Legislature(2001 - 2002)
01/17/2002 10:03 AM House O&G
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
January 17, 2002
10:03 a.m.
MEMBERS PRESENT
Representative Scott Ogan, Chair
Representative Hugh Fate, Vice Chair
Representative Fred Dyson
Representative Mike Chenault
Representative Gretchen Guess
MEMBERS ABSENT
Representative Vic Kohring
Representative Reggie Joule
OTHER LEGISLATORS PRESENT
Representative Joe Green
COMMITTEE CALENDAR
OVERVIEW AND UPDATE BY THE DIVISION OF OIL & GAS
OVERVIEW ON STATE OFFERING TO SELL "ROYALTY" GAS
PREVIOUS ACTION
No previous action to record
WITNESS REGISTER
PAT POURCHOT, Commissioner
Department of Natural Resources
400 Willoughby Avenue, Fifth Floor
Juneau, Alaska 99801-1724
POSITION STATEMENT: Gave brief overview, introduced speakers
from the Division of Oil & Gas, and answered questions.
MARK MYERS, Director
Division of Oil & Gas
Department of Natural Resources
550 West Seventh Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Gave overview of oil and gas activities and
answered questions.
KEVIN BANKS, Petroleum Market Analyst
Division of Oil & Gas
Department of Natural Resources
550 West 7th Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Answered questions relating to the contract
between Unocal and ENSTAR [Natural Gas Company].
WILLIAM NEBESKY, Petroleum Economist
Division of Oil & Gas
Department of Natural Resources
550 West 7th Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Offered information relating to gas
supplies in Cook Inlet.
BONNIE ROBSON, Deputy Director
Division of Oil & Gas
Department of Natural Resources
550 West Seventh Avenue, Suite 800
Anchorage, Alaska 99501-3560
POSITION STATEMENT: Gave overview addressing the state's
process for a royalty-in-kind sale in the event of a major gas
sale off Alaska's North Slope; answered questions.
ACTION NARRATIVE
TAPE 02-1, SIDE A
Number 0001
CHAIR SCOTT OGAN called the House Special Committee on Oil and
Gas meeting to order at 10:03 a.m. Present at the call to order
were Representatives Ogan, Dyson, Fate, and Guess.
Representative Chenault arrived as the meeting was in progress.
CHAIR OGAN reminded members that the legislature must approve
any sale of gas. He noted that the producers had issued a
letter [dated January 15, 2002] saying they are not in support
of such a sale at this time.
OVERVIEW AND UPDATE BY THE DIVISION OF OIL & GAS
Number 0151
PAT POURCHOT, Commissioner, Department of Natural Resources
(DNR), offered general comments as a prelude to discussion by
Mark Myers and Bonnie Robson of the Division of Oil & Gas.
Despite recent news of layoffs by some companies that operate in
Alaska, he said "we have a lot of good news in the oil and gas
industry in Alaska." He pointed out Alaska's tremendous, proven
reserves of both oil and gas, "of national scale."
COMMISSIONER POURCHOT referred to a handout, "Alaska Oil and Gas
Activities," dated January 2002. He highlighted that [Alaska]
has 36 percent of the total U.S. oil reserves, in the amount of
8 billion barrels of oil; has 17 percent of the total U.S. gas
reserves, in the amount of 35 trillion cubic feet of gas, almost
entirely on the North Slope; and is producing 20 percent of the
total U.S. oil production [the packet mentioned 1.04 million
barrels of oil a day]. Although production is greatly reduced
from earlier days, last year oil production increased for the
first time in many years. Commissioner Pourchot mentioned the
Alpine field, Northstar, and some smaller satellite fields that
are adding to the production and countering the decline in the
Prudhoe Bay field.
COMMISSIONER POURCHOT referred to the page of the handout titled
"The State Revenue Pie, Petroleum Revenue sources, (FY 2001)."
He clarified that DNR is responsible for the "royalty side of
the picture," whereas the Department of Revenue collects the
tax, particularly severance and corporate tax. Last year saw a
10 percent increase in state revenue from royalties, with about
$1.1 billion collected. While the amount of production and the
price of oil clearly have much to do with that, DNR's Division
of Oil & Gas has some very skilled, experienced people doing a
lot of the day-to-day negotiating, unit work, leasing work,
defining of lease terms, calculating of valuation, and audit of
the royalty function. Commissioner Pourchot told members that
all of those functions contribute significantly to Alaska's
getting its fair share of oil and gas royalties.
Number 0473
COMMISSIONER POURCHOT offered general remarks about the current
status of the state's royalty gas sale. He noted that in the
last legislative session, the legislature was presented with a
proposal by a group called Netricity and took a keen interest in
the possibilities of using natural gas on the North Slope for
electrical generation to run a computer server. The legislature
had passed a resolution urging DNR to look into ways of perhaps
providing gas on the North Slope for that activity, with the
mention of a royalty gas sale. He commented:
We always have the ability, under our oil and gas
leases, to take either our oil or gas in-kind, which
is to take delivery of gas or oil - our, the state's,
royalty share, about, in most cases, an eighth - and
do what we will with it. ... In the past, on the oil,
for example, we've sold to Tesoro. We currently have
a fairly large commitment of ... royalty oil to
Williams up in the Interior for [refining]. And so,
in the case of gas, we have those options also.
Otherwise, we say what we term "in-value," which is
... we just allow our royalty to be shipped along with
the producers' oil, in this case, to market, and then
we get a netback price on the sale of our oil as the
producers sell ... their oil.
Number 0607
So, beginning this summer after the session we
continued to meet with Netricity. There were legal
issues involved in just taking our gas without the
producers' gas. We urged them to talk to producers,
which they did. They began negotiations and
discussions with producers for possible gas sources on
the North Slope. We have not heard from them recently
... any further on their desires for North Slope,
Alaska-owned, state-owned gas.
However, at the same time we were hearing from
producer groups about the possibility of an open
season for bidding or nominating capacity in a
potential gas line, ... last summer it was told to us
that it could occur as early as January or February or
the first quarter of '03, today.
We also were hearing from companies who were
interested in participating in an open season who were
explorers at this time, who may not have proven gas
reserves, who wanted some ability to bid in an open
season, on the assumption that they might produce gas
or have gas available that they would want to ship
seven or eight years from now, and were interested in
the state's royalty share, bidding on that, as a
backstop for bidding gas.
We also heard from some companies interested in just
marketing gas, having gas coming through a pipeline
and marketing it into their distribution system in the
Lower 48. Also, Williams had mentioned and expressed
some interest in the possibility of utilizing royalty
gas like they use royalty oil for some potential
petrochemical development, particularly in Interior
Alaska. So, we had a number of different kinds of
interests, and we are also facing a possible open
season the first quarter of calendar year '03.
