Legislature(2001 - 2002)
08/14/2001 01:47 PM Senate NGP
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
Anchorage, Alaska
August 14, 2001
1:47 p.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Pete Kelly
Senator Johnny Ellis (via teleconference)
Senator Donald Olson, alternate
SENATE MEMBERS ABSENT
Senator Rick Halford
HOUSE MEMBERS PRESENT
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate, alternate
Representative Reggie Joule, alternate
HOUSE MEMBERS ABSENT
Representative Joe Green, Vice-Chair
Representative Brian Porter
Representative Mike Chenault, alternate
OTHER LEGISLATORS PRESENT
Senator Gary Wilken
Representative Jim Whitaker
COMMITTEE CALENDAR
NATURAL GAS PIPELINE PRESENTATIONS
Update on the report required by SB 158
Alaska Oil & Gas Conservation Commission
Department of Law
Gas Pipeline Office
Testimony - North Slope Borough Assembly
Alaska Highway Natural Gas Policy Council (rescheduled from
8/15/01)
Public Testimony
Legislative Legal Counsel (scheduled but not heard)
WITNESS REGISTER
Mr. Wilson L. Condon
Commissioner
Department of Revenue
P.O. Box 110400
Juneau AK 99811-0400
Mr. William S. ("Bill") Garner
Petrie Parkman & Co.
(No address provided)
Ms. Cammy Oechsli Taylor
Commissioner
Alaska Oil & Gas Conservation Commission
Department of Administration
333 West 7th Avenue, Suite 100
Anchorage AK 99501-3539
Ms. Julie M. Heusser
Commissioner
Alaska Oil & Gas Conservation Commission
Department of Administration
333 West 7th Avenue, Suite 100
Anchorage AK 99501-3539
Mr. Jack Griffin
Assistant Attorney General
Oil, Gas & Mining Section
Civil Division (Anchorage)
Department of Law
1031 West 4th Avenue, Suite 200
Anchorage AK 99501-1994
Mr. William G. Britt, Jr.
State Pipeline Coordinator
Department of Natural Resources
411 West 4th Avenue, Suite 2C
Anchorage AK 99501
Mr. Mike Aamodt
Member
North Slope Borough Assembly
North Slope Borough
P.O. Box 69
Barrow AK 99723
Mr. Jim Sampson
Co-Chair
Alaska Highway Natural Gas Policy Council
1000 Bennett Road
Fairbanks AK 99712
Mr. Charlie Cole, Chair
Federal/International Action Subcommittee
Alaska Highway Natural Gas Policy Council
Law Offices of Charles E. Cole
406 Cushman Street
Fairbanks AK 99701
Mr. Ken Freeman
Special Assistant
Gasline & Business Development
Office of the Governor
550 West 7th Avenue, Suite 1700
Anchorage AK 99501
Mr. Keith Hand
Fairbanks Natural Gas
3408 International Way
Fairbanks AK 99701
ACTION NARRATIVE
TAPE 01-9, SIDE A
CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural Gas
Pipelines meeting to order at 10:47 p.m. Members present during
the meeting were Senators Torgerson, Kelly, Ellis (via
teleconference), and Olson, and Representatives Ogan, Davies,
Fate (alternate), and Joule (alternate). Other legislators
present were Senator Wilken and Representative Whitaker.
CHAIRMAN TORGERSON confirmed that on teleconference were the
Juneau and Anchorage Legislative Information Offices (LIOs). He
then informed members that there would be public testimony from
the North Slope Borough at approximately 5:30 p.m., with more
than the stated three-minute limit being allowed. In addition,
the Alaska Highway Natural Gas Policy Council was being
rescheduled from the following day. Furthermore, U.S. Senator
Stevens may be an addition to the agenda for August 15 at 5 p.m.
NATURAL GAS PIPELINE PRESENTATIONS
Update on the report required by SB 158
Number 02.21
CHAIRMAN TORGERSON reminded members that SB 158 directed the
Department of Revenue to look into potential ownership of the
pipeline - either partial or total - by the State of Alaska. He
mentioned a possible port authority concept or a possible
corporation whereby Alaskans could buy some of it, for example.
Commissioner Condon has selected two companies to proceed with
that study; a representative from one of those companies would
speak today along with Commissioner Condon.
Number 03.34
MR. WILSON CONDON, Commissioner, Department of Revenue, discussed
the work the department has undertaken with respect to SB 158,
enacted during the last legislative session. That bill directed
the Department of Revenue to undertake a fairly detailed study
with respect to possible state financial participation or some
other form of state assistance in the financing of a project for
the commercialization of North Slope gas.
COMMISSIONER CONDON told members that as he reported in the July
hearing, [the department] was in the final stages of completing
contract negotiations with CH2M Hill and Petrie Parkman & Co.
("Petrie Parkman"). Those negotiations are completed, and the
companies have commenced work. The department is assisting in
some of the legwork, but doesn't yet have anything to report,
other than that "we're doing the work."
COMMISSIONER CONDON said "we" have talked with some committee
members about some specific aspects of the project and have
interviewed a number of Alaskan leaders about the pros and cons
of state ownership. He introduced Bill Garner of Petrie Parkman,
an investment banking firm specializing in the energy industry,
and pointed out a company resume [in packets].
Number 07.26
MR. WILLIAM S. ("BILL") GARNER, Petrie Parkman & Co., offered to
describe the firm and then provide his own background, since he
will be the lead person on this project. In addition, he would
discuss the requirements of SB 158 and how Petrie Parkman, CH2M
Hill, and the commissioner's office will proceed to prepare that
report.
MR. GARNER pointed out that although Petrie Parkman doesn't have
a presence in Alaska, it is the world's leading oil and gas
investment and banking specialist; that is all the company does,
which differentiates it from other investment banks. It provides
a full suite of services including divestiture and merger
advisory services, strategic advice, equity research, sales of
securities, underwriting, private placement, bankruptcy services,
and advising governments on energy-related initiatives.
MR. GARNER informed members that Petrie Parkman was founded in
1989 by the former lead investment bankers from The First Boston
Corporation ("First Boston") who left First Boston when it merged
with Credit Suisse. Today Petrie Parkman has offices in Denver,
Houston, and London. The capital markets operations are handled
exclusively in Denver, including research, IPO (initial public
offering) activities, writing research reports on other
companies, providing high-level strategic advice, and handling
financial aspects for companies. The Houston office, where Mr.
Garner is based, handles mergers and acquisitions, transactions,
and advice to governments. The company has about 35 specialist
professionals; about half are from the investment banking
business and about half, including Mr. Garner, are from industry.
MR. GARNER noted that in the past 12 years, Petrie Parkman has
closed more than $35 billion of oil and gas mergers and
acquisitions in more than 250 separate transactions, making it
one of the most active firms in the world in this business.
Named the Best Energy Research Boutique by Institutional Investor
magazine on numerous occasions, in 2001 Petrie Parkman was called
by Petroleum Economist magazine one of the world's leading
investment banks in terms of the monetary value of oil and gas
transactions it has closed.
Number 09.15
MR. GARNER turned attention to two of Petrie Parkman's major
projects for governments. First, it represented the U.S.
Department of Energy under the Clinton Administration in the sale
of the Elk Hills Strategic Naval Petroleum Reserve, which
resulted in the largest monetary privatization in the history of
the U.S. Second, Petrie Parkman is currently the advisor to the
Kingdom of Saudi Arabia in the largest natural gas investment
project in the world, the Natural Gas Initiative.
MR. GARNER explained that the kingdom is, in essence, reversing
many years of policy: rather than developing its hydrocarbon
reserves itself, it is now encouraging the world's largest oil
and gas companies to invest approximately $20 billion in
integrated natural gas projects within the kingdom over the next
ten years. This includes not only exploration and production,
but also the construction of pipelines, processing facilities,
petrochemical plants, power plants, and desalination plants; the
fuel for each facility would be natural gas, and Saudi Arabia is
believed to have some of the largest natural gas reserves in the
world. Having begun that project two years ago, Petrie Parkman
is "in the thick of it" now; it announced the winners of the
bidding rounds and signed the first agreements with those
companies in June, and is now assisting the kingdom in drafting
definitive documents for that investment.
MR. GARNER reported that Petrie Parkman has been active in the
Lower 48 in various transactions. A major project this year was
defending Barrett [Resources] in a hostile takeover attempt by
Shell Oil, which eventually led to an acquisition by the Williams
Companies. He noted that the handout delineates other projects
the firm has worked on.
MR. GARNER informed members that both Mr. Petrie and Mr. Parkman
will assist [on the Alaskan project]. Mr. Petrie's involvement
is primarily in advising the chairmen of companies on strategic
matters and in directing research activities. A graduate of [the
U.S. Military Academy at] West Point and a past member of the
board of directors of the National Association of Petroleum
Investment Analysts, Mr. Petrie has served as president of that
organization; has served on the Securities and Exchange
Commission's Advisory Board on Oil and Gas Accounting; has
delivered a number of technical papers to the Society of
Petroleum Engineers on the subjects of petroleum valuation,
merger and acquisition trends, and energy policy; frequently
appears in the media, including being interviewed on a variety of
energy policy matters on television programs such as "Wall Street
Week" and "The McNeil Lehrer News Hour" and on CNBC and Fox News;
and has been quoted frequently in Barrons magazine, including the
[July 27, 2001] issue.
MR. GARNER reported that Mr. Parkman, who heads the Houston
office, began his career in the industry and later became head of
the oil and gas mergers and acquisitions operations for First
Boston.
MR. GARNER offered his own credentials. He heads the firm's
international practice and is "the pipeline guy." His background
is in natural gas pipelines, and he was the former general
counsel of the fourth-largest natural gas pipeline company in the
world in terms of miles of pipe, K N Energy, Inc. (which since
has merged with Kinder Morgan, Inc.); he noted that neither of
those firms has been active in Alaska. Following that, he was
appointed head of the international group at K N Energy, Inc. He
began work with Petrie Parkman approximately 18 months ago, and
primarily works on pipeline projects and international projects.
Number 13.58
MR. GARNER turned attention to SB 158. He told members
preliminary work has begun with the commissioner's office. The
first process is talking to the stakeholders. It is critical,
before addressing details, to get a better understanding of what
citizens, legislators, proponents, and opponents have to say
about this idea; therefore, CH2M Hill and staff of the
commissioner's office have undertaken those interviews in Alaska.
Those at Petrie Parkman will talk to the companies and the
proposed project developers because it is important to get their
sense about these requirements.
MR. GARNER told members the remaining part of the examination
will be undertaken following that. This includes examining the
history of state participation in the Trans-Alaska Pipeline
System (TAPS) and other natural gas pipeline proposals that have
come before the state; determining the current status of the
various gas pipeline proposals; identifying and quantifying key
uncertainties associated with project development such as
construction costs, operating costs, tariffs, and throughput;
examining available financial participation options of the state,
such as full or partial ownership through public or private
corporations or other entities; looking at sources of funds such
as the permanent fund earnings reserve or the constitutional
budget reserve fund; looking at debt alternatives, including
revenue bonds, general obligation bonds, and so forth; looking at
the feasibility of the state's guaranteeing private debt or
guaranteeing debt in general; and looking at other alternatives
such as state ownership not of the pipe itself, but of the
capacity within the pipe.
MR. GARNER reported that following that, evaluation criteria will
be developed regarding what will be in the best interest of the
state. These include determining what kinds of returns the state
should be looking at; what the impact criteria are for the
state's cash flow and bond rating; what the impact is of the
availability of state credit to fund other essential public
services; looking at conflicts of interest and issues associated
with state ownership in such a project versus the state's
obligation to regulate various aspects; and looking at economic
development generally in the state and the impact of the natural
gas pipeline regarding project costs, the feasibility of the
project, the project timing, and the project participants, for
example. Then the various options will be evaluated against the
evaluation criteria, and recommendations will be arrived at, as
required in SB 158. That work will continue through the autumn;
the report is due to the legislature no later than January 31,
2002. Mr. Garner stated his understanding that [Commissioner
Condon] would be making periodic progress reports as well.
Number 17.41
CHAIRMAN TORGERSON asked whether Mr. Garner is familiar with
other governments, particularly in the U.S., that are part owners
of lines. He also asked whether there are similar studies that
might be looked at for comparison.
MR. GARNER replied that in the U.S., early in the history of the
development of the natural gas industry, there were situations in
which this occurred, primarily as economic development
initiatives; states and local governments would participate in
projects primarily as a means to either stimulate investment or
to meet some other political or environmental concern. For
example, when Denver got natural gas, one issue related to taking
the community off of coal, because of air-pollution issues, and
putting it on natural gas; there was a lot of state and municipal
activity at that stage. Mr. Garner added:
We're going to examine where that might exist today,
but it's ... certainly not a common feature in the
development of the industry today. Now,
internationally it is. Certainly in the case of Saudi
Arabia, where we're working, the Saudi Arabian
government intends to take equity participation
interest in certain of the projects. And the reason
they're going to do that would be their perceived rate
of return, security issues for the kingdom itself; they
hate to turn over certain strategic parts of their
infrastructure ... to non-Saudi entities.
And you see these kinds of activities in ... a lot of
places where you have state-owned oil companies -
Mexico, for example, Indonesia, places like that. ...
But it's a different situation than ... what you have.
There probably [are] ... some analogies that can be
drawn, and maybe some ideas that can be drawn here, but
typically in those countries you're dealing with
different problems altogether than what you have here.
Number 20.34
REPRESENTATIVE DAVIES asked Mr. Garner to comment on rate-of-
return issues. He noted that for a company investing, there are
different rate-of-return considerations than for a state. For
example, a state might take the point of view that infrastructure
development may be an adequate return on the investment.
MR. GARNER replied that it will be examined as part of this
report. These companies, however, are for-profit entities, and
have to make a return for their shareholders; how they look at
this project will be different from how the state will.
Furthermore, it will be regulated by the Federal Energy
Regulatory Commission (FERC); a lot of these issues will be
regulated by the federal government in terms of maximum allowed
rates of return. He pointed out that in a regulated pipeline, an
opportunity for huge rates of return generally don't exist; it
will be in the 10-15 percent range, and probably on the lower end
of that.
REPRESENTATIVE DAVIES responded that he was thinking more about
when the issue is being evaluated as to whether the state should
take ownership. In that regard, what rate of return should the
state be looking at, as a state, not as a private entity? He
asked whether there has been consideration of that issue yet.
MR. GARNER said not yet. It is an important question, however,
because states get involved in these kinds of projects for lots
of strategic reasons other than necessarily to make a high rate
of return for their own income purposes.
