be something we want to
request in the enabling legislation with the feds, is
some kind of a joint RCA-FERC committee or
subcommittee that regulates this particular gas line
so Alaska has a place at the table. So, being one
that doesn't like the feds regulating things, I think
it might be a good way to represent our interests. ...
We're aware of it and we're working the issue, and
hopefully we can resolve it.
Number 2601
CHAIR OGAN requested that Mr. Mahon and Mr. Hannan forward their
written testimony to the committee aide.
Number 2582
REPRESENTATIVE DYSON asked whether it is reasonably easy to
convert existing diesel-fired generators to operate on natural
gas, and whether Alaska Power & Telephone Company would be able
to do so with its machines.
MR. MAHON answered, "That is true, and we'd be able to do that
with our machines. Also, we'd have to take into consideration
the conversion cost versus purchasing new machines."
CHAIR OGAN wished the testifiers good luck with the bid. He
then called upon testifiers from Alberta Energy Company (AEC).
Number 2502
KENNETH A. BOYD, Lobbyist for AEC Oil & Gas (USA) Inc., came
forward to provide background information. He informed
listeners that AEC first came to the state a few years ago when
he himself was director of the Division of Oil and Gas. After
hearing what AEC proposed to do - to buy leases in the foothills
to develop gas, when there was no gas pipeline, and to work on a
offshore [oil] prospect called McCovey with Phillips and Chevron
- he'd commented in a newspaper that AEC had "jumped into the
deep end of the pool." Mr. Boyd remarked, "Indeed, they
continue to be in relatively deep water. You're the lifeguard.
I'm trying to help."
MR. BOYD noted that the previous year Phillips decided not to go
forward as operator of the McCovey oil prospect; located about
11 miles north of Prudhoe Bay in the Beaufort Sea, it has all
the problems of offshore development, but also the potential
benefits to the future of the State of Alaska. He reported that
AEC is bringing a new technology to the table, has worked well
with state and federal agencies, and is "working very carefully
and hard" with Native organizations to give them some assurance
that there will be a safe operation.
Number 2433
MR. BOYD turned attention to gas. He expressed appreciation for
the state's providing the RIK program, citing the importance of
having access to the pipeline with certainty. Noting the high
risk, he told members [AEC] and its partner Anadarko are working
in the foothills, where they've bought leases and shot seismic
[data] for two years, making "substantial investments in a new
place for them." Mr. Boyd pointed out how different the rules
are from Canada's and how many agencies one must go through
here. Referring to AEC, he said, "I think you're looking at the
future of Alaska; I think these are going to be very important
players in our future." He then introduced Alan Sharp, who
would talk about the RIK program.
Number 2370
ALAN SHARP, Director, Northern Business Development, AEC
Marketing (USA) Inc., informed members that he was testifying in
support of the royalty-in-kind sale and process. He offered
four key points from a handout titled "Royalty In Kind (RIK)
Sale." First, RIK is in the state best's interest. Second, it
must be done now while there is a window of opportunity. Third,
it won't impact the producers or the Alaska Gas Producers
Pipeline Team. And fourth and more important, he said:
We're coming at it from an explorer's perspective.
What we're trying to offer here is not just a royalty-
in-kind bid. What we're trying to offer is the state
to share in our vision of what we see for the natural
gas industry in Alaska. We want to see a competitive,
multiplayer natural gas industry in Alaska, and we
[believe] that the royalty-in-kind sale is the first
step towards making that happen.
Number 2313
MR. SHARP brought attention to page 2 of the handout, a map
labeled "AEC Alaska Project" that shows the North Slope and
current natural-gas proven reserves, with 25 trillion cubic feet
at Prudhoe Bay and 5 trillion cubic feet at Point Thomson. The
breakdown shows that the majority of proven reserves are held by
three companies: BP, Exxon, and Phillips [BP Exploration
(Alaska) Inc., ExxonMobil Production Company, and Phillips
Alaska, Inc.]. He pointed out that those same three companies
comprise the Alaska Gas Producers Pipeline Team.
MR. SHARP advised the committee that AEC and Anadarko are
exploring in the foothills region just for natural gas. The gas
found thus far in Alaska predominantly has been found by
exploring for oil. The potential in the foothills where AEC and
Anadarko are exploring is 26 trillion cubic feet, whereas the
ultimate potential for the North Slope is 100 trillion cubic
feet. He told listeners, "We want to make sure that the
pipeline is designed properly right from the start so it takes
into account the full potential that's here in Alaska."
Number 2257
MR. SHARP addressed some of the reasons RIK is in the state's
best interest [page 3 of the handout]. Noting that there is no
risk to the state as the bid is being proposed, he explained:
The state is actually leveraging its gas volumes of
tomorrow to support exploration projects of today.
Those exploration projects represent in-state
expenditures for exploration, more jobs, more revenue
coming into the state, and essentially creates a
competitive gas industry.
The way that the royalty-in-kind sale maximizes the
state's values through this competitive bid, you've
got four bids in front of you, and everyone's put
forward their best competitive bid.
And I think the other thing that's important to note
in our bid is that we've guaranteed that the royalty-
in-kind price will be greater than the royalty in
value. So there is no risk from a monetary
perspective. In fact, the state's better off to
accept a royalty-in-kind bid versus just the status
quo, leaving it royalty in value.
Number 2202
MR. SHARP discussed why RIK is needed now [page 4]. The timing
is critical with regard to the window of opportunity. The RIK
sale takes five months to carry out, plus there must be
legislative approval that [normally] only occurs between January
and May. If an open season falls outside that window, the
opportunity is lost. Mr. Sharp noted that the "producer team"
has just said "they do not foresee an open season being held in
2002." He pointed out that if an open season were held early in
2003 with no notice, the opportunity still would be lost.
MR. SHARP advised members that AEC recommends the following: an
open season June 2003 or later; at least six months' advance
notice; and, more important, complete disclosure of the [tariff]
terms and conditions, especially regarding access and expansion.
He suggested that if the pipeline is designed correctly from the
start, it can be designed "with smaller increments that support
exploration and more players and more competition and
essentially more jobs and dollars" coming into Alaska. He
proposed increments of perhaps 200 million to 300 million cubic
feet a day, from a 4-bcf-a-day pipeline to, say, a 5-bcf-a-day
pipeline.