COMMISSIONER POURCHOT, noting that there is a statutory process
if the state is to sell royalty gas, told members:
It was our determination, to preserve all options,
that we should start that process this last fall,
which we did. We went through a best-interest
finding, we finalized a best-interest finding under
the Act in December, we held a royalty board hearing,
we took public comment, we took public testimony, and
... at the end of last month we went out to a formal
invitation for proposals ... that is running now and
will end at the end of January.
We don't know who ... may participate or make a
proposal. We don't know what the proposals might
consist of. But we will be entertaining those offers,
and we are not committed to making an acceptance of a
proposal. Those proposals will be available publicly.
... And as you stated, Mr. Chairman, if we were to
accept a proposal, if we were to then follow up and do
a contract with a company, that contract would be
brought back to the legislature under state law for
debate and approval - or not.
Number 0847
CHAIR OGAN asked whether Commissioner Pourchot anticipates it
will happen before the end of the current legislative session.
COMMISSIONER POURCHOT said the schedule allows for that; the
timeframe probably would be around the end of March, no later
than the first of April.
Number 0877
COMMISSIONER POURCHOT introduced Mark Myers, Director, Division
of Oil & Gas, and Bonnie Robson, Deputy Director.
CHAIR OGAN noted the presence of Representative Joe Green.
Number 0922
REPRESENTATIVE DYSON requested a synopsis regarding Cook Inlet's
present and future gas reserves. He asked whether recent
discoveries have altered that picture.
COMMISSIONER POURCHOT deferred to Mark Myers, but added that
Cook Inlet activity has increased, with "interesting things"
being found there and interest being shown by a number of
companies. He also noted that using money appropriated by the
legislature last year, [the department] has been conducting an
in-state demand study for gas; the results focus on overall
supply and potential demand for gas if there were a gas line to
the Interior, but also address questions relating to Cook Inlet.
The study's results should be finalized the middle of next week,
and [DNR] will provide this committee with copies of that study.
CHAIR OGAN complimented the commissioner on the level of
professionalism in the Division of Oil & Gas, especially in
upper-level management; he mentioned Mr. Myers and Ms. Robson.
COMMISSIONER POURCHOT expressed pride in DNR's personnel, then
expressed thanks that the legislature has been willing to
provide funding to allow an increase in salaries of some of
DNR's most seasoned, experienced professional people; before
that, the salary structure was far below the private sector's,
and retention and recruitment was difficult for key people.
CHAIR OGAN remarked that DNR's personnel still work for less
than they could receive in the private sector. He welcomed Mr.
Myers and Ms. Robson to the witness table.
Number 1128
MARK MYERS, Director, Division of Oil & Gas, Department of
Natural Resources, noted that on teleconference were other
division personnel to answer technical questions. He prefaced
his presentation by emphasizing how healthy Alaska's oil and gas
industry is, as well as noting the importance of understanding
where the division sees gas potential and how the RIK [royalty
in-kind] sale fits into the overall scheme of state oil and gas
activities.
MR. MYERS returned attention to the handout and referenced the
page titled "Historic and Projected Alaska Oil Production, 1975
- 2022." He stated:
We have some very, very good news on this slide.
Since 1988, peak production, we've seen North Slope
production fall from over 2 million down to 1 million
barrels per day. The good news is, we're actually
stabilizing and increasing a little bit of production.
MR. MYERS noted that most of Alaska's initial production was
from fields at Prudhoe Bay and Kuparuk. Although that is still
true, it is a much smaller percentage. There are new fields
coming online. Mr. Myers pointed out the significance of this
for the state. Two things have happened, he said. First, there
have been substantial exploration successes "for smaller,
subtle, stratigraphic oil traps." Second, the technology has
changed, as has the creative use of technology. The cost
structure has been driven down on the North Slope, and it now is
affordable to develop these fields, particularly near the
infrastructure.
MR. MYERS pointed out that what is needed is a major field to
anchor that infrastructure; that was Prudhoe Bay initially,
followed by Kuparuk, and now Alpine is having the same effect
nearer the NPR-A [National Petroleum Reserve - Alaska] area.
"Once we do that, we can see more exploration, and then
development, through those existing facilities of smaller
satellite fields," Mr. Myers commented. "We're seeing a lot
more oil production now coming out of satellite fields, and this
graph doesn't totally capture it all."
Number 1260
MR. MYERS referred to the next graph in the handout, "Historic
and Projected Prudhoe Bay Oil Production, 1975 - 2022." He
pointed out the decline in Prudhoe Bay production, from 1.6
million barrels a day down to the current 507,000 barrels a day;
he said Prudhoe Bay has been losing production at an average
rate of 8 to 10 percent a year, a significant loss. In order to
replace that and stabilize production, an Alpine-sized field
must be brought online every other year, or else a Tarn- or
Meltwater-type field must be brought online every year. "We're
going to be able to do that in the short term," he noted. "We
have Meltwater coming online; Northstar came online this year at
about 24,000 barrels per day, ramping up to 60 [thousand]." Mr.
Myers emphasized how positive this news is.
MR. MYERS told members that as production spreads away from
existing infrastructure and is produced in new participating
areas and new units, the overhead for management of these fields
- both for the companies and the state - is significantly
higher. Whether a unit produces 500,000 barrels a day or 50,000
a day, it often involves nearly the same amount of
administrative work.
Number 1324
MR. MYERS, in response to a question from Chair Ogan, said it is
usually geologists who name the units, starting at the prospect
level; these names typically are unrelated to the geographic
locations and often follow a theme.
Number 1401
MR. MYERS returned to the presentation and highlighted the good
news regarding the Prudhoe Bay decline: it is "flattening" and
companies are having success in finding and developing these
smaller fields. The challenge, however, is in administering
many more units, over a much broader area.
MR. MYERS turned attention to a map, "North Slope Oil & Gas
Activity and Discoveries, 2002." He emphasized that activity is
being seen over the entire North Slope. He drew attention to
the Alpine field, which is exceeding initial expectations and
now is producing almost 100,000 barrels a day. In addition,
there are two significant "satellite discoveries" to Alpine:
Nanuk to the south and Fjord to the north. Therefore, there is
potentially another 100 million barrels of surrounding
"satellite oil." Mr. Myers emphasized that once there is an
"anchor" field, there will be additional exploration and better
economics for smaller fields.
MR. MYERS highlighted a significant event this year, what he
termed a landmark agreement between the producers and the state
to expand the Point Thomson Unit; critical development targets
there need to be met, he noted, including "development
drilling." He further noted that Exxon, as the operator, has
been going through an "aggressive" permitting schedule now to
develop it, and he indicated there is a desire to see the first
oil flow from there in 2007 - 2008 or slightly later. Like
Alpine, Point Thomson is an anchor field. It also is a very
important part of a [potential] gas line because it is a gas
condensate field with an oil rim and a probable gas cap. Mr.