Number 22.26
REPRESENTATIVE FATE referred to Mr. Garner's mention of the
state's obligation to regulate the pipeline. He asked Mr. Garner
whether he anticipates looking in depth at what effect any
federal regulation may have upon those state regulations, and
whether that may influence it to the extent, perhaps, that it
will be impossible for the state to either regulate it or enter
into any financial agreement.
MR. GARNER answered:
I think only indirectly, sir. I think that that pretty
much exceeds what we're trying to do. I think we're
going to focus more on ... the things we know the state
will have to regulate. And some of these areas, I just
think it's probably going to exceed the scope of this
project.
MR. GARNER suggested that others could comment on that better.
CHAIRMAN TORGERSON informed Representative Fate that the issue
likely would be touched upon at the next day's discussions with
FERC, Bob Loeffler, the Department of Law, and [Legislative Legal
Services] personnel.
Number 24.03
COMMISSIONER CONDON noted that Chairman Torgerson had provided
him a list of topics to cover; he read item 2, which stated
[original punctuation and capitalization provided]:
Representatives of the LNG Sponsor Group testified that
the Port Authority concept provides little, if any,
economic benefit to its project. [The Alaska Gasline]
Port Authority has stated that its structure is
available to the producers and it can provide
significant economic benefits to a project. What is
your Department's current view? Additionally, the Port
Authority's route would cross lands outside the
participating municipalities' borders. What is your
view of the Port Authority's jurisdiction outside their
respective municipalities' borders?
COMMISSIONER CONDON told members:
We're not ready to answer either of those questions. I
can tell you that we are looking at ... a structure
like the Port Authority as one of the models that we'll
be analyzing to see whether it makes sense. And so we
will have a view on that issue, and I simply haven't
turned my attention to the question of whether or not
the Port Authority can construct a project that's
partly outside the physical boundaries of the member
municipalities.
CHAIRMAN TORGERSON informed members that he had written most of
the testifiers a letter, posing questions. He noted that
Commissioner Condon would be before the committee again the
following day to answer questions relating to taxes and other
issues. Recalling testimony that "they" would be tax-exempt
outside their jurisdictions, outside the City of Fairbanks, he
commented, "I don't see where they would be, but that's what I
was hoping you would have an answer for. But that's a difficult
question apparently."
COMMISSIONER CONDON replied that he didn't know whether it was
difficult or not. He apologized for not addressing it.
Number 26.26
REPRESENTATIVE DAVIES referred to Mr. Garner's testimony and
commented that the sale of Elk Hills and [Petrie Parkman's] role
in Saudi Arabia both "move in the direction of privatization."
He asked Mr. Garner, "Would you characterize your firm as being
biased in that direction of privatization, or are you ... going
to take a look at this from a fairly evenhanded point of view?"
MR. GARNER answered:
Definitely evenhanded; that's what our firm is ...
known as. In fact, some people would say we're too
evenhanded. ... We are not in the pockets of anyone.
We just [are] presented projects and look at them and
give people the answer, whether they want to hear that
answer or not. In those particular projects, that was
just the nature of the assignments. There's nothing to
be drawn from there.
And in fact, interestingly enough, I remember sitting
in Riyadh, Saudi Arabia, literally a year ago this
week, debating some of the same issues [in] a very
generic sense [that] I think you will be debating in
the legislature next year about the proper role of
governments in these kinds of projects. And so, ...
even Saudi Arabia I wouldn't necessarily characterize
as a privatization. It's more of a situation where the
kingdom legitimately is trying to do the best thing for
its country to increase employment, to ... increase
revenues available to the country, and exploit a
valuable resource in the kingdom in a proper manner.
CHAIR TORGERSON surmised that the commissioner has made available
to Mr. Garner the past reports and studies done on this; he said
this isn't the first time [the legislature] has looked at this.
MR. GARNER responded in the affirmative.
CHAIR TORGERSON added that he isn't sure what has changed from
the last time, other than the will to look at it again. He asked
whether there were further questions; none were offered.
CHAIR TORGERSON announced an at-ease at 2:15 p.m. He called the
meeting back to order at 2:31 p.m.
Alaska Oil & Gas Conservation Commission
MS. CAMMY OECHSLI TAYLOR, Commissioner, Alaska Oil & Gas
Conservation Commission, Department of Administration, came
forward to give a PowerPoint presentation in response to written
questions posed to her earlier by Chairman Torgerson. [The first
six minutes of Ms. Taylor's testimony were not recorded on the
tape. The questions and the printed versions of the PowerPoint
slides are available in committee packets, and text from the
presentation is provided here; original punctuation and
capitalization are provided, but formatting may be changed].
[The first slide showed a map of the Alaska North Slope.]
Outline of Testimony [slide 2]
Overview of AOGCC Role
Conservation Orders Affecting North Slope Gas Sales
Evaluation Process for Major Gas Sales
Overview of Contractor Scoping Study
Objectives
Recommendations
Alaska Oil and Gas Conservation Commission [slide 3]
(AOGCC)
Independent, quasi-judicial agency
Established under the Alaska Oil and Gas Conservation
Act (AS 31).
Regulatory authority - outlined in Title 10, Chapter 25
of the Alaska Administrative Code
Mission
Protect the public interest in oil and gas resources.
The Oil and Gas Conservation Act requires all oil and
gas drilling, production and measuring operations to be
conducted in a manner that prevents physical waste of
the resource, promotes greater ultimate recovery and
affords all owners of oil and gas rights an equal
opportunity to recover their fair share of the
resource.
AOGCC Function [slides 4 and 5]
PREVENT PHYSICAL WASTE OF THE RESOURCE
Technical evaluation of proposals for major gas sales,
enhanced oil recovery, and gas cap liquids recovery.
Evaluate drilling programs to ensure proper well
design, construction and well control equipment.
Inspect wells and drilling projects to verify
compliance with approved regulations, procedures and
safety requirements for drilling and production
practices.
PROTECT CORRELATIVE RIGHTS
Provide all owners of oil and gas rights the
opportunity to recover their fair share of the resource
through well spacing provisions, permit review, and
pooling authority.
ADJUDICATE DISPUTES BETWEEN OWNERS
Provide a public forum to resolve disputes between
owners.
ENSURE GREATER ULTIMATE RECOVERY
Analyze production data, including reservoir pressure,
gas-oil ratios, water cut, etc., to ensure these
variables fall within the accepted parameters necessary
to provide for greater ultimate recovery.
Review and approve development proposals, including
plans for enhanced oil recovery operations.
INDEPENDENTLY ASSESS OIL AND GAS DEVELOPMENT
Independently audit/verify that oil and gas exploration
& development proposals are in compliance with the
purposes and intent of Title 31.
PROTECT ALASKA'S UNDERGROUND SOURCES OF DRINKING WATER
Provide engineering and geological review of all
activities that affect potential sources of drinking
water.
AOGCC PRIMARY SERVICES [slide 6]
Regulate, monitor and inspect all subsurface activities
directly related to oil and gas exploration and
production including the design and integrity of wells,
well control procedures and equipment, reservoir
management plans and proposed underground injection
programs.
Issue pooling rules and conservation orders.
Approve and monitor plans for reservoir
development and enhanced oil recovery.
Approve permits for initial drilling, re-drill, sidetrack, and remedial well operations. This includes the evalua
cementing and well completion operations.
Inspect drill rigs and wells to [ensure]
compliance with AOGCC regulations.
Witness safety valve, mechanical integrity, and blowout preventer tests.
Witness meter-proving, calibration, and oil
quality tests.
Enforce well spacing rules, monitor production rates, injection well pattern, gas/oil/water ratios, and pressure
Monitor and evaluate gas flaring.
Collect and maintain all oil and gas production records.
Collect and maintain all well history files and well log records.
Administer Alaska's Underground Injection Control
(UIC) program and the annular waste disposal
program.
Powers and Duties of Commission
Related to Major Gas Sales [slide 7]
Investigate to determine whether or not waste exists or
is imminent.
Require plans of reservoir development and operation in
order to prevent waste, [ensure] a greater ultimate
recovery of oil and gas, and protect correlative
rights.
Regulate for conservation purposes the quantity and
rate of the production of oil and gas.
See AS 31.05.030.
[Tape recording begins here]
MS. TAYLOR discussed the following slide:
Waste [slide 8]
In addition to its ordinary meaning includes
The inefficient, excessive, or improper use of, or
unnecessary dissipation of reservoir energy;
Operating or producing in a way that reduces the amount of oil or gas recovered under operations conducted in accor
See AS 31.05.170(14).
MS. TAYLOR informed listeners that gas currently is reinjected
for pressure maintenance in Prudhoe Bay. If gas is sold instead
of being reinjected, the state needs to know whether the loss of
reservoir energy will result in reduced oil recovery. It is also
important to know what alternatives may be available that could
mitigate the loss of that reservoir energy.
MS. TAYLOR turned attention to the next slide, which read:
Applicable Conservation Orders [slide 9]
Pool Rules for the Prudhoe Oil Pool - Conservation
Order 341C Consolidated Pool Rules for Prudhoe Oil Pool
Rule 9 Pool Maximum Gas and Oil Offtake Rates
Maximum 2.7 billion standard cubic feet per day of
gas offtake (BSCFD)
Contemplated a 2 BCFD pipeline sales rate
(salable product)
Gas offtake from PBU has always been well
below this set limit
Rule 9 written in 1977.
Rule 12 Prudhoe Bay Miscible Gas Project
Operator to maintain the reservoir pressure at 250
psi above the minimum miscibility pressure.
MS. TAYLOR explained that one specific question asked [by
Chairman Torgerson] related to the applicable conservation orders
that currently exist. In 1994, she reported, the commission
undertook a consolidation of the numerous conservation orders
that had been written with respect to Prudhoe Bay; amended twice
since then, it is referred to as Conservation Order 341C. Two
rules within that conservation order specifically address the
impact of gas offtake from Prudhoe Bay. As noted above, [rule 9]
is the pool maximum gas offtake rate, set at 2.7 billion standard
cubic feet per day of gas offtake; written in 1977, it
contemplated a 2 billion cubic feet (BCF) [a day] pipeline sales
rate. The other, rule 12, is sometimes referred to by AOGCC
staff as the "pressure decline speed limit"; it specifically
requires the operator to maintain the reservoir pressure at 250
psi [pounds per square inch] above the minimum miscibility
pressure.
MS. TAYLOR reported that separate and aside from gas sales, the
operator is currently involved in a pressure studies initiative
and has begun an initial information exchange with the commission
on its plans.
MS. TAYLOR turned attention to the following slide:
Current Status [slide 10]
Fundamental assumptions upon which rule 9 was
established are not valid.
PBU Gas Offtake rules must be based upon
Current knowledge
Sound reservoir management
PBU Operators have stated to AOGCC that gas sales may
have a detrimental effect on oil recovery.
The AOGCC has not yet been provided with current
technical information regarding Major Gas Sales
MS. TAYLOR told members that the commission believes it is
important to recognize that rule 9 was written on pre-1977
information. The perception of that reservoir is significantly
different from how it was perceived when [rule 9] was created.
The AOGCC believes a gas offtake rule must be based on current
knowledge and sound reservoir management; however, the timing for
a hearing to revisit the offtake rule depends on acquiring
relevant data or an application from the operator.
MS. TAYLOR noted that the operators have consistently stated to
the AOGCC, over the years, that they would expect early gas sales
to have a detrimental effect on oil recovery. Currently, the
AOGCC hasn't been provided with any technical information
regarding major gas sales or an application that specifically
addresses timing or volumes. The AOGCC anticipates a hearing
with a BP reservoir group, however, within the next two to three
weeks, for a more detailed discussion on the types of information
that the AOGCC expects to receive in order to evaluate a
proposal; it is expected that a schedule will be set out at that
meeting for when the AOGCC can anticipate receiving the
information.
MS. TAYLOR indicated AOGCC staff had asked her to relate the
following: in the context of reservoir performance being so
significantly different from that in the late 1970s, the
incremental recovery from Prudhoe Bay of the 3.5 [billion]
barrels of recoverable oil is the largest addition to reserves
since Prudhoe Bay was discovered. The second largest was
Kuparuk. The 3.5 billion barrels is a significant amount.
MS. TAYLOR turned attention to the following slide:
AOGCC Gas Sales Evaluation Process [slide 11]
Scoping Study
Technical evaluation
MS. TAYLOR explained that the AOGCC, in preparation for what will
subsequently be a major gas sale, has prepared a two-pronged
process. She addressed the next slide:
Gas Sales Scoping Study [slide 12]
Consultant Review
Blaskovich Services, Inc. June 2001
Objectives
[Identify] conservation issues associated with gas
sales from the Prudhoe Oil Pool.
Identify technical issues affecting ultimate hydrocarbon recovery
Consider multiple complex interactive recovery mechanism
Provide alternatives for AOGCC technical
evaluation
MS. TAYLOR emphasized that the scoping study was completed in
June 2001 by Blaskovich Services, Inc. The objectives of that
review are listed above, with an additional objective of
providing the AOGCC with a range of costs [for the alternatives].
MS. TAYLOR brought attention to the following slide, specifying
that it relates to the conclusions from Mr. Blaskovich's report:
Conclusion - Consultant Review [slide 13]
Oil Recovery Impact
Oil and Condensate Recovery likely to decrease under
Gas Sales
Unless delayed until later into field
However, if carefully planned and managed Gas sales
Can extend field life
Potentially increase total Hydrocarbon Recovery
Maximum Recovery vs. Owner Economics
Industry Precedents
Few industry precedents for early gas withdrawal
Field management difficult, but does not mean this
endeavor will be unsuccessful
Options
Independent Studies
Critique and peer Review of owner studies
Work directly on Owner project teams
MS. TAYLOR, addressing oil recovery impacts discussed in the
slide, told members the AOGCC's mission and challenge is to
evaluate how [gas sales] are managed and to look at the
alternatives being proposed for maintaining reservoir pressure.
She noted that the report pointed out a natural tension between
the state's desire to maximize hydrocarbon recovery and the
owners' economics. Furthermore, Mr. Blaskovich had reviewed
literature available in the public domain, as well as industry
precedents, and found few industry precedents for early gas
withdrawal before the end of field life in oil recovery.
Although field management might be difficult with these
proposals, however, he believes the endeavor could be successful.
MS. TAYLOR informed members that Mr. Blaskovich's report also
reviewed a number of options, broken down into general
categories; they included doing completely independent studies,
doing a critique and peer review of owner studies, and working
directly on the owner project teams.
MS. TAYLOR presented the next slide:
Recommended Approach [slide 14]
Independent Analysis and Critique
Smaller, Mechanistic Models to study processes
Focus on Technical issues of greatest impact on decisions
Do a credible job
Concurrent with Owner Studies (potentially ahead)
Use WIO data whenever possible
Rely on basic data, avoid debates about
detailed models
Serious critique of WIO data & results
Credibility high if right questions are asked (based upon work above)
Avoid endless debate about who has the best model
This is a Combination of Options 1C and 3 from
Blaskovich Study
MS. TAYLOR explained that the ultimate recommendation made by Mr.