Number 2127
REPRESENTATIVE DYSON noted that if it is required that the
initial pipeline construction facilitate incremental expansion,
he'd heard the producer group say there is a cost to it. He
asked who should bear that cost.
MR. SHARP offered his personal view, from his understanding of
how pipelines are being built, that if it's designed in right
from the start, there would be little or no incremental cost in
order to have that expansion in increments of 200 million to 300
million [cubic feet] a day. As mentioned earlier, it's just a
matter of "putting in a compressor and the proper spacing." He
proposed that if that has been anticipated in the design, it
should be quite easy to do, at little cost. He added, "I think
if there was incremental cost, ... that's where we'd sit down
and talk about it." Mr. Sharp said the "explorers" would like
access and the ability to communicate their concerns and issues
regarding how the pipeline is being designed.
Number 2060
REPRESENTATIVE DYSON asked whether there is a role for
legislators to play to help make sure that conversation happens
so that potential users get access but the producers don't get
saddled with costs and time delays that would "impact the
survivability and economics" of the project.
MR. SHARP answered that first, there should be a joint meeting
among the producers, the explorers, and the state. Up to this
point, that hasn't happened. He said he views the RIK sale as a
process of helping to facilitate those discussions and
negotiations. Noting that [page 7] of the handout relates to
FERC, he countered the view of the producer team that FERC can
support or mandate that process.
Number 1962
MR. SHARP, in response to a comment from Representative Dyson
regarding the open season, indicated AEC has a different
interpretation from that offered by the producer team. He
added:
We're making investments in the state right now.
We're exploring for gas. We want to make sure that we
can "monetize" that gas economically. And it's
basically the same thing that the producers are saying
too. They'd like to lower their risks and their
costs; they need certainty. And I think that's what
we're looking at from a royalty-in-kind-sale process.
It provides us that certainty. And we do not believe
it's a detriment to the producer group.
Number 1931
REPRESENTATIVE DYSON responded that he'd understood [the
producer group] to say it's not a problem and that someone can
always get in and ship the product if willing to participate in
an incremental cost increase. Therefore, the desire to get a
reserved place during the open season is largely an academic
problem.
Number 1907
CHAIR OGAN recalled that there was a lot of discussion about
that in the Joint Committee on Natural Gas Pipelines. He
offered his understanding that once the open season is closed
"it's pretty much closed." He added, "I don't think FERC can
make them do it." It's a big issue, he said, and whether there
is further exploration by independent companies in Alaska is
what this hearing, and this whole issue, is about. He said DNR
is trying to facilitate the independents and some competition.
CHAIR OGAN emphasized the need to hear from a "FERC attorney."
Although some independents have such legal counsel on staff,
Chair Ogan said he didn't know whether that was true of AEC.
That is the debate here, he pointed out. There is a difference
of opinion.
REPRESENTATIVE DYSON agreed that the committee needs to know
whether FERC has jurisdiction and what it can do. In addition,
members need to know about the ability to buy capacity after the
open season, and at what cost. Because of the different
opinions, he suggested the need for a process that leads to a
conclusion that members can have confidence in.
Number 1808
CHAIR OGAN announced that he planned to appoint a subcommittee
to study this issue and perhaps facilitate discussion between
the producers and independents, if all are willing to come to
the table.
Number 1785
MR. SHARP addressed Representative Dyson's question as follows:
I think the explorers' concerns are, first, in the
open season. The open season's going to be structured
by the parties that initiate it. It's not FERC-
regulated. ... Our concern is that we can't make a
commitment during that initial open season without
proven reserves. We need some other type of backstop
or what I would refer to as an insurance policy, which
the royalty-in-kind offers.
And then the problem with waiting for an expansion is
- if you haven't designed the explorers' interests, of
that incremental capacity, in right from the start -
the expansion could be structured so that it's very
onerous to those that want to actually expand the
pipe. So it may not be economic for that party
seeking the next expansion.
Or it could be designed in such a manner that instead
of going from just 4 [bcf a day] in increments of 2[00
million] to 300 million a day up to 5 bcf a day, you
have to actually do the expansion in one large,
incremental step of 1 bcf a day. That would exclude a
lot of new entrants from a pipeline. ...
What we'd like to see is a competitive, multiplayer
industry. I think it's in the benefit of everybody to
have more players generating more jobs and more
revenue for the state. And I think the way to do that
is to ensure that the expansion is done in an
appropriate manner that supports the new entrants to
the pipeline.
Number 1713
CHAIR OGAN noted that during the open season, AEC wouldn't have
gas but would be looking for it, in a joint venture with
Anadarko. If the season closed and if FERC could not, by
regulation, allow entrants after they find gas, "then basically
you're done looking up there."
MR. SHARP suggested other new explorers would be done looking
too. There would be 20 years when the pipeline would be full,
during which time the existing shippers on the pipeline would
start exploring to keep that pipeline full. With a potential of
100 trillion cubic feet on the North Slope, he said, "I guess
what we're hoping is that you would allow explorers like
ourselves - and other explorers - to be able to take advantage
of that potential as well, not just the three parties that are
there right now."
Number 1641
MR. SHARP referred to page 5, "Explorers' Pipeline Decision
Timeline." He indicated [between 2005 and 2006] is the earliest
date for the explorers on the foothills project and the North
Slope for gas, and that AEC and Anadarko are the furthest along
in this regard. Even if the open season were delayed until 2003
or 2004, Mr. Sharp said, they would be in the same situation.
"So we need something else such as a royalty-in-kind process to
participate in that initial open season," he concluded.
Number 1608
MR. SHARP turned attention to page 6, labeled "State's Royalty
in-Kind Decision Timeline." He noted that it highlights, from
the state's perspective on the RIK sale, the reason for having
it now. He pointed out the window of opportunity shown on the
chart for the state's process of a RIK sale, as well as an
example of a timeline for an open season for the Alaska Gas
Producers Pipeline Team. He emphasized that if there is no
commitment from the producer pipeline team, the open season
could occur anytime, perhaps outside the window of the RIK sale.