Myers informed listeners:
We'll see both liquids and gas potentially produced
out of Point Thomson. The current plans are gas
cycling, where they leave the gas in the ground and
produce only liquids, but it's likely that we will
see, in a gas-line scenario, gas sales coming out of
Point Thomson. That will prove as an anchor. Not
only will that produce ... the 300 million barrels of
... liquids, but also, potentially, up to 8 tcf
[trillion cubic feet] or more of gas coming out of
that field. A very substantial portion of the North
Slope gas reserves are there. [It's] very good news
that now we're moving forward with development through
... an aggressive permitting schedule, and we have
solid commitments toward development.
Number 1518
CHAIR OGAN asked how far east the current infrastructure exists.
MR. MYERS answered that it currently goes as far as Badami,
which has an underutilized oil line that probably will play a
significant role in the development of Point Thomson. The "very
good news" is that it will open up more exploration for
satellite [fields]. There are many known "satellite
accumulations" surrounding and internal to the Point Thomson
area, he noted.
Number 1544
MR. MYERS pointed out the amount of exploration activity: 12 to
13 wells expected to be drilled this year on the North Slope,
with 5 of those to be operated by Phillips in NPR-A, working
both on the successes they've had up to this point in terms of
delineation of commercial reserves and on new exploration. He
stated, "They have announced an Alpine-like equivalency ... in
gas, oil, and condensate. So it's very positive news in the
effort in NPR-A." He added that the state took a significant
role, early on, in addressing federal concerns about having a
lease sale. One role of the division, he pointed out, is
advocacy for responsible oil and gas development, whether in
NPR-A or ANWR [Arctic National Wildlife Refuge].
Number 1586
MR. MYERS continued, noting other exploration activity south of
Kuparuk, one on "Artic slope land" and one on state land in the
central foothills, also operated by Phillips. He added that
Anadarko is "branching out" and will drill a separate, dedicated
well in NPR-A. He said it is "very good news to the state to
get as many operators drilling as we can," because it increases
competition, capital, and the likelihood of successful
exploration.
MR. MYERS referred to offshore areas, noting that north of the
Prudhoe Bay Unit is the McCovey prospect; he indicated DNR hopes
to see an exploration well drilled offshore there this winter or
next winter. Another significant event has been that Alberta
Energy Company Ltd., a relative newcomer to the state, is going
to operate that well.
MR. MYERS highlighted another positive event: BP [Exploration
(Alaska) Inc.] is going to operate a well for Alaska Venture
Capital Group to the north of Prudhoe Bay. This is another set
of independents who got together, formed a consortium, and are
going to drill on the North Slope, Mr. Myers told members. He
said the department's effort to try to assist "in every way we
can" to get these independent companies and other competition on
the North Slope "is an extremely important part of our job." He
added:
We take it very seriously, and we're seeing some
success. And that is particularly important when you
have major companies like BP pulling most of their
exploration capital out of Alaska. So, we're trying
to balance and backfill the vacuum. I think the
commissioner showed you, on the front end, it's very
positive that we have very good geology and very high
potential. That's our number-one selling point it
comes down to, and a very prolific oil basin and gas
basin on the North Slope.
Number 1655
MR. MYERS turned attention to Cook Inlet, noting some highly
positive developments there. In particular, Unocal, Marathon
[Oil Corporation], and Forest Oil [Corporation] have stepped up
activities for gas exploration. He indicated four new
exploration units have been formed in Cook Inlet. Cosmopolitan,
noted on the map in the handout, is being used for oil
exploration by Phillips, he noted, which is currently drilling a
well there. Mr. Myers also mentioned the Deep Creek, Ninilchik,
and South Ninilchik Units, just recently formed with Unocal,
Marathon, and CIRI [Cook Inlet Region, Incorporated] "in various
portions in various units"; those are exploration units for gas.
Furthermore, Unocal had reached a "pretty lucrative contract for
gas" with ENSTAR [Natural Gas Company], which "spurred a lot
more desire, higher price levels, it is believed, and ... a lot
more exploration for gas in Cook Inlet."
MR. MYERS said the primary oil success to this point has been
"Forest Energy - Redoubt Shoals." He explained:
They had a small, known oil accumulation that took a
fair amount of substantial risk to go in there and set
an actual platform before they'd delineate sufficient
reserves. ... They're drilling a fourth well now.
They've announced 50 million barrels recoverable,
which makes it an [economic] project with a
significant upside, perhaps as high as 190 million
barrels. So, major new oil production you can expect
out of Cook Inlet - very good news on oil, very good
news on gas.
Number 1720
MR. MYERS reported that there is an open season proposed now by
Unocal for a gas pipeline going as far south as Homer. He
commented, "You may see not only more gas produced to the north,
but actually local energy supply down to Homer, out of this
exploration, should it be successful."
CHAIR OGAN asked whether there is a possibility that the open
season will be extended later.
MR. MYERS answered that the pipeline systems under "common
carrier" - oil pipelines, basically - involve a nomination
process that goes on continually. Gas pipelines, in contrast,
are typically called "open-access pipeline." There is a front-
end open season during which people commit to capacity on that
line, and the line is then built to those specifications. If
the pipeline company so chooses, it can build additional
capacity on the line, based on the belief there will be
additional customers later on. The company can "preplumb for
expansion without actually having expansion occur early on," and
there are many different options. That commitment to ship gas,
however, controls the size of the development of that pipeline.
"It also has to be backstopped with sufficient reserves to be
financed for a certain period of time to get approval," he
added.
MR. MYERS further answered that the second part of the equation,
should additional gas be found, is that people can go to that
pipeline company and request that the pipeline be expanded.
Expansion could take place through "looping" the pipeline -
adding pipe in critical sections - or by increasing compression
capacity; in that case, the pipeline [company] must decide
whether it is going to expand. Generally, if it's in the
pipeline company's economic interest, it will expand the
pipeline. "There could be multiple open seasons," he concluded,
"but that ... capacity in that pipeline's geared toward the
initial nomination in that first open season."
Number 1819
REPRESENTATIVE DYSON mentioned a study done by a distributing
company indicating the supply could be vulnerable in the 2007 -
2009 timeframe. He asked whether that has been pushed back or
otherwise changed.
MR. MYERS noted that the results of the exploration drilling
have not been made public, but said [the timeframe] could be
pushed back, depending on the results. The two issues are the
amount of available gas and how that gas is used. There are
three major [uses] currently: the local energy market, which is
the highest value per mcf [million cubic feet]; the export of
LNG [liquefied natural gas]; and "the fertilizer market, the
market for Agrium."
MR. MYERS said the lower-paying part of the market would suffer
first, depending on how that gas is allocated to those various
resources; it depends on the length of that vulnerability
period. A further element is whether there will be additional
usage and what the increased amount of demand will be; that is
what a demand study will address, in part, which [should be
available] Wednesday. Should these discoveries be successful,
he added, "we can be assured that that date will be pushed back
if existing use and reasonable expansion is taken into account;
how far, we won't know until we see the reserve results."
Number 1882
CHAIR OGAN recalled hearing that in 2003 there will be some peak
loads.