Blaskovich, in conjunction with his discussions with [the
AOGCC's] technical staff, is a hybrid between two extremes:
having the state do a full field model that essentially
duplicates companies' efforts, and just accepting the information
provided by the operators to the commission. She deferred to
Commissioner Heusser to provide a description of the technical
aspects of that recommendation.
MS. JULIE M. HEUSSER, Commissioner, Alaska Oil & Gas Conservation
Commission, Department of Administration, reiterated that the
current approach is two-pronged, a hybrid that avoids either
extreme. The AOGCC's current thinking is that the type of
evaluation that would provide the most value to the AOGCC and the
state would be a combination of an independent analysis plus a
critique of the working-interest owner data and results.
MS. HEUSSER explained that one clear message in Mr. Blaskovich's
scoping study is that recovery from the Prudhoe Bay field is
complex, with a variety of connected, interdependent mechanisms
in a delicate balance; withdrawing gas in the form of major gas
sales would interrupt that balance. The AOGCC therefore plans to
use smaller, mechanistic models to understand how fluids move
through the reservoir; this will allow the AOGCC to focus on
technical issues that will have the greatest impact on the
decisions. "We won't look at everything, but we'll look at the
important ones," she remarked. She reiterated that there has
been little industry experience with major gas sales from an oil
reservoir that has not finished producing oil; therefore, there
is no place that the AOGCC can go to look at actual experience.
MS. HEUSSER mentioned the timing of the gas sale; the question of
what the pressure maintenance needs are; and the question of what
the ramp-up rates and timing will be. She also mentioned optic
points, commenting that right now it appears that most of the gas
could come from what used to be called the oil-rim wells. Should
there be a need for an increased gas sales rate, she asked, what
is the effect of taking gas off of the gas cap? The AOGCC also
wants to look at the effect of gas withdrawal from the reservoir
on the management of the existing "water flood enhanced oil
recovery projects."
MS. HEUSSER told members the AOGCC's goal is to do a credible
job, which requires evaluating not only the gas cap, but also the
reservoir and the gravity drainage areas, as well as areas
involved in water flood and EOR [enhanced oil recovery], which
all interact with each other: when fluids are removed from one
portion, fluids move in from another portion, and there may be a
loss in oil recovery, or condensate, associated with moving
fluids around.
MS. HEUSSER informed the committee that the ideal is to perform
AOGCC's evaluation concurrently with the owners' studies;
however, the AOGCC understands that the owners already have
started their reservoir studies. While the AOGCC may be a little
behind, it is believed the AOGCC can proceed at a pace that will
allow it to not impede any gas-sales decisions in the near
future. Ideally, the AOGCC also could use the working-interest
owner data wherever possible; this is necessary to independently
validate the data, to ensure that the results are believable.
The AOGCC wants to know what data is going in, and wants to make
sure the data is representative of what the commissioners believe
the reservoir to be; that way, the commission will have more
confidence in the results.
MS. HEUSSER noted that the AOGCC also has proposed to do a
critique of the data and the results, which is, effectively, a
peer review. "The credibility of our evaluation will be high if
we study and ask the right questions," she told listeners. "That
will allow us to feel comfortable that what is being proposed by
the working-interest owners really is in the best interest of the
state, to ensure greater ultimate hydrocarbon recovery."
MS. HEUSSER turned attention to the next slide:
Timing Issues
AOGCC approvals dependent upon:
Access to Operator information.
Availability of agency Staff.
Access to specialized expert(s) training in and familiar with large scale compositional reservoir modeling techn
MS. HEUSSER told members the AOGCC has no fixed answer to
Chairman Torgerson's question regarding timing. [That written
question asked the presenters to address the length of time the
AOGCC anticipates it will take to approve any action necessary
for the development and production of Prudhoe Bay gas for sale.]
Instead, she offered the following:
Basically, with our current recommended approach, we
believe that it's going to take about a year ... to do
the reservoir evaluation of the effects of major gas
sales. The actual approval process is pretty
straightforward. Once we receive a package and our
evaluation is done, we put out a public notice, and
with ... 30 days to respond, will hold a hearing, and
then we have 30 days to issue a decision after the
hearing. So that's basically how the process works.
Now, there are some potential slow-downs to this, and
that is access to operator information. As
Commissioner Taylor mentioned, we have a meeting that
is currently scheduled for sometime in the next two to
three weeks to meet with representatives of the
working-interest owners and to provide them with
additional clarification on our information requests.
Also, it's going to be dependent upon availability of
agency staff. As most of you are aware, we have had a
very difficult time recruiting and filling our
technical staff positions. We were very fortunate to
obtain legislative approval for salary increases. We
have filled one of our outstanding positions, but we
are in the process of accepting applications for a
second position. However, ... our staffing levels
never really reflected the need to do the major gas
sales reservoir evaluation at this time. We've been
told that it was always five years down the road or
seven years down the road. So there may be some
additional staffing needs that we'll need to consider.
Now, whether that be permanent employees or whether or
not we use contractors, that would be something that we
would need to evaluate [to] make sure that we're doing
the right thing.
Also, we need to have access to specialized experts
that are both trained in and familiar with large-scale
compositional reservoir modeling techniques. This is
basically because in order for us to be effective in
our critique of the working-interest owner data and
results, these are the type of models that they're
using; they're very sophisticated, and ... they're
fairly new within the last ten-fifteen years or so.
And it takes ... specialized experience in order to
evaluate their results.
MS. TAYLOR added that one question asked [by Chairman Torgerson]
related to the status of any discussion with the Prudhoe Bay
lessees regarding what orders or permits they will need [from the
AOGCC] in order to develop and produce gas for sale [from the
Prudhoe Bay reservoir], including the volume of gas available for
sale at the startup of a gas pipeline and the commencement of
full blowdown of the gas cap. She noted that the information the
AOGCC has received in discussions with the operators has been
general, consisting of a general outline of when they expect to
be reviewing certain things, but without any specific data.
TAPE 01-9, SIDE B
MS. TAYLOR expressed hope that following the meeting scheduled in
the next two to three weeks, the AOGCC will have a better layout
of the "roadmap" ahead.
MS. TAYLOR referred to the last written question asked of the
presenters, which requested an explanation of how the AOGCC
intends to fund, on a program receipt fee basis, the study for
which the AOGCC previously had requested $500,000 in general
funds, as well as an explanation of the scope of the study. She
told listeners the scope of the study, as Commissioner Heusser
had described, is somewhat dependent on what the actual
parameters will be once the operators come to the AOGCC with a
specific proposal and timing. It will be within the model of the
two-pronged hybrid described by Commissioner Heusser.
MS. TAYLOR reported that the AOGCC funding request that went
through the legislature last year was made part of the overall
gas line package. It is the AOGCC's understanding now that the
Department of Natural Resources (DNR) will enter into an
agreement with the producers, and will collect from them through
its statutory designated program receipt authority; through an
RSA [reimbursable services agreement], that will go to the AOGCC.
Number 01.70
MS. TAYLOR offered to answer questions and invited members to
come to the AOGCC's offices for any further information.
CHAIRMAN TORGERSON asked whether the AOGCC needs an application
from the producers before going forward.
MS. TAYLOR answered that with respect to revisiting rule 9, which
currently sets a gas limit for offtake, for a number of years the
commission has felt that rule is no longer current. The
commission has not moved to reevaluate it, however, until such
time as the AOGCC either has an application or more specific
information about the reservoir and about proposed plans, in
order to "make a better-informed rule about what amount and at
what time gas could be taken from the reservoir." She added that
it would also depend upon what alternatives the operators had for
reservoir energy replacement.
CHAIRMAN TORGERSON referred to timing issues and asked whether
those depend on whether the AOGCC gets the information from the
operators.
MS. TAYLOR asked whether that is with respect to the actual
technical review.
CHAIRMAN TORGERSON answered in the affirmative.
MS. TAYLOR replied that the recommendation for the kind of hybrid
review described by Commissioner Heusser is dependent upon the
information that would be provided by the operators.
CHAIRMAN TORGERSON asked whether the AOGCC needs that to amend
rule 9. He specified, "Do you need Commissioner Heusser's report
... for the data you need to make a decision on amending rule 9?"
MS. TAYLOR replied, "To do it intelligently. Otherwise, I think
that you could just delete the rule and wait until someone came
with a proposal and further information."
CHAIRMAN TORGERSON asked, "You said it'd take a year to do this -
a year after what?"
MS. TAYLOR answered, "A year after we receive some detailed
information from the working-interest owners."
CHAIRMAN TORGERSON offered his understanding that the AOGCC
theoretically would get this information from the operators, and
then would make sure it is correct somehow, by hiring the right
people, for example.
MS. TAYLOR responded in the affirmative.
CHAIRMAN TORGERSON suggested that is assuming the AOGCC doesn't
need any additional data.
MS. TAYLOR replied, "That is our best understanding at the
moment. The more information that we're provided, perhaps that
timeframe would be shorter. But based on the hybrid approach
that we'd like to take, we're estimating a year."
CHAIRMAN TORGERSON commented that he finds it a little odd that
the producers aren't addressing the AOGCC, in meetings upfront,
regarding whether rule 9 will even be amended. He asked whether
this is an assumption on the part of the producers that they can
pump the 6 billion [cubic] feet a day out of the field, and that
the AOGCC will approve that. He requested Ms. Taylor's opinion,
then said she didn't have to answer that; he noted that the
producers aren't sharing information on many aspects.
CHAIRMAN TORGERSON then asked whether the economics to the state
treasury are driving the decision. Noting that the economics
involve the loss of oil versus the increase in gas, he asked,
"How do you weigh that?"
MS. TAYLOR replied:
Actually, Title 31 doesn't provide us with any
opportunity to balance the economics of it. Title 31
directly addresses hydrocarbon recovery. And so that
comparison or that evaluation is left to other
departments and the legislature. Our evaluation is to
look ... at avoiding waste and promoting that ultimate
recovery, within reason and, of course, to the extent
that we're not doing it blindly of what the costs are.
CHAIRMAN TORGERSON asked whether a 10 percent loss of oil
production is something the AOGCC would or would not approve. He
also asked whether that meets the AOGCC's criterion of maximum
hydrocarbon recovery.
MS. TAYLOR responded:
I don't think there's a magic answer. ... One of the
things that I think people find most surprising is that
when you have a pool of oil in the ground and someone
is developing that, they don't recover 100 percent of
that. And perhaps Ms. Heusser can address ... the
specifics of what's normally expected and where this
fits in. So I think there's an element of
reasonableness and an element of sound engineering
principles.
MS. HEUSSER added:
This is a difficult question to answer, about what's a
reasonable amount of oil to give up in exchange for ...
major gas sales at Prudhoe Bay. Previous public
testimony by both operators and working-interest owners
[has] suggested that the oil loss is at least ... 500
million barrels. ... That's a chunk of oil. What
percentage ... is it of the original oil in place?
Well, in the grand scheme of things ... it is less than
10 percent. The 500 million barrels of potential lost
oil and condensate, that is a low-end number that we
have heard testimony on before.
Is a 10 percent loss reasonable? 1 percent? [10]
percent of ... the current recoverable reserves at
Prudhoe Bay is ... about 1.4 billion barrels; it's a
lot. So 5 percent is 700 million barrels. So that
just kind of ... gives you some points of reference.
We don't know at this time ... what a reasonable figure
is for loss of oil and condensate reserves. There is
oil in the gas cap, what's called relic oil. When you
start taking gas off, you get fluids moving around, so
you lose oil because you've moved them further away
from where they were originally deposited. ... That
will be a point of discussion: what is a reasonable
trade?
CHAIRMAN TORGERSON, on another subject, said it sounded from Ms.
Taylor's testimony as though perhaps another agency can override
the AOGCC's decisions. He suggested the legislature is one such
entity, then asked whether anybody can veto the AOGCC's decision
and OK a gas sale.
MS. TAYLOR answered, "I guess ... our position right now would be
that without authorization from the commission, they would be at
least in violation of Title 31."
CHAIRMAN TORGERSON asked whether DNR has a say in what limits of
hydrocarbons are recoverable, for example, or whether the
governor can call and say to make it work.
MS. TAYLOR replied:
There is no one out there who could call us and tell
us, "Make it work." DNR can certainly appear as a
party in front of the commission and provide testimony.
... I'd also like to add that part of the evaluation
that is part of this difficult question about what's
lost and what's not is also a challenge for the
commission to evaluate what other alternatives might be
out there with respect to mitigating that loss of oil
recovery when the gas is taken for sale. And that's
part of this process of evaluation, and it's part of -
I'm fairly certain - what the companies are also
looking at.
CHAIRMAN TORGERSON asked how much information is confidential.
MS. TAYLOR answered:
The commission's confidentiality provisions generally,
with respect to subsurface information on particular
wells, is governed by, generally, a 24-month
confidentiality. So the subsurface information that
relates to a particular well, 24 months after ...
they've completed the well, is available publicly.
There is some technical information that, if provided
voluntarily under Title 31, can be held confidential.
The other general aspect is under the general statutory
trade secret requirements. And some of that
information, they have to meet a certain standard, but
if they meet that, that can be maintained
confidentially.
REPRESENTATIVE DAVIES referred to the Blaskovich study,
suggesting it said two apparently contradictory things: oil
recovery is likely to decrease, and if it is carefully planned,
it could extend the life and increase recovery. He said it
sounds as if Mr. Blaskovich's assumption was that it wouldn't be
carefully planned. He asked, "In reading that study, ... do you
agree that there are things that we could do that, with carefully
planned gas recovery, would actually enhance oil recovery? And
what are those things?"
MS. HEUSSER replied:
One of the provisions of Conservation Order 341C is
that the working-interest owners continue to evaluate
pressure maintenance options. One of their recent
proposals to us has been called the pressure support
initiative, which is basically gas-cap water injection.
That is one way that pressure decline can be mitigated.
There [is] also optimizing your field production rates.
Where you physically take your reservoir fluids from is
another means that can be used to manage reservoir
pressure decline or reservoir energy decline. There
are a number of things that could be done.
REPRESENTATIVE DAVIES asked, "So do you ... fundamentally agree
with that statement that ... a carefully planned gas sale could
increase total hydrocarbon recovery?"
MS. HEUSSER answered:
There's a timing question. So, in essence, that is
correct. The timing of the gas sale, if it's ...
somewhere off in the future, gives you more opportunity
to recover your hydrocarbons and to cycle gas and
recover additional hydrocarbons from your gas cap. So
there's the timing issue, carefully planned.