Number 1563
MR. SHARP returned attention to page 7, regarding how FERC can
help; he noted that this is where there is disagreement with the
producer group. He referred to the first four "bullet points,"
which read [with punctuation changes]:
Can not force a pipeline expansion
Open seasons are encouraged but not required
Open seasons are not regulated (complaints basis)
Open seasons filed significantly before the
application - helps determine design and size of
pipeline required for application
MR. SHARP noted that these comments were from the testimony of
Robert Cupina, FERC's Director of Energy Projects, on July 17,
2001, in a Joint Natural Gas Pipeline Committee hearing. Mr.
Sharp further noted that there is a "case precedent, legal
precedent, Section 7 of the natural gas Act and Panhandle
Eastern, which supports our views here." Basically, he said,
FERC cannot force an expansion of the pipeline. Open seasons
aren't regulated or required; if his company had a problem with
the open season from an explorer perspective, it would have to
be under a complaints process, which is inefficient, expensive,
[time-consuming], and usually "doesn't result in a reasonable
outcome."
MR. SHARP discussed a second key point. An open season is held
significantly ahead of time, before an application; the reason
is that it is used to help design and size the pipeline.
Because there is a difference of opinion regarding FERC's power
in this regard, he proposed that access and expansion terms be
written into "the producers' federal enabling legislation."
That would clarify all the rules for access and expansion for
everyone.
Number 1472
MR. SHARP noted that pages 8 and 9 talk about, from the
explorers' perspective, how they will use the RIK sale. He
explained:
Essentially, what we're faced with is exploring and
wanting to monetize natural gas in Alaska. However,
in order to do that, we need firm service. The firm
service is an obligation of $150 million a year. And
over a 15-year timeframe, it's over $2 billion. And
if the term of the firm service is 25 years, it would
be over $3 billion dollars.
Now, without proven reserves - as explorers - we just
can't commit to that type of financial commitment.
And that's where we come in with the royalty-in-kind
proposal.
MR. SHARP discussed a section of page 8 that read:
State RIK backstop agreement
- acts like insurance policy for Explorer
- not a handout, Explorer competing and paying for
RIK gas
- State receives RIK price [greater than or equal
to] RIV price
MR. SHARP explained that the state would be backstopping the
firm service, while [the explorers] would pay a premium relative
to [the state's] royalty-in-value gas price that it would
receive in royalty-in-kind gas. He emphasized that the
explorers aren't asking for a handout, but would be paying a
premium for the right to have this type of insurance policy.
"We're guaranteeing that the royalty-in-kind price will be
greater than the royalty-in-value," he added.
Number 1379
MR. SHARP referred to page 9, noting that it shows the timeline
of the firm service versus the royalty-in-kind purchase
agreement. He told members:
We will know by 2005 whether our exploration is
successful on the foothills. And by 2007, which you
can see in our bid document, that's when we will have
ensured that we've met ... our work commitment on the
North Slope; otherwise, we'd pay liquidated damages.
So we'll actually know, before the pipeline even
flows, whether we're successful in our exploration and
we'll have our own gas to flow or that we require the
backstop. And I think because of that, then, the
producer group has more than advance notice of what
our plans will be. And we would like to work together
on how that would work, with the state as well as the
producer group.
Number 1340
MR. SHARP turned attention to page 10, "Foothills Gas Decision
Tree," which relates to decisions regarding development. First
is ["RIK bid success"], which is happening now; second is the
open season, during which "we would have to commit to firm
service and the onerous liability of the firm service demand
charges"; and third is "exploration success." He pointed out
that the state receives a benefit in all cases, without risk.
He characterized it as a win-win situation for everyone.
MR. SHARP elaborated. Even if there were no bid, he said, "the
state knows what the value of your gas is because you have four
bids coming in, and it gives you an idea of the interests and
the ideas that you could have for monetizing your gas." As for
the pipeline firm service, he said, "If we're unsuccessful in
the open season for some reason, you'd still have our
[exploration work]." He added, "In the foothills, you know what
the potential is for gas, on the foothills and the North Slope."
MR. SHARP told members that if the company were unsuccessful
regarding exploration, "we would be mitigating the
transportation charges that we have under the royalty-in-kind
sale, and over a 15-year period that would be an incremental $77
million over and above the royalty-in-value price that we would
be paying to the state." Finally, if the company were
successful in exploration, one successful gas discovery would
bring in $6.4 billion in "in-state value-add." He said that is
shown in an economic study "that we have in our bid process."
Number 1208
MR. SHARP, in the interests of time, indicated he would skip
page 11, which shows how an explorer utilizes the [RIK] sale.
MR. SHARP turned attention to pages 12 and 13, which relate to
whether there is an impact to the producers. The "decision
tree" on page 12 relates to whether to build in the RIK volume
right from the start. It shows that at 4 bcf a day, if the
pipeline is easily expanded, there is no impact to the producer
group. If the RIK volume is built in right from the start, he
emphasized, there is actually a significant benefit to the
state, as well as - to his belief - to the producers. He
explained, "Where they can accelerate production, you can have
an incentive for more explorers and business and expenditures
and jobs into the state, as well as it maximizes the gas price
in Alaska, as the pipeline's not a bottleneck."
MR. SHARP discussed the "cost side" for the producers [page 13]
from the explorers' perspective. He noted that the chart shows
the supply chain, including the process plant, the carbon
dioxide (CO2) plant, and the pipeline. He offered the belief
that the CO2 plant wouldn't be a bottleneck because its cost
would be five to six times less than the pipeline; it wouldn't
make sense for the producer group to underbuild that portion of
the supply chain because they would want to keep the pipeline
full. He referred to an example on the chart relating to
downtime between the field and the pipeline; he said the end
result is basically an impact of less than 5 cents per million
cubic feet to the producers, which he believes to be "well
within the accuracy of their forecasts of costs and prices for
their project." He concluded, "From our perspective, it's
insignificant impact to the producers."
Number 1088
REPRESENTATIVE GUESS referred to page 12 and asked Mr. Sharp to
go through the scenario of having 4.35 bcf a day and no
exploration. She said it seems there would be a five-year
contract, for example, and then [the explorers] might decide
they didn't want to be in the business anymore; thus the gas
going through the pipe might be down to 4 bcf a day. She
suggested that in addition to the risk of not building a
pipeline with enough capacity, there is quantifiable risk in
building one bigger than will be used. She requested
clarification about the ostensible lack of risk and the benefits
of having extra capacity.