MR. MYERS replied that there are two issues. First is overall
demand on a yearly basis; at certain times in winter the local
energy use increases dramatically, and the question is how to
meet peak demands. One of the big "drivers" to meeting peak
demands is a price structure that rewards the providing of gas
during those peak periods. He commented, "I think we have a
market-driven structure now, ... with the higher gas prices."
He noted that although local consumers pay more for gas under
those contracts, [the higher price] spurs exploration and
development of additional resources, and it creates additional
capacity in the system.
CHAIR OGAN suggested that higher prices are tied to the "Henry
Hub" to some extent.
MR. MYERS noted that Kevin Banks could address specific details
of ENSTAR's contract, but said basically it is tied to a floor
price and then is indexed to Henry Hub.
Number 1935
KEVIN BANKS, Petroleum Market Analyst, Division of Oil & Gas,
Department of Natural Resources, added via teleconference, "The
most recent contract that we are aware of between Unocal and
ENSTAR provides for a Henry Hub index. It starts at a $2.75
floor, and the Henry Hub index is indexed over a three-year
moving average."
Number 1950
REPRESENTATIVE DYSON surmised that Alaska has no secure gas
supply for future, expanding industrial use; furthermore,
existing fertilizer and LNG uses are in some ways vulnerable in
the near term.
MR. MYERS answered, "I don't think in the near term, but in the
long term." He mentioned that there are some management issues,
but cited positive developments including shallow gas, potential
coal-bed methane, additional exploration, and exploration
licensing in areas that are "predominantly gas." He said the
first response to the need for gas is to "turn up the hunt for
supply." He added, "We're seeing that in a lot of different
areas. So I think we can find more gas. How do you quantify
that? It's difficult, but I think potentially that day could be
pushed back significantly." He noted that Will Nebesky was on
teleconference to talk about current usage "and when we see
needs for ... peak-demand gas versus long-term supply issues."
Number 2002
WILLIAM NEBESKY, Petroleum Economist, Division of Oil & Gas,
Department of Natural Resources, told members one way to look at
it is that industrial uses of gas have some "exposure" if new
reserves are not brought online in Cook Inlet. He agreed that
higher prices for gas are probably on the horizon for all Cook
Inlet gas consumers. In terms of annual deliverability to users
in Cook Inlet, he said "it does become an issue sometime around
2005." He added:
Basically, it would take about another ... 1-tcf
discovery of gas, which would add the current
approximate 2 to 2-and-a-half (indisc.) of existing
reserves in Cook Inlet, would push those
deliverability thresholds out about five years; that
is, a tcf would probably extend the demand-supply
balance problems out about an additional five years
from the existing point where demand and supply
balance (indisc.) becomes an issue (indisc.).
Number 2070
REPRESENTATIVE DYSON suggested that after [the committee]
receives the demand study, members should reconvene on this very
subject. He then asked whether the new concerns about homeland
security [following the September 11 terrorist attacks] are
having any impact in Cook Inlet. He noted that there was a
harsher "ice environment" in the upper inlet than before; he
asked whether there were any concerns there.
MR. MYERS noted that Commissioner Pourchot is on the committee
for homeland security in Alaska. He said there are two thrusts:
the state's issues and the military response. However, he said,
he didn't know in detail what the concerns were. He
acknowledged that "point sources" like LNG plants are of
concern, and he reported that the companies have increased
security and that the state has been looking at it. As for how
it affects exploration and development, he concluded that "we
haven't seen any significant effects to it."
Number 2108
REPRESENTATIVE DYSON remarked that in Valdez there is an
"exclusion zone" around the port, and he mentioned the U.S.
Coast Guard. He stated his understanding that there hasn't been
any of that in Cook Inlet.
MR. MYERS answered, "Not to my awareness, but we're in very
close proximity to those F-15s at Elmendorf on alert, so that's
some comfort. ... We certainly have the military force to
respond." He added that he wasn't the right person to explain
the details.
CHAIR OGAN announced that there would be an overview by
Evergreen Resources, probably at the end of the month.
MR. MYERS said [the division] would be happy to present the
results of the demand study to the committee, if the committee
so desires.
Number 2137
MR. MYERS added:
What DNR can do for you is to make sure our leasing
program - our unitization issues - work as smoothly as
possible, and to accelerate exploration and
development. We definitely have some budget issues
with dealing with the issues, and I know we have some
potential changes we might recommend to the shallow-
gas leasing program to help stimulate and bring on
more gas. We think these programs are important
elements to stimulate more gas for Cook Inlet, as well
as making sure ... that the exploration promises the
state makes, in terms of ... our speedy unitizations
and permitting, take place.
Number 2176
MR. MYERS brought attention to the next "slide" in the packet,
which shows the areawide leasing schedule. Noting that there
has been an increase to four areawide sales per year, he
suggested it shows that the division "delivers what it
promises." The sales typically are held in October and May,
with two sales at a time; the next sale is scheduled for May 1.
There will be four sales [a year] into the foreseeable future.
Number 2187
MR. MYERS turned attention to a graph titled "Cumulative Bonus
Bids." He noted that cumulative bonus bids, over a period of
time, bring a substantial amount of income to the state. Last
year, for example, the sales brought in about $25 million.
Although the major "driver" is royalties, there is "real money"
to the state treasury in the leasing process itself.
Number 2201
MR. MYERS brought attention to the page titled "2001 Areawide
Lease Sales." He remarked that the North Slope foothills sale,
in the "gas-prone area," had the largest amount of state acreage
- almost a million acres for 170 bids - ever sold in a sale. He
commented:
One of the important aspects is we were able to
diversify our base of resale participants. We have
Burlington Resources, Petro-Canada involved, Unocal,
Albert Energy, Anadarko, as well as Phillips. So
we're ... starting to be able to diversify [the]
industry base, which, again, is a critical component
to ... having a healthy industry.
MR. MYERS referenced the North Slope sale highlighted on the
same page; he noted that Shell had bid on that and remarked,
"It's tremendous to get another ... competing 'major' up there -
a high-quality company like Shell." He also noted that some
successful "independents" have come in; in the case of Alaska
Venture Capital Group, some have even drilled a well on the
North Slope. He emphasized that a major part of the division's
job is not only working to diversify the industry, but also
"getting quality companies up here."
Number 2247
CHAIR OGAN asked Mr. Myers whether he foresaw any problems with
operating up there, since "the big three" [producers] operate up
there. He asked whether that is going smoothly.
MR. MYERS answered:
I think there's always large commercial issues in
facility-sharing agreements that need to be ironed
out. ... I'd like to see the state take a proactive
role in the process and support that facilities get
used to their maximum, that facility charges are
reasonable. But ... those are primarily commercial
negotiations between the parties.