And there's the pressure or reservoir energy mitigation
issues that can help maintain the reservoir pressure,
maintain the reservoir energy, and allow you to recover
-- I'm not saying it's necessarily more oil, but ...
you would lose less.
REPRESENTATIVE DAVIES asked whether 500 million is the right
order of magnitude, and whether that is for Prudhoe Bay or the
entire North Slope.
MS. HEUSSER said that number is just for Prudhoe Bay. She
deferred to Ms. Taylor, noting that a range has been quoted.
MS. TAYLOR responded, "I think the range we've heard historically
has been 400 to 500 [million], but ... in the context that we
have heard, it has been very loosely used, with no identifiable
date at which that gas would begin to be taken off the
reservoir."
REPRESENTATIVE DAVIES asked whether that is for a year's
recovery.
MS. TAYLOR answered, "Based on the current production rate, yes."
REPRESENTATIVE OGAN inquired about the total reserves in Prudhoe
Bay.
MS. TAYLOR replied that Prudhoe Bay's total current estimated
recoverable oil reserves are "about 13 billion."
REPRESENTATIVE OGAN said that differs from what BP just put out
in its statistical review of U.S. energy in 2001, which was 4.9
billion barrels.
MS. HEUSSER asked whether this is comparing apples to apples,
however. In response to a further question, she added,
"Estimated recoverable oil reserves are ... in the neighborhood
of 13 billion; there was, like, 23 billion oil in place, and they
expect to recover something on the order of 13 billion of that."
REPRESENTATIVE OGAN asked whether the 500 million loss touted in
the past was based on a draw of 2 BCF. He asked whether the fact
that now people are talking about 4 [BCF] affects it
significantly.
MS. HEUSSER replied:
The 500-million barrel potential loss came with no
qualifiers, except that rule 9 does allow for gas sales
of 2 BCF per day, which equates to something like 2.7
BCF per day offtake. So ... if you're comparing apples
to apples, we believe that's the correct context.
REPRESENTATIVE OGAN said he isn't a petroleum engineer, but it
seems that if twice as much gas is drawn down as that rule
allows, there will be more of a loss, faster.
MS. HEUSSER responded:
When you take out twice as much gas, your pressure
decline does accelerate. And oil recovery is a
function of pressure decline. So is it linear? ... I
don't know the answer to that.
And I just had a note from Mark Myers: what you're
seeing in your report right there is BP is quoting
remaining reserves. And what I quoted you was total
reserves. So ... they are pretty much saying the same
thing.
REPRESENTATIVE OGAN said he would be curious to see how the total
loss would "pencil out" with a 4 BCF draw.
MS. HEUSSER replied, "That is one of the things that we will be
taking a look at, the effect of gas offtake or gas sales rate on
the various recoveries."
SENATOR KELLY asked how much water will be able to replace the
gas that might be removed. He also asked whether that is an
unknown technology.
MS. HEUSSER answered that it isn't an unknown technology. She
acknowledged that she would have to "talk around" this question,
then stated:
The pressure support initiative will put gas in the gas
cap area, and that will be a means to help the
reservoir pressure decline - level off. However, in
the water flood areas where we're currently injecting
water, our voidage, our oil and water produced from
those areas, is more than the water and gas being
injected into those areas. And ... the very simple
reason behind that is reservoir management: when you
overinject, you move fluids from one area to another
and you have the potential to lose recovery. So it's
not so simple as ... "you take one barrel of fluid out,
or equivalent gas, and put one barrel of water in."
It's never that easy. It's a function of where you do
it and how you manage your reservoir.
SENATOR KELLY stated his understanding, then, that water is never
going to be able to replace gas, although in some circumstances
it could be used.
MS. HEUSSER replied, "I hate to use the word 'never.'"
SENATOR KELLY asked whether there are other reasons why water
wouldn't be used, such as environmental reasons.
MS. HEUSSER answered:
I am not really the person to address that. I am not
familiar with any environmental reasons that would
preclude [it], except ... there may be some limit on
the amount of seawater that can be taken from Prudhoe
Bay and be available for gas-cap water injection. I
understand their plans are to use seawater, as opposed
to produced water.
MS. TAYLOR added:
I think that with respect to the areas in which we
regulate the underground injection of water for
purposes of enhanced recovery, there aren't any as long
as the proposal is done according to our regulatory
criteria. And I'm not aware of there being any
difficulties in the Prudhoe area ... mechanically, with
respect to environmental regulations. And that deals
with the potential sources of drinking water. And
we're not aware of any.
REPRESENTATIVE DAVIES returned to the question of timing. He
asked when the AOGCC can begin the study. He acknowledged the
need to have data and a more specific idea of what the
development plan will be before a study will be optimal. He
asked, however, whether there are other things the AOGCC can be
doing now, following on the scoping study, to prepare to move
ahead and to jump-start the process in order to keep the time to
a year.
MS. TAYLOR replied:
Absent information - any sort of technical data - one
of the reasons for the recommendation that we actually
use the technical data provided by the operator - that
they use to build their models - was so that you'd
[have] some consistency.
A lot of technical information is provided by the
operator to the state. The time it would take to put
that information in a useful fashion, to do that same
exercise, would be fairly overwhelming at this point.
Our hope is to actually move forward on a decision
about how to proceed with this evaluation so that we
can actually begin the procurement process in terms of
getting an RFP [request for proposals] out there and
finding out more specifically what it would cost and
who's out there available to do this kind of work, and
hopefully that can be lined up ahead of time. We'll
have a better indication in the next two to three weeks
when we actually meet with the reservoir group at BP to
hear more specifically about what their timing schedule
looks like.
MS. HEUSSER added, "Using the working-interest owner data and
quality checking that basically eliminates disagreements. It ...
streamlines the whole process."
REPRESENTATIVE DAVIES asked, "Can you request that data in
advance of an application?"
MS. HEUSSER answered yes.
REPRESENTATIVE DAVIES further asked, "Can you anticipate the sort
of data you're going to need and then just simply request it?"
MS. HEUSSER replied:
Yes. In fact, we have done that. We have written to
the operator and specifically outlined the type of
information that we're looking for, and requested from
them confirmation on the timing that we could expect to
have that information. And that is what's prompting
this meeting in approximately two to three weeks.
REPRESENTATIVE FATE commented that in several hearings it was
stated, by the owners, that 4 BCF a day would have little or no
effect on oil production. He expressed concern about the timing
issue, saying [legislators] have been under the illusion "that
they've been doing a study" and that there will be at least 4 BCF
a day, or even 6 BCF a day. He stated:
Here we are now, backing up, talking about rule 9 and
what has to be done ... to confirm either whether or
not 2.7 billion a day is going to decrease or 4 billion
is going to decrease the production of the remaining
oil in Prudhoe Bay. And to me, Mr. Chairman, ... it's
backing up the cart here, when we need to go forward
with it. And we've been discussing 4 billion.
Apparently, it's been an illusion. Is that correct?
Is this an illusion?
MS. TAYLOR answered:
We're not privy to the information about the 4 BCF a
day. Are you hearing that the 4 BCF are to be coming
from the Prudhoe field, or are they coming from other
places as well?
REPRESENTATIVE FATE responded:
We understand the Prudhoe field, because that's where
most of the gas will be coming from. And we've been
told this. So we just took it - or at least I
certainly took it - to mean that there had been,
certainly, studies on whether or not 4 BCF would in
fact diminish the production of the oil.
MS. TAYLOR replied:
I guess we would be hopeful, then, that if the studies
have already been done when we meet with them in two to
three weeks, we would anticipate receiving information
relatively quickly.
CHAIRMAN TORGERSON responded:
I don't know if they've really finished the studies,
but I do know that we've plugged different numbers in
for loss of oil in certain economic models that we've
been running ... on the production, and most of those
come from conversations with the producers ... or other
places that would show a loss.
CHAIRMAN TORGERSON added that he understands Representative
Fate's displeasure with finding out that there are a lot more
hoops to jump through to sell gas. He said there are certain
steps that it seems would be done first, and one is to get
approval to sell it before spending $100 million "to even see if
you want to do it." He indicated that is one reason he wanted to
hear from the AOGCC, to address concerns the committee has heard.
REPRESENTATIVE OGAN surmised that the AOGCC's decision could be
litigated and overruled by the courts.
MS. TAYLOR affirmed that, specifying that any decision made by
the commission can be appealed to the superior court.
CHAIRMAN TORGERSON thanked the presenters and said he would take
them up on the offer to visit the AOGCC. He asked that they call
his office after the upcoming meeting in order to provide a
briefing. He noted that the next scheduled meeting for this
committee will be in September, and he suggested it may be
worthwhile to address the AOGCC's upcoming meeting as part of
that agenda.
CHAIRMAN TORGERSON called an at-ease at 3:30 p.m. He called the
meeting back to order at 3:33 p.m.
Department of Law
MR. JACK GRIFFIN, Assistant Attorney General, Oil, Gas & Mining
Section, Civil Division (Anchorage), Department of Law, came
forward, noting that he is the head of the Oil, Gas & Mining
Section. He presented answers to the written questions posed to
him earlier by Chairman Torgerson. He suggested the questions
about overlifting were prompted at least in part by SCR 10; that
dealt with a proposal by an entity called Netricity, which had an
interesting idea for a gas development project on the North Slope
involving an Internet "server farm."
MR. GRIFFIN paraphrased the introduction to his written response,
which read [original punctuation and capitalization provided]:
INTRODUCTION AND GENERAL COMMENTS
What is overlifting and underlifting?
"Overlifting" and "underlifting" are terms used in
agreements among two or more parties with interests in
production that describe situations where one or more
of the parties has, in a given production period, taken
more or less production than that party's allocable
share. If a party takes more than its share, it has
overlifted its production; if less, it has underlifted.
Generally speaking, when one party overlifts its
production, one or more of the other parties will be
underlifting that is, receiving less than the share
of production to which it is entitled.
For an example let us assume two parties, A and B,
have equal production interests in a field, so that
each month each party is entitled to 50% of the
hydrocarbon stream sold or removed from the field. If
A incurs marketing or transportation problems in a
month, he may find at the end of that month that he
lifted only 45% of the field's production, while B has
lifted 55%. A has underlifted his production, while B
has overlifted his.
The parties with interests in production often
agree in advance to the terms and conditions that
govern the reconciliation that must occur in the event
of overlifting or underlifting by the parties. These
are sometimes called balancing agreements. Balancing
may occur in a number of different ways, but perhaps
the most common are by (1) adjusting the amount of
production each party is entitled to lift in subsequent
production periods, or (2) making cash payments.
In our example, balancing could occur by having A
take 55% of the next month's production while B takes
45%. Assuming the production for both months was
equal, A and B each would have received their 50% share
over the two-month period. Alternatively, B the
overlifter could simply pay A the cash value of the
extra 5% of production that it had received that month.
The causes of overlifts and underlifts may
include, but are not limited to: marketing problems of
one or more party; governmental action in the form of
legislation or regulation; disruption or absence of
facilities for accepting an owner's share of production
for some period of time; inability or refusal of a
purchaser to take delivery of an owner's share of
production for some period of time; unanticipated
cessation or decline or production; drainage; and
variations among parties as to information,
expectation, and risk aversion. See Williams and
Meyers, 11th ed., p. 78.
While overlifts and underlifts often occur because
of unforeseen circumstances or slight hiccups in day-
to-day operations, they can also be planned for and
expressly negotiated. For example, parties with
varying interests in production from several pools in a
field may use overlifts and underlifts, instead of cash
payments, to align their equity interests across the
field. That is essentially what happened at Prudhoe
Bay, among most of the working interest owners there,
following the BP-ARCO merger and Phillips' acquisition
of ARCO's Alaska assets.
What is the State's interest in production at
Prudhoe that might be overlifted or underlifted?
The State, of course, has an interest in
production from its North Slope leases. With respect
to gas, those leases give the State the right to a
royalty share of the gas that is "produced and saved
and sold or used off [the lease] ...." Gas that is
used for repressuring the reservoir, or for enhanced
oil recovery, is not subject to a royalty obligation.
At Prudhoe Bay, the State's royalty interest [under the
leases] is generally 12.5%.
MR. GRIFFIN presented the first question posed by Chairman
Torgerson and his own answer, which read:
I. OVERLIFTING
1) Are there any statutory provisions that are
relevant? If so, what are they and why?
There are no statutory provisions that
specifically address the State's ability to overlift
oil or gas. Consistent with the general powers granted
under the Alaska Land Act, AS 38.05, we believe the
Commissioner of Natural Resources has inherent
authority to negotiate an overlifting agreement with a
producer or group of producers where the Commissioner
concludes such an agreement furthers the best interests
of the State. Assuming the Commissioner intends to
commit the overlifted gas to a royalty in-kind (RIK)
sale, AS 38.06.055(a) becomes relevant, as it provides
that the RIK contract must be approved by the
legislature.
MR. GRIFFIN went over the underlifting and overlifting basics
again at a members' request. In response to a question by
Representative Davies regarding whether the state would attach
the royalties based on what should have been the right amount, he
said in most circumstances when the overlifts and underlifts are
"the little ... blips in production" [the state] doesn't pay
attention to that. If someone has a 30 percent share in
production, for example, the royalty will be based on that share,
rather than looking at slight overlifts or underlifts in a
particular month. However, if the parties have negotiated to
overlift or underlift for an extended period, the state would
probably look at that arrangement, ask how the royalty interest
should apply, "and then go talk to them about it." He said it
might go either way.
REPRESENTATIVE DAVIES noted that the state might have a different
interest in the different shares.
MR. GRIFFIN agreed, adding, "That's why we might look at it
differently." [Ends mid-speech because of tape change].
TAPE 01-10, SIDE A
MR. GRIFFIN concluded by saying a number of different factors
must be considered. Except for a negotiated underlift or
overlift, he reiterated, most of those little overlifts and
underlifts "we look the other way on."
CHAIRMAN TORGERSON asked whether the balancing agreement that
"was because of the merger between Phillips and ARCO" was
finalized.
MR. GRIFFIN replied that he would need to check to be certain,
but his understanding is that the overlifts and underlifts
necessary to accomplish the realignment among the major working-
interest owners has, in fact, ended.
CHAIRMAN TORGERSON said he was interested in the overall
agreement; he asked whether it was finalized and signed off on,
with the different provisions in it.
MR. GRIFFIN answered yes.
REPRESENTATIVE OGAN asked whether Chevron had been the "sticking
point" in that realignment, and whether that had been worked out.
MR. GRIFFIN remarked that perhaps he'd misunderstood Chairman
Torgerson's question. He then stated:
There isn't complete alignment at Prudhoe Bay. Right
now, my understanding is that not all of the ...
working-interest owners at Prudhoe Bay have aligned
their interests. The agreement I was thinking of was
the -- there is an agreement among some of the working-
interest owners to align their interests as much as
possible; that agreement has been signed. But the
alignment at Prudhoe Bay is not complete.