Number 1009
MR. SHARP answered as follows:
Right now in Prudhoe Bay they're cycling 6 to 8 bcf a
day. And if you're only talking a 4-bcf-a-day
pipeline or 4.35-bcf-a-day pipeline, really, you have
the supply there. And so you could actually
accelerate production from Prudhoe Bay and Point
Thomson for that small portion of the pipeline; it
only represents 8 percent of the capacity. And so
you'd actually get accelerated gas sales. And on a
time-value basis, that's significant value to both the
state as well as the producer group.
Number 0971
REPRESENTATIVE GUESS asked, "But isn't that forcing the people
that are left over, that have the 4 bcf, into doing that?"
MR. SHARP answered:
Not necessarily. I think they would do it because it
would maximize their revenue. But I think, more
importantly, if you do have capacity on the pipeline,
it creates an incentive for other people, other
explorers, to come into the state and explore for gas
as well. But I think that's really where you gain a
competitive natural gas industry. The more players
that you have, the more money that's spent in the
state, the more jobs, the more revenue that's created.
Number 0928
REPRESENTATIVE GUESS countered that it seems that the whole
backstop proposal is just shifting risk. She explained:
We'd either sell it to a producer such as yourselves
and we're fine, or we force the people who own the
pipeline to move it. So we're not really having any
risk in either case. But ... you could leave after
your contract and there still could be that empty
capacity, or we could have ... 4 bcf and we could take
the producers' view of "then they're forced to take
it."
MR. SHARP responded:
I think there'd be two ways I'd add to that. I think
first would be the gas potential on the North Slope.
I think you have to take that viewpoint that out of a
100 [trillion-cubic-foot] potential, that if you have
capacity on the pipeline and people are able to ...
monetize their gas exploration and production, you're
going to have lots of players out there exploring,
because they're going to want to fill that piece of
pipeline first before, let's say, the existing proven-
reserve holders. And I think with that small margin
of the 350 million cubic feet a day, I believe that
could be easily filled by the existing proven reserves
on the North Slope.
And that's kind of why I had this next chart here
[page 13], is that if you have a processing plant here
with a capacity of 8 bcf a day, and you have the CO2
plant - which they have to put in place - what I'm
suggesting is that you would overbuild this CO2 plant,
regardless of whether you have the royalty-in-kind ...
sale occurring, the reason being that this is only 20
cents, whereas the pipeline cost is five to six times
as much. So you want to make sure you have excess
capacity on the front end so you can always keep your
highest-cost component of this supply chain full.
So my argument ... is that the 350 million cubic feet
a day is such a small portion of this overall volume,
I believe it would be within the design of these
facilities. In fact, ... if I was the producer, I
would design that in, so I could keep my pipeline
fully utilized ....
Number 0764
MR. SHARP offered some of the conclusions outlined on page 14 of
the handout. From an explorer's perspective, he noted, AEC
believes the RIK is in the best interest of the state and that
RIK provides no risk [to the state] or impact to the producer
group, unless it is a positive impact due to the accelerated
sales. In closing, he emphasized that AEC is offering to the
state a vision of creating a competitive, multiplayer gas
industry in Alaska, and believes that this RIK sale is the first
step towards creating that.
Number 0704
CHAIR OGAN thanked Mr. Sharp and requested that his company,
along with other independents operating in Alaska, including
Anadarko Petroleum Corporation, provide an overview to the
committee as well as suggestions of what [the legislature] can
do to make it easier for independents to do business in Alaska.
He stressed timeliness in case legislation needs to be drafted.
He then introduced Mark Hanley, former member of Alaska's House
of Representatives.
Number 0610
MARK HANLEY, Public Affairs Manager, Anadarko Petroleum
Corporation, came forward to testify, noting that Mr. Sharp had
gone over a lot of the issues already. He pointed out the
following in the [the Anadarko/AEC] bid document: cash payments
that have accrued [$350,000]; an exploration work commitment for
$50 million to do exploration in the foothills looking for gas;
a preference for in-state gas processing, which may encourage a
company like Williams to process gas, for example; a preference
for local hire; training obligations; and other items that he
believes show that the state will get a value out of its royalty
gas because of the addition of other factors beyond what the
state would get otherwise. Clearly, if the state sells its
royalty gas, he said, there is going to be added value from
that.
Number 0492
MR. HANLEY addressed timing. He emphasized that if the state
doesn't sell its royalty gas before an open season, it is
unlikely to get anything for its royalty gas. He told members:
Everybody will bid capacity on the pipeline. It will
be utilized at full capacity, and there'll be no
reason for people that already have capacity to pay an
extra premium to carry the state's gas. And anyone
else that wants to buy the state's gas, other than
potentially right on the North Slope, ... there won't
be any capacity for them to take that down the
pipeline. So they won't be able to bid. ...
It is important, if the state is interested in getting
extra value for its royalty gas, that that sale occur
before any open season. And, again, you've heard the
producers say they don't see one in this calendar
year; of course, that could be early next year, which
would have the same problems, or ... I suspect if they
got their federal legislation and the tax credits that
they were going [after] and their study finally
finished up, and they said, "We've got a project," you
would expect them to hold an open [season]. In fact,
the state would encourage them to have an open season.
... The timing is crucial to have a royalty sale, to
see what kind of bids you have out there.
Number 0373
MR. HANLEY turned attention to whether FERC can force expansion
and what its regulatory abilities are; he offered his belief
that FERC is lax in how it regulates. He referred to a letter
[dated January 15, 2002, from the Alaska Gas Producers Pipeline
Team to DNR Commissioner Pat Pourchot] asking that the sale be
canceled, noting that it suggests no precedent is cited in
support of the assertion that FERC cannot compel expansion; it
also says that FERC asserts it can compel pipeline expansion,
and provides a citation. Mr. Hanley advised the committee that
he could provide a legal citation that suggests FERC cannot. He
recalled hearing Mr. Hurley say, however, that [FERC] could not
force expansion, nor would that be desirable. Mr. Hanley said
this is a critical issue for the committee to understand. He
further said:
You can't bid for initial capacity and take the risk
if you don't have any gas. And if you don't bid for
initial capacity, it's all going to go to the ...
producers' team, and that's a natural.