The state has limited authority to do something about
it, but it is an area of concern, to make sure that
independents are ... treated fairly [and] the playing
field is level. I think that's what the state can do,
one thing that's crucial. It's all it can do to
assure that everyone has fair access, whether it be to
pipelines, oil, or gas, or whether it be to processing
facilities.
Number 2283
CHAIR OGAN asked whether there is a statutory reference to that.
MR. MYERS answered that basically the unitization statutes deal
with [DNR's] ability to expand units when necessary, to maximize
production and use of facilities. A lot depends on the
"interconnectibility" of reservoirs and exploration processes.
It is very difficult to "force-unitize" an area unless the
geology suggests it is appropriate for unit expansion to occur,
because of reservoir management issues.
MR. MYERS emphasized that the state must be highly aware that in
order to get more companies on the North Slope, access to the
existing infrastructure is of critical importance. That
includes exploration rigs and permitting expertise, for example.
One thing the state can do positively is to educate, "spending
time with these folks in the permitting process, [and to] have a
clear, level, understandable permitting process to go forward,
in all cases." In addition to education, the state certainly
can process applications as quickly as possible in order to
accelerate development and eliminate uncertainty. To that end,
[DNR] is asking in the budget for an additional
"permitter/inspector."
MR. MYERS cited some successes, including Meltwater, which
proceeded from discovery to production within two years; he said
that is "remarkable" and is a credit to both Phillips and the
state. Some areas, however, perhaps more environmentally
sensitive, present major challenges. He restated the importance
of DNR's helping people understand the "playing field" and doing
what it can to assure people of access to facilities.
Number 2354
MR. MYERS, in response to a question from Representative Green
about the cooperation of state and federal agencies, said:
I think that level of cooperation varies at different
times. I think the other agencies are well-
intentioned. I think there is coordination through
DGC [Division of Governmental Coordination] at some
level. We have to remember, though, that other
agencies have very different statutory requirements,
and they have to honor those statutory requirements.
... [The Alaska Department of] Fish and Game, for
example, whose job is to protect the habitat --
certainly you can't develop oil without some habitat
disruption. So right there, there's always going to
be room for conflict and negotiation about what's
reasonable.
So I think the ability to do that depends on several
things, [such as] the willingness of the agencies and
the individuals in the negotiation. It also depends
on [the] funding level for those organizations as well
as ours. So overall we encourage cooperation, and ...
certainly at the governor's level I've seen ... a
strong desire to see this accelerated oil and gas
development.
Number 2405
MR. MYERS referred to the next page in the handout, "Oil and Gas
Leases Sold." He highlighted the long-term trend since 1996 of
an overall increase of leases sold. He noted that the areawide
sales are helping greatly, and added that "our ability to
administer the program is incredibly important."
MR. MYERS turned attention to the next page, "Leases Issued."
He pointed out the huge overall increase, despite a couple of
"low" years. He highlighted the large number of leases issued
last year [2001] and the number of shallow-gas leases. He noted
that the new programs coming online are a challenge because
[DNR] hasn't increased staffing in order to deal with either
shallow-gas leasing or exploration licensing.
MR. MYERS referred to the next page, a series of maps titled
"Shallow Natural Gas Leasing Program." He noted that these are
primarily in the Matanuska-Susitna area and in the Big
Delta/Fairbanks area, with a few leases in the Red Dog area, as
well as some in the lower Kenai Peninsula. With these shallow-
gas leases, he remarked, "we've seen a pattern that suggests
that the primary use of these leases will be for commercial gas
development - again, important to Cook Inlet and the users down
there, but also a program that we think needs some modification
into ... a more commercial-related program." He expressed the
hope of seeing some legislative changes to that effect.
Number 2453
REPRESENTATIVE DYSON asked whether the administration would
produce legislation this session regarding that.
MR. MYERS answered:
The administration won't, but ... we're hopeful that
the legislature will have ... a friendly approach to
this. We have some suggested language that we're
working through a few legislators to see if they're
willing, but as of yet we don't have a sponsor.
MR. MYERS emphasized that the program is about three times as
active as in the past. One consequence is it takes longer to
issue leases - now 12 months on the average. This slows
exploration and development on these leases, and it causes
delays.
TAPE 02-1, SIDE B
Number 2481
MR. MYERS indicated DNR has a $500,000 proposal to solve that
bottleneck; it would allow DNR an additional inspector/permitter
and a reservoir engineer. "We think, again, this is a
moneymaking proposition for the state," he told listeners. "And
we can demonstrate that."
MR. MYERS referred to the next page in the handout and said to
the department's credit, DNR can routinely put out four sales a
year despite a very small staff; he credited DNR's lease-sale
personnel. Saying the process is "somewhat torturous, but
necessary," he told listeners:
There are a few critical bottlenecks in that process,
and that's what we're looking at for the increment.
So we're targeting specific positions in areas we know
will speed up the process. So we're not just asking
for money, but we're targeting it very, very
specifically. And we recognize that we've streamlined
the process as much as we can, and to that end, I
think we're having quite good success. But ... it's
good news/bad news. ... We're a victim of our own
positive success in the lease-sale process.
Number 2441
MR. MYERS brought attention to the next page of the handout,
"Title Work." He highlighted the significant amount of new
title work [required] because of the new programs - the
exploration licenses and the shallow-gas leasing. In some
cases, he noted, those [new programs generate] the majority of
DNR's title work from year to year. "We expect that majority to
continue," he added.
Number 2414
MR. MYERS noted that he would skip over the pie chart on the
next page [titled "New Shallow Gas Leasing & Exploration
Licensing Programs Dramatically Increase Division Workload"].
MR. MYERS turned attention to "Lease Assignments in Alaska." He
told listeners that one important element is that once [DNR]
issues a lease, the department has a need to administer it. He
mentioned reorganizations; mergers; "new independents"; leases
being transferred and reassigned; and the workload over time,
going up dramatically. He remarked, "Again, within that
$500,000 increment is a position for lease administration to
deal with that issue."
Number 2401
MR. MYERS addressed the next graph, "Unit Actions." He pointed
out the long-term upswing in "unit actions" over six years, with
a fourfold increase from 1995 to the present. He commented:
We expect this to fully continue. We formed seven new
oil and gas units this last year, which are the core,
basic units for exploration and development. We
formed four new participating areas, which are the
core elements for production. So now ... the state
has 42 separate oil and gas units and 54 participating
areas for production.
MR. MYERS turned attention to the next page, "What Are The
Common Lease/Unit Administration Actions?" He informed the
committee that once the units and participating areas are
created, these are the basic building blocks of how [the state]
gets its royalty revenue. These are extremely important,
complex agreements. He explained, "We use a commercial asset
team of geologists, geophysicists, engineers, petroleum land
managers, commercial analysts, with assistance from the
Department of Law, to create and administer these units. These
are really big deals." He lauded division personnel - enough
people for one asset team - for the ability to manage 42 units;
he added that the [Division of Oil & Gas] personnel listening on
teleconference deserve a lot of credit for this.