CHAIRMAN TORGERSON asked what that means [for the state].
MR. GRIFFIN replied:
What it means might depend on the particular question.
I think that in terms of how the three largest working-
interest owners at Prudhoe Bay look at things, in a
sense, they've been simplified. Now, the fact that
there hasn't been complete realignment means that the
... Prudhoe Bay Operating Agreement, in all of its
complexity, is still out there and still ... being
followed - at least that's my understanding.
CHAIRMAN TORGERSON asked, "You're not negotiating that or in on
the negotiations with the balancing agreement?"
MR. GRIFFIN said no.
CHAIRMAN TORGERSON asked who is handling that.
MR. GRIFFIN answered:
Right now, that is a commercial matter among the owners
at Prudhoe Bay. Once they have been able to negotiate
a complete alignment, they'll come to the Department of
Natural Resources and request permission for the cross-
assignment of leases to ... reflect the realignment,
and the department will consider that request on its
merits.
CHAIRMAN TORGERSON asked, "Is our 12.5 percent a party to that?"
MR. GRIFFIN replied, "We'll get our 12.5 percent no matter what
happens."
CHAIRMAN TORGERSON asked whether the state is a signer on the
agreement.
MR. GRIFFIN answered:
The state would not be a signer on the agreement
between the companies, but the Department of Natural
Resources has to approve any assignment of a lease
interest. So in that sense, it can't happen without
the Department of Natural Resources' blessing. My
understanding would be that the Department of Natural
Resources supports ... the companies' efforts to
realign the interests at Prudhoe Bay.
SENATOR KELLY asked whether, with the agreement not finalized,
everything could go back to "square one." He also asked whether
there is just one holdout that needs to be addressed.
MR. GRIFFIN replied:
My understanding of the arrangements that are in place
to date would be that we'd never go all the way back to
square one. I think there are actually two companies
... that have not agreed to a complete realignment of
their interests - I think Chevron and Texaco. ...
There may be arrangements with one or both of the
companies that I'm not aware of, but they certainly
haven't come to the Department of Natural Resources
with signed agreements reflecting the fact that ...
everyone has aligned their interests. But ... over 90
percent of the interests at Prudhoe Bay have been
realigned, and the fact that one or two ...
SENATOR KELLY interjected, asking whether that 90 percent is
"carved in stone."
MR. GRIFFIN answered:
The department has approved the cross-assignment of
lease interests ... for those working-interest owners
at Prudhoe Bay who have aligned their interests. So,
in that sense, it is ... carved in stone. It's not
carved in stone in the sense that they could always
come back to the Department of Natural Resources, I
suppose, and ask to do something different. But ... I
would doubt that very much.
CHAIRMAN TORGERSON returned attention to the presentation.
MR. GRIFFIN again paraphrased portions of the written response to
question 1 regarding overlifting [text provided previously].
CHAIRMAN TORGERSON surmised that basically the state could do
that with the permission of the producers.
MR. GRIFFIN said it would be a negotiation.
CHAIRMAN TORGERSON mentioned Netricity, which would take gas in
advance of having a pipeline; it totally would be overlifting by
the state, he suggested, because there wouldn't be any line at
all. Chairman Torgerson remarked that he isn't sure legislation
isn't needed. If, for example, the producers say the route is
not economical "or we get beat out by some of their other
projects around the world that they're working on," the state may
want to take its 12.5 percent royalty in advance. He also said
he wasn't sure it followed the examples laid out by Mr. Griffin.
MR. GRIFFIN pointed out that subsequent answers [to Chairman
Torgerson's written questions] would address that.
MR. GRIFFIN paraphrased question 2 and the response, which read:
2) Are there any lease provisions that are
relevant? If so, what are they and why?
The lease provisions that create the State's
royalty interest in gas and its right to take its
royalty gas in-kind are relevant, in the sense that
they describe the production interest that would be
"overlifted."
MR. GRIFFIN addressed the third question, which read, along with
the response:
3) Is there an explicit right in any of the
provisions? If not, is there an implied right?
There is no express or implied "right" under the
leases for the State to overlift gas produced from
Prudhoe Bay.
MR. GRIFFIN specified that there is no express or implied right
in the leases for the state to unilaterally decide that it wants
to take more than its royalty share of what is produced and
removed or sold from the lease.
MR. GRIFFIN turned attention to question 4, which read, along
with the response:
4) Has the Prudhoe Bay Unit Agreement or any
other agreement between the state and the producers
modified any of our rights?
Nothing in the Prudhoe Bay Unit Agreement or any
other agreement between the State and the producers has
created a right for the State to overlift its gas. If
anything, these agreements reinforce the conclusion
that the State has no "right" to unilaterally decide to
take a quantity of gas that exceeds its royalty share
of the gas stream that is currently being sold or used
outside of the Unit.
MR. GRIFFIN paraphrased question 5 and the response, which read:
5) Assuming that under the current agreements or
applicable law, there is a questionable right to take
royalty in-kind before a major gas sale, is there a
legislative fix that you could recommend?
The Department of Law cannot recommend a
legislative fix at this time. The State has not
decided that taking a large volume of gas in-kind
before a major gas sale is in the State's best
interests. Moreover, the producers have indicated a
willingness to discuss the terms of a gas balancing
agreement with the State in the event it wishes to
pursue an actual sale of gas to Netricity. For its
part, Netricity has also been talking to the producers
about purchasing gas, and our understanding is that
Netricity is currently working on a more detailed
proposal that addresses some of the issues their
initial proposal left unaddressed. The question of
whether the State should pursue the Netricity proposal
alone therefore may become moot.
Finally, while this may go without saying,
legislation that would attempt to force the producers
to provide the State a right under its leases that was
not part of their original bargain is likely to run
afoul of the Impairments of Contracts clause of the
United States Constitution.
MR. GRIFFIN emphasized that should the Netricity scenario occur,
the state would have to discuss how to make the producers whole
later. For example, would there be a cash payment or a trade in
production? And if the latter, at what time would that occur?
All these would have to be talked about, as well as the physical
steps necessary to take the gas from the field and "get it to our
potential customer." Mr. Griffin added that to his
understanding, Netricity has been talking to the producers about
purchasing gas. He explained:
They came to us and talked to us. I think the
Department of Natural Resources expressed some
curiosity about why, if this was such a good deal, the
producers didn't seem interested. And I think at that
time Netricity just hadn't spoken with the producers.
I understand that since that time Netricity has spoken
with the producers and, in fact, is ... in the process
of putting together a more detailed proposal, to answer
some of the questions that were presented to it that
they weren't prepared to answer at their first set of
meetings.
So I guess the point of that is, we may not have to
enter this negotiation over what a gas balancing
agreement is going to look like. We may not be
pursuing that option on our own.
MR. GRIFFIN emphasized that if the legislature was trying to
alter the terms of the deal that the producers struck when they
first signed the leases with [the state], there would be a
potential problem under the Impairments of Contracts clause of
the U.S. constitution. There are many ways to get a result;
however, the state probably shouldn't think about trying to
change the terms of [producers'] agreements with the state
through legislation.
MR. GRIFFIN turned attention to question 6, which read, along
with the response:
6) In any event, what action has the
administration taken to reach a voluntary gas balancing
agreement with the producers so that the state could
take its royalty gas in-kind before a major gas sale?
As indicated above, the producers have expressed a
willingness to discuss such an agreement with the
State. However, my understanding is that Netricity has
informed DNR that it wishes to pursue its options with
the producers. As a consequence, it has asked the
State not to take any additional actions in furtherance
of its initial proposal at this time. This suggests
that the need for a gas balancing agreement with the
producers may never materialize.
MR. GRIFFIN added that consistent with that, "we haven't been
pushing the producers for a gas balancing agreement."
MR. GRIFFIN turned attention to underlifting. He pointed out
that because underlifting is the corollary to overlifting, some
answers would be parallel to the previous ones. He addressed
question 1, which read, along with his response:
II. UNDERLIFTING
1) Are there any statutory provisions that are
relevant? If so, what are they and why?
AS 38.05.180(l) specifically addresses the
Commissioner's authority to negotiate underlifting
agreements. It provides:
Subject to the provisions of AS 31.05, the
commissioner has discretion to enter into an
agreement whereby, with the consent of the
lessee, the state's royalty share of oil and
gas production may be stored or retained in
storage by the lessee, or the commissioner
may enter into an agreement with one or more
of the affected field lease holders to trade
current royalty production from a field for a
like amount, kind, and quality of future
production, on the condition that the state
receives back its stored or traded royalty
share during the first half of the estimated
field life or no later than 15 years after
start of production, whichever is sooner.
That statutory provision was adopted after the
State negotiated the Prudhoe Bay Unit Agreement.
During the negotiation of that agreement, the State
sought to include an express provision allowing it to
underlift Prudhoe Bay production. The State ultimately
dropped that request.
MR. GRIFFIN noted that AS 38.05.180(l) addresses underlifting
without actually using that term, and indicated AS 31.05 contains
the conservation statutes. He pointed out that the statute in
question reflects a preference for balancing with future
production, as opposed to balancing with cash payments. As to
why that statute exists, he told members:
This statute was adopted soon after we negotiated the
Prudhoe Bay Unit Agreement. And in the course of
negotiating that unit agreement, the state was in fact
trying to include, within the confines of the unit
agreement, a specific provision that would allow it to
underlift ... oil and gas. And ultimately the state
did not succeed in getting that into the unit
agreement. At some point, we dropped ... the request.
... The legislative history is a little bit unclear on
this, but ... the most natural reading of the history,
I suppose, is that this ... particular provision was a
natural outgrowth or consequence of not including the
underlifting provision ... in the unit agreement.
MR. GRIFFIN turned attention to question 2, which read, along
with his response:
2) Is there an explicit right in any of the
[lease] provisions? If not, is there an implied right?
As with overlifting, there is no express or
implied "right" under the leases for the State to
underlift gas produced from Prudhoe Bay.
MR. GRIFFIN addressed question 3, which read, along with his
response:
3) Has the Prudhoe Bay Unit Agreement or any
other agreement between the state and the producers
modified any of our rights?
Nothing in the Prudhoe Bay Unit Agreement or any
other agreement between the state and the producers has
created a right for the State to underlift its gas. As
previously indicated, the State sought to include such
a right in the Prudhoe Bay Unit Agreement, but was
unsuccessful. If anything, the State's agreements with
the producers reinforce the conclusion that the State
has no "right" to unilaterally decide to take a
quantity of gas that differs from its royalty share of
the gas stream that is currently being sold or used
outside of the Unit.
MR. GRIFFIN turned attention to question 4, which read, along
with his response:
4) Assuming that under the current agreements or
applicable law, there is no right to delay taking
royalty in-kind after a major gas sale, is there a
legislative fix that you [the Department of Law] could
recommend?
The legislature adopted the appropriate fix when
it enacted AS 38.05.180(l). As with overlifting,
legislation that would attempt to force the producers
to provide the State a right under its leases that was
not part of their original bargain is likely to run
afoul of the Impairments of Contracts clause of the
United States Constitution.
MR. GRIFFIN added that in the department's view, AS 38.05.190(l)
was the appropriate fix to the extent a fix was necessary. The
caution about not changing the leases through legislation applies
to unit agreements and other agreements, he noted.
MR. GRIFFIN next addressed question 5 and the response, which
read:
5) Would a gas balancing agreement between the
state and the producers be necessary for the state to
underlift?
Yes.
MR. GRIFFIN turned attention to question 6, which read, along
with the response:
6) Has the state ever entered into a gas
balancing agreement with a producer?
Not on the North Slope and not to our knowledge in
the Cook Inlet. However, we are still reviewing
historical records of oil and gas production in the
Cook Inlet to see if the State ever entered such an
agreement.
MR. GRIFFIN turned attention to the next set of questions,
relating to lease termination in the event that there is no gas
pipeline. He paraphrased question 1 and the first part of the
response, which read:
III. LEASE TERMINATION
1) If the Producers assert that a gas line
cannot be built and [as a consequence] fail to market
the gas, can the state terminate the leases for breach
of contract?
At Prudhoe Bay, where there are ongoing oil and
gas production operations, the answer is almost
certainly not.
The question that has been posed really has two
parts. The first is whether the producers' failure to
build a gasline and market the gas constitutes a breach
of their leases or other agreements with the State. If
so, the second part is whether termination of the
leases is the appropriate remedy for that breach.
A decision by the [producers] not to build a
gasline is unlikely to be a breach unless the State can
show that the producers failed to exercise prudent
business judgment in reaching that decision. This
standard is also referred to as (or perhaps is a sub-
part of) the reasonable prudent operator standard, and
generally requires the lessee to act in good faith,
exercise competence in making business judgments, and
give due regard to the lessor's (the State's)
interests.
REPRESENTATIVE OGAN asked whether "prudent business" includes
prudent business within the state or would have to include a
worldwide scope. He pointed out that there are projects
competing with Alaskan gas. He offered Point Thomson as an
example, saying it has never really been developed and is "pretty
much a gas field."
MR. GRIFFIN answered that he believes it is an interesting
question. To his knowledge, he said, that has never really been
addressed in any of the cases. He offered his belief that the
state could well take the position that "the lessee's agreements
are with us; that's what establishes our relationship; we don't
have a relationship with their other business dealings throughout
the world, and so the duty that is owed us is a reasonable,
prudent judgment based on the merits of our project, and not how
our project necessarily compares to other projects ... in the
world." Mr. Griffin added that he doesn't know that the courts
would accept that argument, but said, "I acknowledge that it
could be an argument that we might raise."
MR. GRIFFIN noted that the second part of question 1 is what the
appropriate remedy is, if it can be shown that there has been a
breach. Would termination be the appropriate remedy? He told
members that at Prudhoe Bay, he believes the answer is no. There
are substantial investments at Prudhoe Bay, as well as ongoing
oil and gas production operations. He paraphrased a portion of
his written response, which read:
Assuming for the moment that the State could show
that a decision not to build a gasline was the result
of something other than prudent business judgment, the
question of the appropriate remedy arises. Generally
speaking, whether termination of an oil and gas lease
is an appropriate remedy will depend on the particular
facts in a given case. The general rule, however, is
that a court will avoid remedies like termination where
damages are adequate to redress the harm occasioned by
the breach. A court is highly unlikely, in our view,
to consider termination an appropriate remedy where, as
at Prudhoe Bay, there are substantial investments and
ongoing production operations by the lessees. It is
also improbable, in our view, that the State would
consider termination of the leases there to be in its
best interests.