But what you really have is a policy call. If they
control all the capacity - and we suggest if they
control the initial capacity, it's going to make it
almost impossible for anybody to get into the expanded
capacity as well - you will not have exploration in
this state, not by frontier explorers like Anadarko or
Alberta Energy in areas like the foothills - at least
not for many, many years, long after lease sales have
expired. And, in fact, you're not likely to get
additional participants at a future lease sale in the
foothills if people cannot be guaranteed access.
So there is an impact to the state. There's a benefit
by selling the royalty gas. It's a guaranteed higher
value.
Number 0185
MR. HANLEY continued:
The question you have is, the producers assert "this
is going to kill the pipeline" or "it's unduly
burdensome." That's your question, and you need to
delve into that in detail, because we think there are
ways that the potential risk that they suggest can be
mitigated.
One of the assumptions I think they made in their
example, which is very simple, is that there's a 4-bcf
pipeline. Well, do you build it and it's only 4 bcf?
Can you not squeeze another molecule through? What is
the level? ... Typically, even without expansion
costs, there's some flexibility of 100, 200 mcf a day
on a pipeline the size of 4 bcf. So, possibly, of the
300 that they say they would get, prorated, possibly
200 would be able to be absorbed within any system
that they build.
Of course, I think they may claim that they're going
to build it to the absolute maximum molecule that can
be put through, and not another. That's not, in our
understanding, the reality of the situation. So, some
of that risk is mitigated. Gas left in the field
potentially means more oil recovery; that's [an] added
value to the state and even, potentially, the
producers; it mitigates some of that risk. So there
are ways to go out there.
I think one of the problems you have is it's very
difficult to talk in theoretical terms when you don't
know the specifics. And you don't know what they say
the maximum volume's going to be. You don't know what
they say the maximum pipeline capacity's going to be.
We don't know what the expansion capacity [will be].
The terms and conditions of open seasons and expansion
are generally set by those that build the pipeline.
So of course they're going to set them both to their
best economic value but also to their advantage for
controlling the capacity, because that ... is an
economic value to them as well. And so that's not a
bad thing. They're going to do ... what's in the
companies' best interest. It may not be in the
state's best interest. It may not be in the
explorers' best interest.
MR. HANLEY said the question is whether explorers can be
provided for; he cited ASRC as an example.
TAPE 02-7, SIDE A
Number 0001
MR. HANLEY reiterated the need to get specific information from
the producers on how they will build this [pipeline]. He added
that if the expansion capacity is also "one shot or nothing," it
also has the ability to "freeze out" people; however, the
producers could say it's the cheapest way to build it. He told
the committee:
You need to make that call, because ... if it goes
forward the way it could very well go forward, you
will have three producers, largely, controlling all
the capacity, and you will not have exploration. And
is that a good thing for the state?
I think Conoco suggested awhile back that controlling
capacity on a pipeline - and this was a common-carrier
oil pipeline - was one of the reasons they left the
state. ... You're hearing people tell you, "This is an
issue; this could cause companies not to explore for
things."
Don't just take our word for it. Get your own
independent evaluation of FERC authority and get the
details from the producers so that you can actually
make an honest value judgment of whether there is a
risk, whether there are ways to mitigate that risk.
Number 0139
REPRESENTATIVE GUESS asked Mr. Hanley whether he believes the
RIK [gas sale] is the only way to ensure access and expansion of
the gas line.
MR. HANLEY answered, "Not necessarily." He said there are lots
of public policy calls. For example, it could be a common
carrier. The same issues would exist, he noted; the producers
would argue that they don't want their gas prorated. He added:
But it happens on oil lines all the time, and it's not
unusual. It's unusual for a gas line, but this is an
unusual gas line, with identified reserves that you
know are out there to do it. You could reserve all
the expansion capacity for new gas, or give it a
preference. There are other ways to do things,
absolutely. RIK is not the only way to go about this.
Number 0231
REPRESENTATIVE DYSON remarked:
We could also do something that guarantees there's
always an open season, or that you guys don't get shut
out of the open season because of your timing on
exploration, or that, as [Mr. Sharp] suggested, that
pipeline gets built with the excess-capacity potential
and that you only have to pay your agreed-upon fair
share of what expansion costs are, in order to get
your gas in the pipe.
MR. HANLEY replied:
Possibly. ... But, again, it comes down to who
controls the process .... If you start off with a
goal of making sure it can be easily expanded and
that's a policy you want to have, do you think you can
design a project that can do that with minimal cost?
Well, you probably can. It will have some extra cost,
possibly, but is there some extra benefit even to
yourself? Possibly, but these are things you don't
know ... because you're not doing the design. And
could you design a project that creates the most
advantage for you ... on a business basis?
Absolutely, making it difficult for others to get in.
... It can also be economic.
Number 0369
CHAIR OGAN remarked that the more he deals with the pipeline
issue, the more he realizes how little influence the state has
on it; because of FERC, [most decisions come from] Washington,
D.C. He thanked Mr. Hanley and invited to the witness table
Mark Myers and Bonnie Robson of the Division of Oil and Gas.
Number 0460
MARK MYERS, Director, Division of Oil and Gas, Department of
Natural Resources, noted that online to answer questions was
Kevin Banks, the division's commercial market analyst, who is
the person within the division who has been most responsible for
the RIK sale program.
MR. MYERS commended the legislature and this committee for
taking on this issue early; he emphasized the importance of this
issue to the state. He pointed out that the process was begun
the previous year when the legislature asked DNR to consider a
potential sale to Netricity and to look at selling the state's
RIK gas. He told members:
We got the message loud and clear that the legislature
wanted the state to look at the options it had for
uses for its royalty gas and how it might sell that
royalty gas versus leave it in value. So, again, we
are ... trying to honor ... the commitment to you to
fully evaluate it.