Number 2352
MR. MYERS referred to the next page, "Different databases and
data managed and merged to create 3-D [three-dimensional]
pictures of oil fields and royalty share." He reported that as
technology has evolved, the division has strived to "keep in
place with the latest and current technology." Last year, he
indicated, the legislature provided money for 3-D seismic
[technology]; he said he would show the committee how that money
has been used, if there is time during the briefing.
MR. MYERS pointed out that in order for DNR to interpret what
the state's royalty share in the subsurface is, as well as "what
our vulnerabilities are in these negotiations," that data must
be integrated with engineering data; with seismic data; with
geophysical data from wells; with geological data; with core
data; with current geographic databases; and with the lease
ownership position, which is constantly changing and evolving
with each lease sale [because of] ownership changes and shifts
by companies. The division does that. It has a series of
digital databases that integrate into a main section.
MR. MYERS told members, "This is one of our successes, that we
have to duplicate what an oil company does in order for us to be
effective in our management and negotiation. And I invite all
of you, at this time, to come into the division to see how we do
it." He noted that Chair Ogan already had come to the division
MR. MYERS reported that one of [DNR's] critical weaknesses is
lack of enough engineering support. He added, "We clearly need
a dedicated, modern, current reservoir engineer to integrate
into our staff. And in that $500,000 request ... the last
position is a reservoir engineer."
Number 2285
MR. MYERS turned attention to the next page, "Gas Cap
Mechanisms." He said another reason [DNR] needs quality
reservoir engineering support is that anytime there is a major
change in reservoir management - such as a potential gas sale at
Prudhoe Bay - the effects are huge. He explained:
They affect us in terms of royalty. They affect us in
terms of proper management. We share information on
these issues with the AOGCC [Alaska Oil and Gas
Conservation Commission], but we still need to have
internal expertise on managing the effects to the
reservoirs. We also need a determination of what the
producible part of the oil is, based on royalty tract
variation.
So, again, we have a lot of sensitivity as to not only
that oil is ... correctly produced, but the state
receives its fair share of royalty because of the
allocation of that production from various ... leases.
MR. MYERS turned attention to the page titled "PBU [Prudhoe Bay
Unit] Mechanisms." He described the reservoirs as "almost
living, dynamic organisms." If one thing changes, it changes
everything in the reservoir. Understanding that and adjusting
to it is a very needed specialty within the engineering
profession "that we badly need to get some more assistance on."
Number 2234
MR. MYERS turned to the next graph, "Seismic Data Status, 1990 -
2001." He told legislators:
You gave us money to acquire additional -- we had a
huge backlog in 2-D and 3-D seismic, which is critical
for interpretation. The line in red and green shows
you just how much data we collected with that
incremental money: we collected over 10,000 miles of
2-D and over 2,000 square miles of 3-D data. And we
[collected] very little of that in the past. So we
said that was a critical component of capturing that
data before we lost it, and the state has a right, via
permit. We went back, took that money, and got
aggressive on collecting this critical seismic data.
Number 2214
MR. MYERS referred to a page titled "C35-T4.1 Window Far Offset
Maximum Amplitude," which he said was provided with the
permission of Phillips Alaska. He noted that it shows 3-D
seismic [data] over the Meltwater discovery. He emphasized how
incremental the picture is, as well as how critical that
[information] is in all aspects of exploration on the North
Slope, in development and in equity determinations. He
concluded that capturing that data upfront, for the state, pays
huge dividends in all aspects of business.
MR. MYERS turned attention to the page titled "Layered lobe
deposits consisting of waning flow high-density turbidities."
He commented:
You gave us ... some money for doing geologic
fieldwork, to analyze ... potential supply in the ...
North Slope foothills. We dovetailed the money we got
to work with the state survey and geologic field
studies. So another element in the foothills, in
particular, is integrating surface geology, in
addition to the subsurface information. ... This is
information we can make public, which is very useful
in the process of promoting and getting new companies
... up on the North Slope. It helps us in our
analysis. So it serves multiple ... functions.
I'd like to commend, too, the work the state geologic
survey does on the North Slope as an integral part of
this ... effort to promote understanding and
development of North Slope resources. ...
We work as closely as we can with the [Alaska] Oil and
Gas Conservation Commission so we don't duplicate
effort on issues. ... Sometimes statutorily we're
required to be separate, but when we can compare
notes, work together, and share expertise - and where
we have common interests - we do. And I'm very
pleased with our relationship with the AOGCC at this
point in time. I think it's a credit to the
commissioners and to the staff ... that our good
working relationship is there.
CHAIR OGAN recalled that it wasn't always so; he said it is good
to see.
MR. MYERS noted that some money for gas-line studies was joint
funding. For example, [the legislature] gave DNR $50,000 for
part of a larger study on reservoir mechanisms for which the
AOGCC is trying to get $500,000. He added, "We haven't spent
the money until AOGCC gets coordinated. We wanted to spend it
jointly, to get the maximum value from the studies. That's an
example of the coordination. We also do a lot of data
coordinating on information." He mentioned creating digital
files together as an example.
Number 2120
MR. MYERS reported that another weakness in DNR is the ability
to analyze commercial pipeline terms. "We badly need a
commercial analyst to look at pipelines," he noted. For an
explanation, he referred to the page of the handout titled
"Alaska Regulated Pipelines"; it shows that the number of
regulated pipelines in which the state ships royalty gas is
increasing dramatically. For example, in 2002 there are 16
different regulated pipelines. The reason is that exploration
and development take place increasingly farther away, requiring
interconnecting pipelines.
MR. MYERS explained that this is important to DNR and the state
because the royalty value - and to some degree, the tax value -
is based on netback value. Transportation costs are subtracted
from what [the state] receives as its royalty share. It is in
the state's interests, therefore, to pay as little in
transportation costs as possible.
Number 2070
MR. MYERS referred to the graph titled "Projected Pipeline
Tariffs as a Percent of ANS [Alaska North Slope] Wellhead
Price." He said as the Trans-Alaska Pipeline System (TAPS)
ages, as its throughput decreases, and as additional pipelines
are needed to get gas to market, "our cost of tariffs, versus
our royalty value, is going up dramatically." Now at 20
percent, it is projected to rise to more than 30 percent in the
relatively near future. Therefore, he said, the state needs to
negotiate and understand its commercial position "so that when
we are represented before regulatory agencies that set rates, we
understand our commercial position that, then, the Department of
Law will negotiate for us."
MR. MYERS explained DNR's need for a full-time specialist.
Having such a specialist would bring [the state] a lot more
money in "on the tariff issue," he suggested. He pointed out
that one penny per barrel on TAPS is equal to about $800,000 a
year to the state. He added:
It's reasonable the state pay its fair share of costs.
We just have to make sure that that's exactly what we
are paying in these negotiations. So, in many of
these pipelines, the pipelines are owned by the
producing companies, and we are a paying client on
those pipelines, in effect. So, again, commercially,
it's a very important part of our asset team to ...
include this expertise....