MR. GRIFFIN emphasized his belief that a court is unlikely to
terminate unless it can be shown that an award of monetary
damages is somehow inadequate. He doesn't believe the state
would be able to say that the failure to build a gas line
requires that the leases at Prudhoe Bay be terminated, and that
there is no other adequate remedy.
MR. GRIFFIN read question 2 and paraphrased the response, which
together read:
2) Are there any other provisions in the lease
which the state can use to terminate the leases if the
Producers declare the gas uneconomic to market?
Putting aside the question of whether termination
is the appropriate remedy if the State could in fact
show a breach, there are several implied covenants in
the leases that might be invoked under appropriate
circumstances [in defense of the state's rights].
These include the implied covenant to reasonably
develop the leases, the implied covenant to market, the
implied covenant of diligent and proper operation, and
the implied covenant of good faith and fair dealing.
MR. GRIFFIN read question 3 and paraphrased the response, which
read:
3) Assuming that the state does not approve the
Producer's plan of development for Prudhoe Bay because
it is not in the state's best interest, can the state
terminate the Unit Agreement and the leases within that
Unit?
If the producers' fail to comply with a DNR-
approved plan of development at Prudhoe Bay, DNR may
declare the Unit in default. 11 AAC 83.374. At that
point it would be incumbent upon the State to seek
appropriate relief from the courts. For the reasons
already articulated, the courts probably would not
consider termination of the Unit and the underlying
leases an appropriate remedy.
MR. GRIFFIN explained that for each field on the North Slope, the
producers are required to submit a plan of development to DNR.
That is reviewed by the department and then, usually after some
give and take, approved by DNR. The operator then continues to
produce oil and/or gas from the field in accordance with that
plan. This question asks what happens if an agreement cannot be
reached and the department does not approve a plan.
MR. GRIFFIN again emphasized that at Prudhoe Bay it is highly
unlikely the remedy chosen by the courts would be termination of
leases. He added:
Again, it strikes me as ... at least hard to imagine
that we would think that would be in our best
interests, but it would be a situation [in] which we'd
present arguments to the court, and it'd be up to the
court to accept those arguments or choose some other
appropriate remedy, assuming, again, that the state
could show a breach.
CHAIRMAN TORGERSON asked what would happen if [the state] showed
it had another customer ready to go forward with some sort of
high-volume usage, although not necessarily a pipeline, and the
analysis by the producers was that it isn't economical. He said
he would think the producers could certainly make a deal with
that other person, and that if they refused to do so, the state
would have a cause. He asked what Mr. Griffin thought.
MR. GRIFFIN answered:
Well, I guess my personal view is that a scenario in
which we would think it'd be in the state's best
interests to go forward with a project like that and
the producers would not - and then the producers would
not go the next step of trying to accommodate our
interest in pursuing that proposal - would be somewhat
unlikely. But I guess I acknowledge your
"hypothetical," and I think that under the right
circumstances you could, in fact, allege a breach and
try and pursue some ... remedy there. ...
I think, to be fair to the producers, they - believe it
or not - are interested in making money. And if you
could make money off a proposal like that, they'd
probably be interested.
Now, there may be a situation in which, for example, we
don't think we need to make as much money as the
producers feel they need to make. Well, then, then
we're going to have a situation in which we're going to
ask the producers to help us out on what to them would
be money-losing proposition. But they say OK. So we
enter into the arrangements and we have a situation in
which we're selling gas at a price that is lower than
the producers would be willing to accept on behalf of
their shareholders.
Now, presumably the reason the producers would conclude
that that price is too low is that they've got
something else in mind. And so let's take the
hypothetical further and say that what they've got in
mind is a major gas sale. And then they'd build the
gas project. And lo and behold, the price that they're
getting is, in fact, much higher than the price we've
committed to in our agreement with Netricity. ... We've
created a rather unfortunate situation in which they
are going to be, probably, a lot of hard feelings all
around, and the producers ... might feel that we might
take it out on them because ... they weren't ... as
forthcoming with us as they should have been in
describing just how unprofitable this particular scheme
was, or whatever. ...
What we generally try and do is find ways of aligning
ourselves with ... the producers. And if we come to a
point that we really want to do something and the
producers really don't, ... we'll be talking a lot with
them, and we may be talking a lot with you, as well.
But we haven't reached that point yet. Netricity
hasn't come forward with a proposal that is something
that is detailed enough to justify the unqualified
support of either the state or the producers.
CHAIRMAN TORGERSON responded:
Or me, as far as that goes. I'm not necessarily
looking at Netricity, but there are other things out
there. And I'm not saying either one of them are
better. I'm not trying to give you names of different
projects that may or may not be a little bit better.
But the facts are, the producers sat on this for 27
years, haven't done much, and we have a lot of interest
in moving this. And they're looking at a particular
thing. And the question looms that if their project's
uneconomical and they refuse to sell to somebody else,
then what position are we in, in ... terminating the
lease or doing other things?
MR. GRIFFIN replied, "Right. And with any luck, we won't have to
face ... that particular scenario. But if we do, we do."
REPRESENTATIVE DAVIES followed up, specifying that he wasn't
talking about the Netricity model, but a situation in which the
state is willing to develop for a return on the investment that
is considerably less than the companies might be willing to do it
for. For example, a company could go through its "due diligence"
and conclude that the return on investment at 10 percent is too
low, and that a better return on the capital can be obtained
elsewhere in the world, not even necessarily with gas; it would
be a perfectly valid business decision. However, the state might
be willing to build a pipeline and finance it for an investment
return of 5 percent, and would see that as a perfectly valid
investment because it would develop infrastructure and get gas to
the citizens, for example. He asked, "Where are we then?" He
also asked, "How do we get the gas?"
MR. GRIFFIN answered:
Well, we ask them for it. ... If they say no, I guess
there are probably a number of hammers that the
legislature could wield. The power to tax is the power
to destroy; you've got the biggest hammer there is.
And perhaps that's one reason why they are willing to
talk to us, if that's really what we want to do. ... I
suppose from their perspective, they'd look at it as
... if we want to hang ourselves, they'd sell us the
rope. ...
As long as we're willing to pay for what we want,
there's relatively little reason for them to say no,
except, again, perhaps this fear of what's going to
happen down the line. ... Let's take your example: We
sell gas with the expectation of a 5 percent return on
investment; they develop a gas project and are making
17.5 percent. Well, we're going to be paying ... for
the gas that we overlifted to earn 5 percent with 17.5
percent gas. We're not going to be very happy about
that. Or ... someone's going to make a deal today, and
then ten years from now it's payback time, and the
people who made the deal aren't going to be around.
And the folks who are judging the deal ... are probably
not going to be very happy. I think that sort of
scenario makes the producers a little bit nervous.
I think they would like to be aligned with us on gas
development projects. And alignment generally, I
think, is what's contemplated in the leases and in the
unit agreements. But I'd say we talk first; I think
that will probably take care of it. And if it doesn't
take care of it, I think that the state does have other
options at its disposal, as unsavory as those options
might be.
REPRESENTATIVE OGAN asked what happens if the "something else
[that producers have] in mind" is to warehouse [the gas] another
27 years. He also asked whether that would give the state the
legal ability to call it a breach of contract. He mentioned a
paper written by Bob Bartlett at the Alaska constitutional
convention about giving a property right to a corporation that
will warehouse it until such time as the corporation sees fit to
market it; Representative Ogan commented that it was prophetic.
MR. GRIFFIN responded, "I think from the companies' perspective,
they would not warehouse gas ..."
REPRESENTATIVE OGAN interjected, "They have been."
MR. GRIFFIN replied:
That presumes that ... it would have been commercially
reasonable to develop the gas before now. And I think
that based on the work that we've done with our
consultants, the work that the Department of Revenue
has done, we could not conclude that it was
unreasonable of them to not build a gas pipeline and
enter a major gas sale before now.
Because a dollar today is worth a lot more than a
dollar 27 years from now, I think that if these
companies could profitably develop the gas today, ...
that's what they would choose to do. I don't think, as
a state, we would want them to develop the gas if it
couldn't be done profitably. We want a royalty
interest. We want there to be a slice of the pie that
we can tax. That's how we benefit from these projects.
... The project would benefit us very little if, in
fact, it was a money-losing proposition.
CHAIRMAN TORGERSON informed the committee that Mr. Jack Chenoweth
[legal counsel from Legislative Legal Services] wouldn't testify
that afternoon. He had asked Mr. Chenoweth and Mr. Griffin the
same questions, he pointed out, but had also asked Mr. Chenoweth
to respond to some questions he had asked FERC and the
Washington, D.C., attorneys. However, Mr. Chenoweth had only
responded to the latter questions. Therefore, Mr. Chenoweth's
written responses to the FERC-related questions would be handed
out at the following day's hearing.
MR. GRIFFIN turned attention to the next section. Question 1,
along with the response, read:
IV. PRUDHOE BAY UNIT AMENDMENTS
1) Have there been changes in those agreements
which affect the Producers' obligation to develop gas
resources in Prudhoe Bay?
No. The producers have always had the obligation
to develop Prudhoe Bay gas, assuming it is commercially
reasonable to do so, and that obligation has not
changed.
MR. GRIFFIN discussed question 2, which read, along with the
response:
2) Were there any provisions in older versions
of those agreements that were an impediment to gas
development?
I assume you are referring here to the disparate
ownership interests held by the working interest owners
in the Oil Rim and Gas Cap of the Sadlerochit Reservoir
in Prudhoe Bay. My understanding and belief is that
these disparate ownership interests, and the agreements
establishing these interests and the manner in which
they would be operated, created no economic impediments
to a major gas sale.
More specifically, the Department of Revenue
analyzed this question at length and concluded that
there were no provisions in those agreements that
created an economic disincentive for any working
interest owner at Prudhoe to develop a gas project
capable of supporting a major gas sale. If such a
project is economic, Revenue concluded that every
working interest owner would have an incentive to
participate in it.
It is nevertheless true that the source of each
working interest owner's incentives varied, depending
upon that owner's relative interests in the Oil Rim
versus the Gas Cap. Speaking in very rough terms, a
Gas Cap owner's incentives come primarily from the
revenues generated by a major gas sale. An Oil Rim
owner, however, derives many of its benefits another
way: once there is a major gas sale, some of the costs
of running the field are shifted from Oil Rim owners to
Gas Cap owners. Nevertheless, at the end of the day,
the incentives of these owners were aligned, even
though their ownership interests were not. Of course,
the analysis becomes complicated, because every working
interest owner at Prudhoe owns interests in both the
Oil Rim and the Gas Cap.
MR. GRIFFIN added that the cost-shifting happens under the
agreements. Therefore, an oil rim owner also has an incentive to
pursue a major gas sale. He concluded that the incentives are
aligned, but the source of the incentives comes from different
parts of the agreements.
MR. GRIFFIN turned attention to question 3, which read, along
with the response:
3) Have those impediments been removed?
As indicated above, the claim that such
impediments existed is not really accurate. The
substantial realignment of interests at Prudhoe Bay
has, however, greatly simplified the analysis. It has,
moreover, created a situation where the economic
incentives of the major producers are not only aligned,
but also spring from exactly the same source.
MR. GRIFFIN added that the producers are all "looking at the
picture the same way," which is a real benefit to the
realignment, even though it didn't really change the economic
question or answer.
MR. GRIFFIN addressed the fourth and final question, which read,
along with the response:
4) If impediments remain, can the State
terminate the leases unless the Producers agree to
remove those impediments?
Again, we do not agree that the term "impediments"
is accurate. To the extent that there were
"misalignments" attributable to disparate ownership
interests in the Gas Cap and the Oil Rim, those
misalignments did not create an economic disincentive
for a major gas sale. In addition, the Department of
Natural Resources approved the disparate ownership
interests between the Oil Rim and the Gas cap as part
of the Prudhoe Bay Unit Agreement. It would not be
appropriate to seek termination of the leases simply
because the lessees have not completely realigned the
interests that DNR previously approved.
REPRESENTATIVE OGAN turned to the issue of gas balancing and
posed a hypothetical situation. There is no gas balancing
agreement, and the three major producers are looking at a
project. One wants it to go one way, but the other two prefer
another way. He asked whether lack of a gas balancing agreement
doesn't give that minority owner a "pocket veto," in essence, if
that one owner doesn't agree to a route. He asked whether that
could be used as leverage in negotiating with the other two,
because if there is no gas balancing agreement, then the gas
cannot be commercialized.
MR. GRIFFIN responded that a gas balancing arrangement is just
one of a number of commercial arrangements that would have to
take place among the working-interest owners. He added:
I don't think that the lack of a gas balancing
agreement today would necessarily ...
TAPE 01-10, SIDE B
... inhibit commercial development if two out of three
working-interest owners wanted to go their own way.
I'm going to have to review the Prudhoe Bay Unit
Operating Agreement again, but essentially ... there
are balancing arrangements already in place among the
working-interest owners. ... And it would probably be
more appropriate ... for someone from the companies to
answer this question. But I think that to the extent
you're referring specifically to the existence of a gas
balancing agreement - as I understand that term - that
agreement may already exist in Article 39 of the
Prudhoe Bay Unit Operating Agreement.
REPRESENTATIVE OGAN recalled that in testimony this year [before
the House Special Committee on Oil and Gas] the companies said
there isn't a gas balancing agreement. He again asked whether
that could be used as leverage regarding the choice of a route if
the three producers didn't agree.
MR. GRIFFIN replied:
I personally don't see how that could be used as a ...
real lever in the discussions among the companies. ...
The companies may have different views ... today about
... how particular aspects of gas development should be
treated. But I think at the end of the day they're
going to try and align themselves. ... I guess I just
don't foresee the existence or lack thereof of a gas
balancing agreement preventing them from ... getting
together, because ultimately they will get together,
one way or another.
REPRESENTATIVE OGAN remarked that he has talked directly with
people who have been around the industry for a while, and who are
directly involved with the "majors" who feel that that is a major
factor. He said he was trying to determine Mr. Griffin's take on
it, and whether he had firsthand knowledge.
MR. GRIFFIN specified that he didn't have firsthand knowledge.
SENATOR OLSON asked, "If there are changes in agreements -
realizing that the district I represent is the North Slope - are
there any significant negative effects to the local people up on
the North Slope if some of these agreements are to be changed?"
MR. GRIFFIN replied:
The agreements I'm thinking of generally are the
Prudhoe Bay Unit Agreement, the Prudhoe Bay Unit
Operating Agreement, and perhaps the Point Thomson Unit
Agreement and the Point Thomson Operating Agreement.
... I don't see that changes to any of those agreements
should have negative effects on the people ... of the
North Slope. Those changes will ... address the
relative interests in each lease or participating area
that the working-interest owners have. It'll be a
shuffling of interests.