An RIK sale does just that. We get proposals in from
all parties ... interested in ... wanting to purchase
RIK gas. So it was a very open process in the sense
that ... anyone who could meet the minimum business
requirements in the state ... could bid.
Number 0550
MR. MYERS noted that the process has been characterized as an
"RIK backstopping method." He stated:
That's totally untrue; that's a total misconception.
It is an open process, requires full analysis of all
bids, regardless of what the intended purpose of those
bids [is], and then it involves your legislative
approval. So it's a very public process to look at
all options for state ... RIK gas. And that's, again,
part of what DNR considers.
You've put a tremendous amount of fiduciary
responsibility on us to manage our state oil and gas
lands to the maximum benefit of the people of the
state. And that's really what this is all about, is
DNR's attempt to assure that we are maximizing value
for the people of the state, whether it be financial
value, whether it be in-state refining potential,
local energy use by a local utility, or whether it be
to allow for further exploration. And it's also,
certainly, to receive maximum financial value ... for
that gas received.
Certainly, when you look at the way the proposal from
the state was set up, it was designed to look at all
those ... potentials. So I guess I take exception
with the concept that the sale's purpose was to
provide RIK backstopping. That was one of the
possible uses that was listed, out of many other uses.
So, hopefully we cleared up ... that misconception.
Number 0665
MR. MYERS noted that this committee and others have been looking
at what to do to facilitate a robust oil and gas industry in
Alaska as oil revenues decline. He suggested rather than having
incentive programs that give out dollars, the state should
ensure fair access to its oil and gas lands, whether through
lease sales or facilities. It is crucial to the process, he
said.
Number 0693
MR. MYERS referred to a handout titled "Alaska Royalty-In-Kind
Gas Sale," dated February 5, 2002. He brought attention to
Figure A, "Alaska's Onshore Basins," noting the potential beyond
Prudhoe Bay and Point Thomson. If the state is to see that
potential realized, he said, there has to be access. He likened
it to building a superhighway and then not allowing anyone to
travel on it; that is how critical access to the pipeline is to
the state's future well-being, he told members. It applies not
just to the North Slope foothills, but also to other Interior
basins that might be along the pipeline's route. "It's not only
intake of gas; it's also offtake of gas for local use," he said.
"All those are critical issues that revolve around the issue of
access to a pipeline."
MR. MYERS turned attention to Figures B and C. He said the
potential for gas on the North Slope is astounding. As
mentioned by BP, for example, there is more than 100 trillion
cubic feet of gas hydrates. He said those gas hydrates sit
almost directly under the current existing facilities.
Number 0770
MR. MYERS, in response to a question from Chair Ogan, explained
that akin to ice, gas hydrates are actually frozen rather than
being in a free, gaseous state. Gas hydrates contain a
tremendous volume of captured gas. It is known that the
hydrates are in the field because there have been extensive
drilling through it and early studies. He added:
We have all the well data, all the seismic data to
indicate the hydrates are there, so we have great
certainty; these numbers are certainty.
Now, how much of that can be captured economically is
another question. But ... we get into the issue of,
will you overbuild this pipeline? And if you have
another [trillion cubic feet] of gas sitting just
underneath the existing infrastructure that won't be
available for capacity in the line for 15 or 20 years
... or longer, I have great faith we'll find the
technology to do it.
[There are] research programs going on as we speak by
the Department of Energy; there are two proposals that
have been funded for Alaska by two different groups
that ... will result in the drilling of wells to test
the commercial production of these hydrates.
Number 0863
CHAIR OGAN requested confirmation that the hydrates aren't
currently in production.
MR. MYERS said they are solid, at fairly shallow depths just
underneath or in the base of the permafrost on the North Slope.
He referred to Figure D, which shows a well cross-section
displaying gas-hydrate and free-gas zones. He said, "We can
quantify with great accuracy the amount ... of hydrates there."
MR. MYERS brought attention to Figure E, "North Slope Gas
Hydrate Potential." Although it shows hydrate potential all
over the North Slope, he said, not just beneath the existing
infrastructure, it is under the infrastructure that it would
have the best economics.
MR. MYERS told members the state wants to facilitate a long-
term, viable gas industry. The question is how to get there.
Obviously, there must be a pipeline, and "you can't burden it
commercially to the extent that makes it unusable," he said.
"However, we do believe that the RIK sale does not burden, yet
could ... facilitate this process."
MR. MYERS highlighted that this pipeline is contract carriage,
whereas an oil pipeline is common carrier. Many of
Representative Dyson's good questions on the issue of open
access wouldn't be a question on a common-carrier line.
However, a contract-carriage line doesn't provide the certainty
that there is readily available access "to other folks."
Number 0981
MR. MYERS told members:
We've had numerous discussions with many consultants
and external lawyers, FERC experts, and we've actually
had internal communications within FERC. And FERC has
never, to their internal knowledge, forced an
expansion of a pipeline. They believe that market
forces will, in fact, lead to the expansion.
However, in Alaska we have a very unique situation.
Those market forces in the Lower 48 would drive either
the pipeline to expand or a new pipeline to be built
if they weren't willing to expand. We're going to get
one pipeline.
MR. MYERS cited some reasons Alaska will get only one pipeline:
environmental reasons, construction costs, lots of permitting,
and treaty negotiations, for example. The same market-forces
expectations aren't there as for a contract-carriage pipeline.
He said:
I think there's concern, and you've heard some of that
concern by explorers. We have an RIK bid from a
producer: Chevron, [which] has over 2 [trillion cubic
feet] of gas on the Slope, has the same concerns. ...
We have folks like Williams that are bidding that,
again, are transporters, marketers; they have concern
about access. And finally, we have local power
companies and users concerned. So one of the things
the RIK process brought out was we had bids from the
total spectrum - from producers with known reserves to
explorers to transporter-shippers and refiners ... and
to the final end-users.
Number 1047
MR. MYERS noted the enormity of this issue [of access]. After
pointing out the differences of opinion, he said, "We are ...
very uncomfortable that a contract-carriage pipeline will
provide that access." He explained:
Why is that access important in the sense of the
state's RIK value ... and the timing issue? Well, the
bottom line is, the state does not ship gas itself.