CHAIR OGAN suggested a pipeline company has a lot of incentive
to keep the costs up, then, because they are subtracted from the
netback, resulting in less royalty.
MR. MYERS responded:
Any good business has a desire to maximize their rate
of return ... and it's our incentive to pay the
minimum tariff that's reasonable. So therein is a
commercial negotiation, or at least ... a commercial
understanding of the position, so when those tariffs
are negotiated before the proper regulatory [agency],
the state fully understands its commercial position.
Number 1968
MR. MYERS turned attention to a page depicting seismic data
"over ANWR," prepared by the United States Geological Survey
(USGS). He reported that the Division of Oil & Gas has taken an
active role in promoting the opening of ANWR [to exploration and
drilling]. For example, he made five or so trips to the North
Slope with various groups last year, and he and staff have
participated in national debates, addressed congressional
delegations, and provided key support to Arctic Power [a
lobbying organization that receives money appropriated by the
legislature for the opening of ANWR]. He added that even
national publications like The New York Times have used [DNR's]
graphics to develop "frontline articles" and illustrations. He
credited the cartographers, in particular, as well as others
including technical experts who testify. He said:
I've been told by congressional delegations, time and
time again, what's of extreme value that comes out of
the Division of Oil & Gas is that ... we have the
technical expertise to back up, we've done the
geologic fieldwork, we have the engineering expertise,
we have the leasing background. So when we speak,
generally, we seem to have a fair amount of
credibility before those congressional delegations and
before our key business leaders. ...
We have permitted ... so many oil and gas developments
in sensitive areas, we have credibility there. ... It
doesn't always get recognized, but these folks in the
division - our technical experts - get called on a lot
to testify or to provide information to key government
officials and ... even to Arctic Power and certainly
to industry groups.
Number 1894
CHAIR OGAN pointed out that the USGS data was from 1984 to 1985,
the Dark Ages as far as seismic work goes.
MR. MYERS noted that the data is shown as a 2-D grid of
relatively low-quality data, compared to that of modern times.
Modern 3-D [seismic data] clearly is needed for a full
assessment. In response to a comment from Chair Ogan, he noted
that it would take congressional action in order to allow such
an assessment of ANWR and to determine the actual reserve
potential there. On the other hand, if there were leasing now,
the first activity of a company would be "shooting 3-D seismic"
in order to assess value.
MR. MYERS emphasized the necessity of 3-D data. He pointed out
that exploration successes have risen on the North Slope, from 3
or 4 percent to about 40 percent. In addition, a 3-D shot
allows one to customize and target facilities ahead of time; he
cited Meltwater as a classic example of that, indicating there
was little waste of effort or disturbance of the tundra beyond
that absolutely necessary for development. "So it's a great
tool in minimizing environmental impact and for adding geologic
certainty," he concluded.
Number 1817
MR. MYERS referred to the next page, "Division of Oil & Gas
Organizational Links Affect the Bottom Line." As an agency, the
division recognizes the need to mimic an oil company-type
structure, with an access team, he said. The weakest links are
engineering and some areas of commercial analysis; those need to
be strengthened. Overall, however, the system works well. He
expressed pride in the division's personnel and their ability to
negotiate these highly technical issues with a high level of
professionalism.
MR. MYERS brought attention to the page titled "Recent Dynamic
Changes in Alaska's Oil and Gas Business REQUIRE a
Transformation of the Division of Oil and Gas." Referring to
budget requests from the previous year, he noted the need to
retain highly skilled people; he thanked [legislators] for their
support on that.
MR. MYERS reported that the biggest challenge in the future is
not so much in the exempt professional ranks; rather, it is in
the "professional, union, natural resource manager-officer
series" and other series. He expressed the hope of seeing some
changes in the way that structure is created, "in terms of
having a professional technical ladder that is equivalent to the
management ladder for these nonexempt employees." He added, "We
think that's absolutely critical for us to maintain high-quality
staff"; he cited permitting personnel, lease-sale personnel, and
highly skilled natural resource officers as being especially
important in this regard.
Number 1731
MR. MYERS addressed the last page of the handout, "Alaska's
Onshore Basins." He emphasized that Alaska's potential isn't
limited to just the North Slope, particularly for gas. He said
for early exploration in the Interior basins, for the most part,
the biggest problem was "oil-source-prone source rocks." The
strong evidence was that many of these basins had "very strong
gas-prone source rocks"; he mentioned "coals" and other rocks,
as well as "thermal maturities that are higher in some of the
more oil-prone rocks, which would have generated gas." He
stated:
We believe there's a lot of potential in the Interior
basins, and certainly a lot of potential in North
Slope foothills. I think access to that potential is
one of the issues that is important in the southern
[gas] line consideration. It's also a very important
consideration that when a gas line gets built, that we
have access, that other parties that are exploring can
get access to the transportation system - for without
transportation, there is no exploration. ... No one
can expend the millions of dollars it takes an
exploration program, and the hundreds of millions it
takes to put major developments online, if they're not
going to have reasonable assurance they can get into a
pipeline system.
MR. MYERS continued with concerns about access, noting that gas
pipelines work differently from oil pipelines. He stated:
One of our major concerns in DNR is a viable, long-
term industry for oil. And as we see the oil maturing
in the ... long-term future, we see gas taking over.
... There's a history of that, whether it be in the
Alberta basin or other basins that are mature. It
goes through a cycle of oil exploration followed by a
major cycle of gas.
[Looking] at a long-term perspective of Alaska's oil
and gas industry, the gas starts growing bigger and
bigger as an element. And to do that, again, it's
absolutely critical that if we get only one
distribution system, which is the most likely
scenario, that that distribution system has reasonable
access so we can continue the exploration process that
we are so encouraged about today, based on leasing
patterns, based on new companies coming in.
MR. MYERS concluded by saying the concern about the access issue
and open-season timing of the pipeline was one major reason for
the timing of the RIK [royalty-in-kind] sale that [Ms. Robson]
would talk about. Obviously, he said, "you have to get the
system built." He advised members that the importance of having
that system provide fair, level access cannot be overestimated.
OVERVIEW ON STATE OFFERING TO SELL "ROYALTY" GAS
Number 1631
CHAIR OGAN turned attention to the overview regarding the
state's offering to sell royalty gas. Noting time constraints,
he suggested there could be another hearing in a week in order
to address royalty-in-kind issues in more depth. He asked that
members hold questions until that time.
Number 1580
BONNIE ROBSON, Deputy Director, Division of Oil & Gas,
Department of Natural Resources, referred to a handout titled
"Alaska Royalty-In-Kind Gas Sale," prepared by the division and
dated January 2002. She noted that she had been asked to
address the state's process for a royalty-in-kind sale in the
event of a major gas sale off Alaska's North Slope.