Of course, once a gas project is built, or ... as it's
being built, ... there's going to be a number of
effects on the people on the North Slope, and I'm not
really prepared to address those effects.
CHAIRMAN TORGERSON asked whether Mr. Griffin's understanding is
that the balancing agreements that were negotiated because of the
ARCO-Phillips merger are public documents.
MR. GRIFFIN answered that he doesn't believe they are.
CHAIRMAN TORGERSON asked if Mr. Griffin would venture to guess
why that is.
MR. GRIFFIN replied:
The reason I have them and they are not public is that
I obtained them under the investigative powers of the
attorney general, as part of the merger investigation.
And there are fairly strict confidentiality
requirements that attach to investigations like that.
... As a rule, private companies don't share their
commercial negotiations and ... their commercial
arrangements publicly.
CHAIRMAN TORGERSON expressed his understanding that the
legislature has a request in, from Mr. Jack Chenoweth, for
copies. He stated:
Initially we were told it was confidential, and then
were told later that they'd get us one Xeroxed copy of
it so that we could review those ... as to how they may
affect the old agreements versus the new ones, because,
quite honestly, this is like a mysterious document out
there that nobody wants to talk about. ...
I can't tell you if the state's interests were
protected or not, and neither can you, apparently,
because you've ... conflicted yourself out by saying
[they're] confidential. So ... if you obtained them
that way, I'm assuming you can't speak about them or
what's in them to any degree .... I think it's
important that our Legislative Legal [Services] review
those documents, which I understand are six volumes,
versus the Prudhoe Bay Unit Agreement was one volume,
and that was negotiated however many years ago. ... I
can't believe it's the same information and nothing's
changed .... I believe we do have a request in, to get
those documents.
MR. GRIFFIN replied, "I think you should review those. I was
under the impression that the legislature had, in fact, been
privy to some of that information during the merger, but perhaps
I'm wrong."
CHAIRMAN TORGERSON responded:
Well, they probably were, but the people on that
committee were conflicted out also. They signed a
confidentiality agreement that lasts beyond life. ...
Whoever drafted that one was a dandy, but I wouldn't
[sign] it myself because it would just [prevent] you
from being able to discuss it ... in any event, at any
time, in any case, the way I read the thing. ... But
I'm not looking for that to be presented to this
committee in a confidential form, because I won't do
that. I don't think it needs to be confidential, or
nothing that I [am] going to review is going to be
confidential, from my point of view.
REPRESENTATIVE DAVIES said to Mr. Griffin:
In answer to one of the questions earlier, you said
that the state's interest - I think ... you were
talking about alignment with the industry ... and that
our interest was, I took you to be saying, entirely
within our ability to tax and to get severance taxes
and royalties off the development of the gas. ...
I wanted to ask you to broaden the consideration to
lower energy costs for citizens if gas were available,
and the possible development of petrochemical
industries and those kinds of things, and how do we
balance those interests of the State of Alaska with the
severance taxes and royalties. Clearly, there are
scenarios where ... it would be in our collective
interest to ... have a lower wellhead value and have
the gas produced, because of these other benefits. ...
What's the calculation that we do to make that
decision?
MR. GRIFFIN answered:
That's a good question. I didn't mean to suggest that
... the legislature's only power in this regard applied
to its tax regime. ... I was speaking in terms of ...
what the appropriate mechanism is ... in which to
accomplish particular objectives, and what the
objectives are, I think, as a policy choice that's
given to the legislature. And I think you can
certainly make tradeoffs between wellhead value and
other interests - gas to local communities and the
like.
Again, I was just suggesting that you don't want to try
and accomplish those objectives by changing the terms
of the leases that the state has with the producers.
You want to pick other mechanisms for accomplishing
those objectives, and there may be many different ways
of accomplishing those objectives. ... There may be
ways in which we take our royalty in kind and devote it
to ... the interests you've described, or we create tax
incentives for certain types of conduct that accomplish
the legislature's goals. I think it is up to you to
come up with what the appropriate goals are, and then
there are a number of different ways, probably, to
accomplish those goals.
Personally, though, in any sort of tradeoff like that,
... I don't like trading wellhead value unless someone
can show me that ... when you add the benefits of the
jobs and the benefits of the local gas use, that you
come out with greater economic benefit than you would
get from just taking that wellhead value and paying for
the gas or paying for the jobs yourself. So ... we
want to be careful, when we start trading wellhead
value for something, to make sure that we actually get
what we're paying for.
CHAIRMAN TORGERSON thanked Mr. Griffin and asked whether there
were further questions; none were offered.
CHAIRMAN TORGERSON called an at-ease at 4:47 p.m. He called the
meeting back to order at 5:03 p.m.
Gas Pipeline Office
CHAIRMAN TORGERSON reminded members that although Mr. Bill Britt
had given a lengthy presentation at the July committee meeting,
he had been invited to update the committee on the status of the
memorandums of understanding (MOUs) with the producers and
Foothills Pipe Lines, as well as anything else that may be going
on with the [Gas] Pipeline Office.
MR. WILLIAM G. BRITT, JR., State Pipeline Coordinator, Department
of Natural Resources, came forward, noting that he was tasked by
Administrative Order 187 with setting up the office that will be
responsible for permitting natural gas pipelines to move North
Slope gas to market, and for overseeing construction of
pipelines. He offered a list of activities and accomplishments
[in committee packets]. The first section read [original
punctuation and capitalization provided]:
Gas Pipeline Office
Activities and Accomplishments
Project Proponent Relations
1 We began work planning with Foothills Pipe Lines on
July 26. Follow-up will occur on August 16 and 17.
2 Work planning with the producers' consortium will begin
on August 23.
3 DFG [Department of Fish and Game] approved the
producers' consultants' fish collection permit.
4 Meetings have occurred with representatives of El Paso,
Williams, and Anadarko.
MR. BRITT turned attention to the second portion of the list,
which read:
Federal Relations
5 BLM [Bureau of Land Management] assigned a liaison to
the GPO [Gas Pipeline Office]. Discussions are
underway with MMS [Minerals Management Service] for
assignment of a liaison.
6 The GPC [Gas Pipeline Coordinator] and BLM liaison to
GPO were briefed on DOI/DOE/FERC cooperative efforts on
August 9.
7 Travel to DC [by Mr. Britt] is tentatively scheduled
for mid-September to attend the North American Natural
Gas Forum and to coordinate with FERC and DOE staff.
MR. BRITT explained that the liaison assigned by BLM is an
engineer with a petroleum pipeline background. He also noted
that there is an ongoing relationship with MMS in the State
Pipeline Coordinator's office because of the "Liberty project."
He reported that the Gas Pipeline Coordinator is himself, and
said DOI/DOE/FERC refers to a task force among the [U.S.]
Department of the Interior, the Department of Energy, and FERC,
formed pursuant to the President's energy policy to figure out
how to cooperate on a variety of issues including a gas pipeline.
He pointed out that in his travels to Washington, D.C., he plans
to have staff-level interactions with both FERC and the
Department of Energy; at that point, he will have relationships
going with all of the major federal agencies that he believes the
state needs to cooperate with.
MR. BRITT addressed the next portion of the list, which read:
Legislative Relations
8 The GPC provided testimony at the Joint Committee on
Natural Gas Pipelines on July 17 and August 14.
9 The GPC and the DFG and DEC [Department of
Environmental Conservation] liaisons to the GPO
provided testimony at the Alaska Highway Natural Gas
Policy Council on August 2.
MR. BRITT turned attention to the next portion, which read:
Media Relations
10 The GPC was interviewed by the Journal of Commerce on
July 19.
11 The GPC was interviewed by Petroleum News Alaska on
July 27.
MR. BRITT commented, "Fortunately, I believe, we have not
received a great deal of media relations, so we've been able to
concentrate on other things. A couple of folks have picked up on
the opening of the office and the signing of the reimbursement
MOUs, and so I've conducted a couple of interviews."
MR. BRITT turned attention to the next portion, which read:
Financial
12 LB&A [Legislative Budget and Audit Committee] approval
for the Chairman [Therriault] to release funds to DNR
occurred on July 17. Commissioner Pourchot received
Senator Therriault's letter approving the first
expenditures of general funds on July 18.
13 The reimbursement MOU with Foothills Pipe Lines was
signed on July 18.
14 The reimbursement MOU with the producers was signed on
August 1.
15 RSA forms for state agencies were completed the week
of July 30. Detailed attachments have been completed
for DEC and DFG.
16 Collocation codes have been established for all GPO
agencies.
MR. BRITT clarified that the state agencies mentioned above
regarding RSA forms are the other agencies that will be
participants in the Gas Pipeline Office. The accounting
functions have been set up with those agencies to track the money
and make sure everything stays straight.
MR. BRITT turned attention to staffing, noting that the GPO has
begun to staff up, although it is still relatively small in
numbers. That portion of the list read:
GPO Staffing
17 Liaisons from DEC and DFG have been hired and are on
the job.
18 The DFG Design and Permitting Coordinator has been
hired and is on the job.
19 The DFG Field Inspection and Compliance Coordinator
has been hired and is on the job.
20 Recruitment for DFG Habitat Biologists III is
underway.
21 Recruitment for the DOT [Department of Transportation
and Public Facilities] liaison should begin soon.
22 Recruitment for the DGC [Division of Governmental
Coordination] liaison should begin soon.
23 The GPO Administrative Manager has been hired and will
begin work soon.
24 Recruitment for the Deputy GPC is underway. Display
ads ran in Anchorage, Fairbanks, and Juneau papers last
weekend.
25 Two Assistant Attorneys General have been assigned to
assist the GPO on an as-needed basis.
26
MR. BRITT concluded by informing members that the GPO moved into
its temporary offices in the Atwood Building on August 10 and
will be there for the next four and a half months or so.
CHAIRMAN TORGERSON said he has been hearing rumors that the
producers may have reduced their scope of work. He asked whether
there is any truth to that.
MR. BRITT answered that he hadn't heard that, and hadn't seen
much evidence of it, so he didn't know.
REPRESENTATIVE OGAN expressed concern with the appropriation that
was approved, saying it creates new divisions of bureaus. Once
this work is done, he asked, are these positions going to go
away? He acknowledged that Mr. Britt couldn't speak for other
portions of the administration, but asked whether these people
are being told they are going to work themselves out of a job,
for example.
MR. BRITT replied:
The Gas Pipeline Office has always been viewed as an
entity with a sunset clause. And the administrative
order speaks to it, and I believe, and I've said it out
loud: The Gas Pipeline Office's purpose in life is to
permit the project and to oversee construction; when a
gas pipeline is operational, it will return to the
Joint Pipeline Office, which is where the rest of the
operational pipelines exist, and that's exactly where
it should go.
REPRESENTATIVE OGAN asked, "What if it takes another 27 years?
Will you be coming to the legislature next year for an
appropriation, and the year after, and the year after?"
MR. BRITT answered, "I'll stop somewhere before 27 years. ... At
the point that the majority of our funding is not through
reimbursement, I would expect the patience with the Gas Pipeline
Office to wear fairly thin, fairly fast."
REPRESENTATIVE FATE asked why there must be a new hire for the
Alaska Department of Fish and Game habitat biologist, rather than
recruiting someone interdepartmentally.
MR. BRITT responded that the liaison came from within the Alaska
Department of Fish and Game. He added that he believes both
those positions were filled by people from within the Alaska
Department of Fish and Game; they are new positions because that
department's resources were such that it couldn't simply move a
position from another program and short-hand that other program.
Mr. Britt offered his belief that the DEC liaison, recruited from
outside of state government, may be the only current GPO employee
who wasn't already a state employee at the time of accepting a
position there.
CHAIRMAN TORGERSON reminded members that at the last meeting he'd
raised concern about the administration's and the legislature's
going down parallel courses and not talking much to each other.
He noted that right before coming to Fairbanks, he'd received a
letter from Commissioner Pourchot saying he wants to work with
the legislature and this committee; Commissioner Pourchot had
also asked Chairman Torgerson for suggestions on how he might
communicate better. Chairman Torgerson asked Mr. Britt whether
he does weekly updates for the public, for example, and whether
he could include the committee.
MR. BRITT answered:
I'm not doing that right now, Senator Torgerson, but
I'm at the point where the activities are such that a
weekly update wouldn't be too short and boring. So
it's probably time to begin preparing periodic updates
for a variety of folks, and I'd be happy to include you
on the list.
CHAIRMAN TORGERSON replied that he appreciated that, but wasn't
quite sure what the best way to interact would be. He said
information is not free-flowing, and that needs to be addressed.
Whether it is what Mr. Britt proposed for every office, he
indicated, he wasn't sure, but he suggested that wouldn't be too
time-consuming.
MR. BRITT responded:
No, I don't think so. My expectation was, with the
general funds from LB&A, that I would be in as frequent
a contact with Senator Therriault as he wished to be
briefed on what was going on and how the money was
being spent. And I would certainly offer the same
thing to you or any other member of this committee. If
you ever would like a status report on any of these
topics or anything else within the Gas Pipeline Office,
please give me a call.
CHAIRMAN TORGERSON asked whether there were further questions or
comments; none were offered. He thanked Mr. Britt for the
update.
Testimony - North Slope Borough Assembly
MR. MIKE AAMODT, Member, North Slope Borough Assembly, North
Slope Borough, came forward to testify as follows:
My name is Mike Aamodt. I've lived on the North Slope
for 29 years, and I've been on the North Slope Borough
Assembly for 14 years. I am currently the Assembly
vice-president.
Thank you for the opportunity to address the Joint
Committee on Natural Gas Pipelines. For more than a
quarter of a century, the people of the North Slope
have played an active role in Alaska's oil and gas
development. Ever since the first oil flowed from
Prudhoe Bay, North Slope residents have worked in
partnership with the state and the industry to expedite
development and at the same time protect the land and
wildlife that feed the people that I am married into
and form the spiritual core of Inupiat culture.
We believe natural gas development is the next logical
step in the North Slope resource extraction. We salute
the legislature and the governor for firm support of a
highway route in delivering gas to market. The highway
route makes a lot of sense because it increases the
potential for in-state use of gas. This can help to
create new industries along the route and keep
communities viable, especially in rural areas where
energy costs are so high.
Most important to residents of the North Slope Borough
is that the highway route makes the best environmental
sense. By using the existing pipeline corridor instead
of the ice-choked Beaufort Sea, the highway route
minimizes damage to the land and the risk to the
wildlife. From our perspective, putting a pipe out in
the Beaufort Sea is just asking for trouble.
When the Alaska Highway Natural Gas Policy Council held
a hearing in Barrow a few weeks ago, many whaling
captains and elders showed up to tell the committee
about the current and wind-driven forces of ice that
they've seen out in the ocean. It's going to take more
than a few feet of ocean floor to protect the pipeline
in the Beaufort Sea. That's why the North Slope
Borough, the Alaska Eskimo Whaling Commission, the
whaling captains association, and other local
organizations have expressed opposition to the over-
the-top route.