The state has historically sold its gas on the North
Slope, expecting whoever buys it to deliver that to
market. ... They cannot do that if they don't have
capacity in the pipeline, plain and simple. There has
to be capacity ... for someone to buy RIK gas on the
Slope unless they intend to use it on the Slope.
Number 1101
CHAIR OGAN posed a scenario in which an entity that bids on the
state's RIK ends up producing its own gas and putting it into
[the pipeline], then substitutes the RIK gas. The producers
would be required to carry the RIV gas, he suggested, and it
would displace the throughput. He said that seems to be what
the difference of opinion is about. He asked Mr. Myers to offer
his view on that. He also invited the producers to come back
before the committee to comment [at a later date].
Number 1183
MR. MYERS responded:
Under that scenario, the state is a winner. That
means additional gas has been discovered and is being
produced on the North Slope. So new gas reserves are
coming online for the state, with ... the billions of
dollars of added value that goes along with it. So we
are a winner. ...
That means there's additional capacity in the pipeline
system. ... That implies, then, that the pipeline is
operating at a higher production level and ... is more
efficient. Producers - I think the issue steps back
to a larger issue of, is a pipeline a pipeline, or is
a pipeline an extension of the existing oil fields?
Now, clearly a pipeline's supposed to be a separate
infrastructure ... from the oil fields. It's
regulated separately; it's a very different beast. I
do not see any of those cases where the pipeline
itself is disadvantaged in this case. ... The pipeline
economics are always positive; in fact, they're better
there, and they're better in this case.
What would then happen, if the producers feel that
they were getting less [throughput] of their gas, they
would then ask for an expansion of the capacity of the
pipeline; the pipeline would expand - the pipeline has
more rates, has better economics in that case. So,
again, the pipeline wins, we win, the producers
ultimately win, but there's a period of time prior to
that expansion where they would then have to forego
some of their gas in order to carry RIV gas. ...
So basically we see, again, if you look at the
analysis by Alberta Energy, we see an effect on the
producers' cash flow. That effect is relatively
minimal for the value to the state and to other folks,
and, again, we believe there are ways to totally
mitigate that loss and damage.
Number 1339
REPRESENTATIVE FATE inquired about the endpoint where expansion
ceases and it becomes uneconomical and inefficient to continue
that expansion. Given the tremendous amount of potential up
there, and given that the market price of gas is expected to be
economic when this comes online, he said, there may be a huge
surge that will "go above that endpoint." He asked: What do we
do then?
MR. MYERS said that is a very good question. He answered:
Basically, if you look at the design [specifications]
of the proposed pipelines, they have generally .8 to 1
bcf of additional expansion capacity planned. And
that ... expansion capacity depends on the pressure of
the line and ... a little bit on the gas itself, but
then on the amount of compression. ...
The economic part of the expansion curve is designed
into the pipeline in the early stages, but what the
producers are suggesting is ... about .8 to 1 bcf of
expansion capacity. Then it gets very expensive and
very inefficient, and you have to basically double the
pipeline - create another parallel pipeline or make
large loops in the pipeline - to get expansion
capacity beyond that, when probably that is going to
be very marginally ... challenged economically to do
that.
So approximately 20-25 percent expansion capacity is
probably going to be the limit, [given] design specs
at this time. So what do you do after that? You wait
in line. And if you don't have expansion capacity,
nothing happens. You wait till there is capacity in
the line.
Most gas pipelines are built with expansion capacity.
In other words, they're built at less than the known
offtake. So this is a very unusual case, where we
have the ... capability to offtake at least 8 bcf and
no design has contemplated anywhere near that size.
The current reserve base is probably problematic for
that level of offtake as well.
So the bottom line is, this is a unique situation
where the pipeline, as you have suggested, is
constrained not by the ... ability to deliver supply,
but by the size of the pipe. ... We can't do much
about that; that's an engineering-spec problem and a
cost differential that will make expansion beyond
about 25 percent probably uneconomic.
Number 1470
CHAIR OGAN asked whether Mr. Myers was saying design is the
limiting factor because "we've got as much gas as we can put
down the line." If that is the case, he asked, how much does
the "offtake affecting production" drive that decision? He
offered his understanding that studies were planned but not done
by the AOGCC. He asked how much [the division] is looking at it
as well.
CHAIR OGAN said he'd like to see some independent analysis
regarding how that affects oil production. He noted that a warm
winter on the North Slope results in a drop in production
because not as much gas is being injected; he suggested that
certainly offtake would affect it. Also in the mix is the
amount of gas being produced in the foothills, for example; he
said the more gas is produced in the foothills, the less gas
will be taken off the existing producing oil fields, and the
longer those fields will last.
Number 1562
MR. MYERS responded:
First of all, there are ongoing studies to look at
offtake rates. It's a little more complicated that
just Prudhoe Bay because Point Thomson contains at
least 8 bcf of gas reserves as well. So you have a
balance between two fields, and ... since Point
Thomson will be ... a green field, a brand-new
production facility, there's a lot of latitude to
design what that level of offtake is and what you do
to optimize the liquids recovery as well.
Prudhoe Bay, the same way, there are mitigation
measures such as the "pressure-support initiative"
where you inject water into the gas cap. There are
ways to mitigate the offtake of gas.
And then the timing of initial sale of the pipeline
has great effect. ... You see the rapid decline in
Prudhoe is continuing on the main reservoir. So if
the gas sale is delayed a few years, the question is
very different in terms of oil loss than if it comes
on in, say, a 2008 timeframe. 2008 versus 2010 -
[they] are different.
All those are [mitigable] standards, and certainly
everyone has to look at the economics of ... oil loss,
the conservation of the resource involved with that.
But there is a tremendous amount of flexibility in
that process.
And, again, if you think about the 2008 timeframe, an
explorer would have time in that timeframe to go out
there. ... They've got six years. They've got two or
three years to delineate additional gas reserves as
well to, again, ... look at other gas coming ... into
the system. But, again, you can't ... nominate gas
unless you have it because the risk you take is ...
substantial. ...
I believe there's a workable solution. ... It's
partially economics, partially drawn by the reservoir
engineering. But it's a [mitigable] standard because
of the flexibility to take ... offtake gas from both
Prudhoe and Point Thomson. And it's also driven,
then, by market value of gas ... versus incremental
oil recovery.