In the short term, any summer construction activity
will disrupt the bowhead whale migration around
Kaktovik, Nuiqsut and Barrow. This is unacceptable.
In the overall scheme of things, three small
communities are probably meaningless when the cost
savings of the northern route is considered. But for
the people dependent on that resource, the loss is
beyond value.
Apart from the concern over where the pipeline goes,
there is also the political and economic question of
how to make it happen. The North Slope Borough took an
early interest in the possibility of public-sector
involvement in financing the gas line.
As a member of the Alaska Gasline Port Authority, we
explored finance options as mechanisms for lowering the
effective cost to industry and maximizing the return to
the state and communities all over Alaska. The port
authority has sponsored some good discussion and has
brought consultants with relevant expertise to the
state.
However, now that your committee and the governor's gas
policy council have commenced hearings, the borough
believes it should defer to both groups and wait for
the results of these hearings.
The North Slope Borough will remain open to all
development scenarios under consideration, including
the port authority. We also want to see the results of
industry efforts through the Consortium Group and the
Sponsor Group.
We feel so strongly about [this] that the North Slope
Borough Assembly has passed resolution 44-2001 to put
our position on the record. That resolution says, in
part: ...
1. The North Slope Assembly supports the
administration's current efforts to use
borough participation in the port authority
as one means of encouraging the development
of North Slope natural gas resources;
2. The Assembly believes it is in the
borough's best interests for the port
authority, at the present time, not to expand
its role until other development strategies
are fully explored; and
3. The Assembly supports the administration's
continued effort to take into account the
entire political picture and pursue ... and
support the natural gas development strategy
which will best protect the borough's tax
base and method of taxation, and ensure the
continued vitality of the economic and
political structure of the North Slope
Borough.
I need to make one comment about resource revenues. We
have been approached by the producers and asked to
consider support for the over-the-top route. While we
are predisposed not to grant that request, we are
getting such mixed messages from the legislature that
it's hard to tell where the greater danger lies.
It is fitting that our testimony is given in Fairbanks,
because on the one hand, the legislature wants us to
join in promotion of the highway route so that
Fairbanks and other parts of the Interior can benefit,
but at the same time the North Slope Borough is under
intense and very pointed attack from Fairbanks
legislative leaders over our method of resource
taxation and our ability to issue bonds. That is not
exactly the kind of gesture you make to a development
partner.
In the meantime, our interests and concerns remain
constant. We support the statewide effort to develop
our natural gas resources. We strongly favor
transportation down the existing pipeline corridor and
the Alaska Highway. This is consistent with our
preference for onshore development, instead of taking
unnecessary risks out in the unstable icepack of the
Beaufort Sea. Also, it will ... occur largely within
the existing resource development area, which helps to
confine the impacts to our land and wildlife. Finally,
gas development will help to sustain the state and
local revenue stream.
After all, we are partners in resource development, and
the borough looks forward to working together with you
for the good of Alaska. We look forward to the results
of your work in this committee and to the continued
partnership in the reasonable development of the
resources we've been blessed with. We are all in this
together, and through mutual respect, we can achieve
the goals of all Alaskans.
MR. AAMODT concluded by saying that is the report from the
borough's administration and the assembly. It may not represent
his own feelings completely, but represents the group.
REPRESENTATIVE OGAN inquired about Mr. Aamodt's comment about
receiving mixed messages from the legislature. He remarked that
he doesn't believe there has been any mixed message from the
legislature about the route.
MR. AAMODT responded:
The mixed messages I'm referring to are attacks on our
taxing authority and our ability to sell bonds. It's
becoming a little bit difficult to sustain our way of
existence with the way the legislature has come at us
in the past. I don't think that's going to continue,
though.
CHAIRMAN TORGERSON thanked Mr. Aamodt for his testimony.
REPRESENTATIVE JOULE commented that with the effort to open the
Arctic National Wildlife Refuge (ANWR) [to development], he would
like to thank the people of the North Slope for their active role
in that endeavor. He concluded, "It's greatly appreciated,
because we are being partners in a lot of ways."
CHAIRMAN TORGERSON agreed with Representative Joule and related a
story about being in Washington, D.C., mentioning two women who
had done an excellent job of lobbying on behalf of opening ANWR.
Alaska Highway Natural Gas Policy Council
MR. JIM SAMPSON, Co-Chair, Alaska Highway Natural Gas Policy
Council, came forward to provide an update, noting that the other
co-chair is Mr. Frank Brown. He informed members that with him
were Mr. Charlie Cole, who chairs the council's
Federal/International Action subcommittee, and Mr. Ken Freeman,
special assistant to the governor, who also provides staff to the
council.
MR. SAMPSON reported that since the last time the council came
before the committee, it has continued public hearings throughout
the state on the issue of a gas pipeline. Public hearings have
been held in Barrow (July 19) and Juneau (August 2), and the
final meeting is scheduled in Valdez (August 23).
MR. SAMPSON reported that the council's subcommittees continue to
meet, looking at issues important to the commercialization of
Alaska's natural gas. Those efforts are led by five subcommittee
chairs: Mr. Cole chairs the Federal/International Action group;
Mr. Bill Corbus heads the State Pipeline Ownership and Tax
Structure group; Mr. Mike Navarre heads the Alaska Hire/Buy/Build
group; Ms. Peg Tileston leads the Environmental Considerations
group; and Mr. Ken Thompson leads the Access for In-State Gas Use
and Future Opportunities group.
MR. SAMPSON expressed hope that in the next four or five weeks,
subcommittee chairs will start putting on paper their
recommendations on issues they've been discussing in
subcommittee. It is hoped that the first draft of the council's
report will be completed between the first and middle of October,
with a final report to the governor by November 30. Mr. Sampson
deferred to Mr. Cole to discuss issues relating to his
subcommittee.
MR. CHARLES E. COLE, Chair, Federal-International Subcommittee,
Alaska Highway Natural Gas Policy Council, informed members that
the meeting in Barrow was "very successful." From that hearing,
the council learned of the intense opposition to a pipeline route
across the Beaufort Sea. He noted that he had encouraged the
administration to transcribe that testimony so that it will be
available for anyone who wishes to look at it. He added, "It was
dramatic and telling."
MR. COLE reported that he'd arranged a meeting of his
subcommittee at which Mr. John Katz and Mr. Bob Loeffler
testified; he'd recorded that testimony and had it transcribed
[copy in packets.] Important was testimony from Mr. Katz and Mr.
Loeffler about [draft] legislation provided to U.S. Senator
Murkowski and perhaps other members of the U.S. Senate from the
producers. [That draft legislation, dated July 19, 2001, and
titled "Alaska Natural Gas Pipeline Act of 2001, is also included
in committee packets.]
MR. COLE further reported that when [Mr. Katz and Mr. Loeffler]
were asked whether the proposed legislation is route-neutral,
they said no, in their view. He suggested that committee members
may want to use that transcribed testimony to further their
interrogation of Mr. Katz and Mr. Loeffler at the following day's
hearing. [He noted that Ms. Esther Wunnicke's name was
misspelled in the transcript, and that Representative Ethan
Berkowitz was inadvertently referred to as the Speaker.]
MR. COLE also noted that discussed was the effect of the treaty
between the United States and Canada regarding the ANGTS [Alaska
Natural Gas Transportation System] route; he indicated the views
of Mr. Katz and Mr. Loeffler on that are contained in the
transcript as well.
MR. COLE informed members that at his suggestion, Mr. Rigdon
Boykin had drafted another version of federal legislation
[provided in packets] that proposes to just amend [the Alaska
Natural Gas Transportation Act of 1976 (ANGTA)] to clear up
problems it poses to a highway route now. By contrast, the
producers' legislation is designed to favor a Beaufort Sea route.
Mr. Cole concluded by emphasizing the need to cooperate and by
offering any information that the council is able to generate.
MR. COLE noted that he had comments to make on other testimony as
well. He recalled about ten years ago [when he himself was
attorney general] that he and Commissioner Harold Heinz [of DNR]
looked at the producers' implied obligation to develop the gas at
Prudhoe Bay; the principal consideration they talked about was
whether that gas was needed economically to further the
extraction of oil from Prudhoe Bay. He remarked, "Well, it
raised such a hue and cry when we even mentioned that we were
looking at it, that for some reason or other the whole subject
was dropped."
MR. COLE suggested it might be good for the legislature to look
aggressively at the implied obligation to develop, "because I
have the sense, to the extent that that obligation exists, that
... a lessee of oil and gas leases ought not to be able to defer
the development of those reserves essentially in perpetuity until
the lessee concludes, 'Well, I've got a bonanza here now, and
it's time to do something,' and to remain sort of silent up until
that time." He said there must be a lot of law on that point,
and an able legal scholar might be helpful to this committee in
looking at those cases. He added, "If you find ... they pass the
'red face' test, then you can write that letter and say, 'Hey,
... it's time ... to put up or shut up or say goodbye.' And
that's pretty bold talk, but, ... it's gone on for years and
years, and something has to happen."
MR. COLE also commented that as he looks at the statutes and what
happens with respect to Alaska's oil lands, so often one runs
across this confidentiality; many times, citizens of this state
just can't find out what's going on with respect to their prized
reserves. [Not on the tape but recorded in the log notes was
that he believes the best government is when the people have full
knowledge of what is going on with their resources.]
TAPE 01-11, SIDE A
MR. KEN FREEMAN, Special Assistant, Gasline & Business
Development, Office of the Governor, told members:
One of the interesting things we learned in Southeast
Alaska, actually, is how much Southeast sees the
potential benefits from a highway project as well. We
heard from the cities of Haines and Skagway, in
particular, who see themselves as a very important link
in terms of moving people and materials up Lynn Canal
and into Canada. ... They're taking this very seriously
in terms of maybe even potentially expanding the
facilities at their docks.
We also heard from the Juneau Chamber of Commerce and
Southeast Conference on even Juneau's perception,
hopefully, that they would even have some economic
benefits also of materials and people moving up Lynn
Canal. And interestingly enough, ... we've talked
about potential linking of other opportunities in
Anchorage and Valdez off an Alaska Highway project;
Haines also sees an opportunity for itself to have an
LNG [liquefied natural gas] facility.
Bill Corbus's committee met all day yesterday - the
state ownership and tax structure committee - and I
think he's making some good progress and wants to
interface with this group as much as possible, in terms
of how he starts to formulate some of his
recommendations.
And lastly, I just wanted to mention: I think the last
meeting we discussed a trip we made to Austin, Texas, a
couple of the gas policy council members; we met with
their division of lands, learned a little bit about how
Texas takes its gas, in kind versus in value. They
take about half their gas in kind, and about half the
time make more money on it than they would in value.
We've invited an individual up from Texas to join us
September 17th, and we'd like to make him available to
you if you have an interest in that.
MR. SAMPSON commended Chairman Torgerson and the committee for
the leadership role in the legislature on the issue of oil and
gas, noting that there will be a lot of expertise. He also
commended members for going to Canada, saying he believes it will
be worthwhile. He said the council looks forward to continuing
to work with the committee as it finalizes its report to the
governor.
CHAIRMAN TORGERSON thanked council members for their comments,
noting that Mr. Bill Corbus had called him and invited him to the
meeting; however, he was in Fairbanks, so it didn't work out. He
added, "We are going to exchange data and information back and
forth." He noted that Commissioner Condon would go through some
of that at the following day's hearing. Furthermore, the
administration has made Mr. Pedro van Meurs available to the
committee, beginning with a teleconference on the 18th between
mainly Mr. Van Meurs and Chairman Torgerson, "setting down the
groundwork on where we're going to go on the severance taxes and
some of the other things." He added, "Most everything that I do,
if not all of it, I want to make public." He offered to interact
in any way possible with the council.
CHAIRMAN TORGERSON asked whether there were further comments;
none were offered.
Public Testimony
CHAIRMAN TORGERSON announced that the committee would hear
further public testimony.
KEITH HAND, Fairbanks Natural Gas, came forward to testify,
noting that Fairbanks Natural Gas is a certificated utility. He
explained that there is, indeed, natural gas in Fairbanks, with
LNG being trucked up from Cook Inlet. He said Fairbanks Natural
Gas has been widely accepted with enthusiasm from a lot of people
in the community; he mostly supports the committee's worthwhile
efforts, and would offer statements that he believes to be common
and generally representative of most residents of Fairbanks and
the Interior.
MR. HAND referred to gas available for Alaskans, not only for
heat but also for electricity. He reported that the local
utility, Golden Valley Electric Association (GVEA), obtains a
substantial amount of its power from "Cook Inlet gas, ... the
intertie." Future ancillary industries are very important to the
Interior, he said, and are being studied by a plethora of
entities; he cited Williams [Companies] and El Paso [Energy
Corporation] as two.
MR. HAND brought up a second point: availability at an equitable
price via netback pricing, tariffs, and perhaps royalty gas
tagged for in-state use; he suggested those might be solutions to
dampen any price spikes caused by Lower 48 energy crises.
MR. HAND encouraged infrastructure development prior to when a
gas line becomes available to the people. If a pipeline comes
through town and there is no infrastructure to support it, there
will be no benefit from that pipeline for several years. Just as
the pipeline will demand a high amount of "labor and brains" to
build it, so, too, will the infrastructure require that expertise
in pipeline capabilities. He concluded by saying the following:
I'd just like to leave you with the goal to unite and
conquer. Currently, there are three government
entities ... focusing on the pipeline: ... yourselves,
... the governor's policy council, and the ... three
mayors of Valdez, North Slope, and Fairbanks - powerful
mayors - have also had their own group in the [Alaska
Gasline] Port Authority; of course, they have ... kind
of a different agenda. But obviously these three
groups should have the common goal of the top three
points I've identified. And these government entities
really should stand together, I believe, provide a
united front with one another, and one strong voice
championing the best interests of the State of Alaska,
its communities, and its residents, because everyone
should be sharing the same goals [rather than] having
three weaker voices and three different groups to
approach .... Each time, it seems a bit redundant, and
I think if everyone pooled their interests, it'd be a
better product, a faster result, and a stronger group.
CHAIRMAN TORGERSON thanked Mr. Hand and asked if there were
questions; none were offered. He then asked whether anyone else
wished to testify; there was no response. He closed the public
testimony.
CHAIRMAN TORGERSON reminded members that there was a reception
sponsored by the Fairbanks North Star Borough and the Fairbanks
Chamber of Commerce that evening at 6 p.m.
CHAIRMAN TORGERSON thanked participants and adjourned the meeting
at 5:46 p.m.
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