Number 1673
CHAIR OGAN stated his understanding, then, that the issue of the
oil production's not being as prolific isn't really a driver in
the decision of how much gas is put in the line or the ultimate
decision on how big to build it.
MR. MYERS responded that there is a range of values; within the
range of values for a probable pipeline, however, there are
"solid ways" to mitigate the oil loss. He added:
Now, if you're talking about taking 6 bcf out of
Prudhoe Bay, no, there's not; there would be
significant oil loss. If you're talking about 2.5 to
3 and the rest out of Point Thomson, it's a much
easier issue to deal with. ... Within the sidebars of
the potential sizes of a pipeline between 4 and, say,
... 5.5 or so, those are totally [mitigable]. But if
you get a very large number like 6 and 8, then the
issue becomes very acute and ... there's going to be
more oil loss.
Number 1730
CHAIR OGAN suggested that gas from the foothills would play some
role in extending the oil fields. He asked whether that is a
fair assumption.
MR. MYERS answered:
If you were to produce gas from other resources,
definitely the oil loss would be less. Ultimately,
there will be some oil loss. The ... longer you
maintain higher reservoir pressures in the field, the
longer you maintain miscible flood injection, miscible
flood, the more oil you're going to recover. But that
... window of oil you recover becomes smaller and
smaller and smaller as time goes out.
Number 1770
BONNIE ROBSON, Deputy Director, Division of Oil and Gas,
referred to Chair Ogan's mention of testimony from BP and
Phillips that the RIK sale may harm the pipeline project or harm
them as producers. She said:
I think both the statements of Mr. Hurley and Mr.
Konrad were to the effect that "we do not object to
all RIK sales; we only object to those sales where
some volume of gas may be ... taken out of royalty in
kind and put back to the producers as royalty in value
during the period of time required as a commitment for
pipeline capacity." And he gave an example where
there could be a possible put-back of .3 bcf of gas
from an RIK purchaser to the "big three" during the
period, say, a 15-year commitment for the initial
pipeline capacity.
There's a couple of points I think need to be made in
response. First of all, if .3 [bcf is] put back to
BP, Exxon, and Phillips, they have come forth and
stated that this pipeline ... can be expanded
relatively easily and fairly through an open process
with FERC. And if they have an additional .3 [bcf] at
that time that they need to get to market, then they
can seek expansion of the pipeline at that point in
time.
And I suggest to you that it will be easier for those
who own the pipeline to expand the pipeline than for
those who do not own the pipeline and have no standing
to compel expansion.
Number 1863
MS. ROBSON continued:
The second point to keep in mind in this regard is
that what they are essentially saying when they say
that they do not object to all RIK sales, just one
where the duration of deliveries may be less than the
pipeline commitment - and I'll use 15 years as an
example of a pipeline commitment - ... is, "We
recognize that while the lease form gives the state
the right to switch between royalty in value on six
months' notice, we, in fact, want that six months to
be changed to 15 years." They are asking for a change
in the term of the leases that they execute with the
state.
And I think, in deciding whether or not that's an
appropriate change to ratify, you need to look at the
standards that the statutes - in fact, this
legislature - have dictated for providing some form of
royalty relief.
Basically, the leases have two provisions on royalty.
The first imposes royalty and sets the rate -
typically at 12.5 percent. The second gives the state
the right to take its royalty in kind or in value, and
to switch on six months' notice.
Now, you have dictated that when they want relief from
the imposition of royalty, from the 12.5 percent rate
-- let's say they want to go to 10 percent. What they
must do, to do that, is to come to bare their soul, to
show their economics, to open their books, to convince
you that royalty relief is needed, is in fact
justified, and will not harm the state - in fact, will
benefit the state.
Here, they are asking for a form of royalty relief.
They are saying, "We do not like the six-months'-
notice provision in the lease forms. We want that to
read 15 years."
I suggest to you that it is appropriate for them to
come forth and to provide the numbers, provide the
economics, to open their books, to show that it really
does hurt, and that there is not an alternative. We
have, in fact, asked the producers to come forth and
to make that showing, to run us the numbers.
Today is the first day we have seen any numbers. We
will explore them further. We will continue to ask
the producers. We will examine whatever numbers they
provide .... We have attempted to run the numbers
ourselves in the absence of their information, and we
do not reach the same conclusions. We see the
possibility that this could, in fact, have a net
economic advantage to them, and certainly to the state
in many arenas.
So I think you need to keep that in mind, and we need
to ask the producers the hard questions, to make them
show us the numbers that would justify a conclusion
that this sale could, in fact, harm them and harm the
project.
Number 2019
MR. MYERS offered further comments:
The other question is - and I think Representative
Dyson was trying to get at the issue - are there other
ways to assure access? And we have explored with the
producers, with ... two of them, at least - Phillips
and BP - on whether or not they'd be willing to write
up language that would assure other folks - including
ourselves but including "explorationists" and other
people that might want access to gas - that ... there
would be reasonable expansion potential and fair
access to that expansion capacity.
They have declined to provide that language. The
response was a protest to the RIK sale. They've also
told us that -- Phillips has sent us a letter saying
the terms of the RIK sale are commercially
unreasonable, which is their term. Yet you've seen
the bids ... that support, from a wide variety of
users, from ... a producer with significant reserves
on the slope that has concern about access to
explorers that have concern about access, to, again, a
pipeline marketing company, to an end-user, all of
which felt the need to bid and did not see the terms
as commercially unreasonable.
So, again, there's ... strong differences of opinion,
and I'd commend you if you would explore as to why
these differences exist.
Number 2094
CHAIR OGAN replied that he would like to do that. He announced
that he would recess the meeting until Thursday at 10 a.m. in
order to continue the discussion and allow the producers an
opportunity to respond. He advised members that he would assign
a subcommittee at that time in order to facilitate discussion
and try to resolve the differences. He agreed it is an
important issue and expressed appreciation for testifiers'
participation.
ADJOURNMENT
CHAIR OGAN recessed the House Special Committee on Oil and Gas
meeting at 12:17 p.m., with the meeting to be continued on
Thursday, February 7, at 10 a.m.
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