MS. ROBSON discussed information on the first page of the
handout. She explained that "royalty" is a share of oil and gas
production; it is reserved for the state at the time that an oil
and gas lease is issued by the state. Typically, it is one-
eighth of production (12.5 percent), but there are instances in
which it is one-sixth (16-2/3 percent) or one-fifth (20
percent). This royalty share reserved for the state may be
taken in-value or in-kind.
MS. ROBSON explained royalty taken in-value. It simply means
that the production is left with the producers, who take [the
state's] share - typically 12.5 percent - to market along with
their own 87.5 percent share. It is marketed, therefore, as an
undivided 100 percent of production; [the producers] then pay
the state 12.5 percent of the net proceeds or the market value
of that gas or oil, whichever is higher.
CHAIR OGAN requested confirmation that it is the netback on the
wellhead price.
MS. ROBSON affirmed that. She then explained royalty taken in-
kind. Under this option, the state physically takes possession
of the oil or gas in the field and sells it, then and there, to
a buyer; this is typically done under a contract of some
duration, made well in advance of the time when the state
actually takes physical possession of the oil or gas.
Number 1501
MS. ROBSON informed members that the abbreviations used for
royalty in-kind and royalty in-value are RIK and RIV,
respectively. She pointed out that the state's right to take
its royalty share in-kind or in-value is a term of the lease
agreement. It is also the lease that allows the state to switch
between taking its royalty share in-kind or in-value.
Typically, that switch can be made on six months' notice; often,
however, the actual switch is done with much more advance notice
than six months.
MS. ROBSON turned to page 2 of the handout. She reported that
this right to take royalty in-kind or in-value, and to switch
between the two, has been a term of every oil and gas lease
issued by the state for more than 40 years. The state believes
its right to take oil and gas in-kind, and to switch between in-
kind and in-value, is a valuable asset owned by the state.
Number 1441
MS. ROBSON explained three reasons the state sees the
aforementioned as valuable [page 3 of the handout]. First, in
lieu of taking gas in-kind, for example, the state may simply
leave it in-value with the producers, who then sell it. The
producers are on a self-reporting system for what the proceeds
and market value of that gas would be. If the state has any
reason to believe the reported numbers don't accurately reflect
the actual value of the gas, [the state] has a couple of
alternatives. One, it can audit the producer - which it does,
although it is an after-the-fact method that often cannot assure
the certainty of catching every possible inaccuracy in
reporting. Two, it can simply decide to take its royalty share
in-kind; it then can offer that gas to the market, to see what
price the market will pay for it. It is a mechanism to ensure
that the state is capturing the full value of the oil or gas.
MS. ROBSON explained a second reason. There may be an in-state
buyer or user of gas who is willing to pay market value for that
gas and yet is unable to find a producer willing to sell it.
That might happen, for instance, if the buyer is also a
competitor of the producers. In that case, the state could step
in and sell its royalty share, or some portion of it, to ensure
that there is, in fact, in-state access to gas.
MS. ROBSON offered a third reason. It is an opportunity to
capture premium value for the oil or gas. This frequently would
happen because the state may be willing to offer its
hydrocarbons on terms that are somewhat different from the
industry standard. For example, if a buyer seeks a long-term
supply of oil or gas, but the marketplace isn't willing to offer
long-term contracts for that oil or gas, the state may be able
to "sell for a long term but capture additional value or some
premium on price because it is willing and able to offer terms
other than industry provides." She noted that it has happened
in Alaska repeatedly in the context of oil. She gave an
example:
We do have two large, major refiners, as well as a
smaller refiner, in-state. And both Tesoro and
Williams and their predecessor have been long-term
purchasers at one time or another of the state's
royalty share. And that ... certainly has contributed
to their success as in-state industry and the
providers of in-state jobs and income and tax
revenues.
Number 1271
MS. ROBSON referred to page 4 of the handout and asked: Why
conduct a royalty-in-kind sale for gas now? She emphasized that
the administration hasn't made any decision to sell [the
state's] gas; rather, it has decided to preserve the option to
do so. She noted that a number of factors have resulted in the
administration's having a request for proposals "on the street"
now for [the state's] royalty share in the event of a major gas
sale. She said:
As the commissioner indicated earlier, last year, in
2001, the legislature passed a resolution encouraging
the administration to explore the possibility of a
sale of royalty gas to an entity willing to build an
Internet data center on the North Slope, who was in
the market for anywhere between 8 million and 112
million cubic feet of gas per day. And, of course, we
have wanted to be responsive to that. However, we
felt it important to not only deal with one potential
buyer on gas, but to seek an indication of the range
of interest across the spectrum from potential buyers
of gas.
Number 1191
MS. ROBSON said a second motivating factor is the potential open
season for a gas pipeline. She reminded members that the three
major producers formed a team last year; they spent a year and
$100 million on studies regarding the feasibility of a gas
pipeline off the North Slope to transport some 4 billion cubic
feet a day or more of gas to other markets. [Those producers]
indicated, perhaps last August or September, that there could be
an open season for pipeline capacity as early as January 2002.
Then, in either September or October 2001, to her recollection,
they indicated that open season might be pushed back to the
second quarter of 2002. She continued:
However, we were privately told that ... the open
season could, in fact, be as early as January of 2002,
once again. Just within the last couple of weeks, one
of the producers [has] indicated that an open season
could be in the second quarter of 2002. Also, the
pipeline consortium that has been recently
reconstituted under Foothills has indicated that if
they reach a successful conclusion to their
negotiations with the producers, that an open season
could be as early as the second quarter of 2002. Just
this past Tuesday, we did receive correspondence from
the producers' consortium indicating that they
themselves did not have a current intent about an open
season in 2002.
Number 1096
MS. ROBSON addressed the question of what is so critical about
an open season. She called an open season "a vehicle to get
pipeline capacity." Because this gas pipeline would be a
contract-carriage pipeline, the entity that constructs a
pipeline would - before making an absolute commitment to build
that pipeline - conduct an open season in which those interested
in shipping on the pipeline must make long-term, irrevocable
commitments to pay for capacity on that pipeline, regardless of
whether they ship on it or not. The required commitment could
be 15, 20, or possibly 25 years. The extent of commitments made
during an open season would be a significant factor in deciding
pipeline size. Once the parties make irrevocable ship-or-pay
commitments and the pipeline is sized accordingly, there may be
no additional way to get other gas into that pipeline for 15,
20, or 25 years.
MS. ROBSON addressed possibilities for getting other gas into
the pipeline beyond that nominated in the initial open season.
First, someone with existing capacity could resell some of that
capacity. She commented, however:
We don't think that's particularly likely in this
environment, since those North Slope producers,
particularly the Prudhoe Bay and Point Thomson
producers who are expected to factor predominantly in
the open season, have the known gas reserves and will
want to move their stranded gas assets off the North
Slope in the capacity they nominate. So we do not see
them as being significant marketers of secondary
capacity.
MS. ROBSON reported that second, there could be an expansion of
pipeline capacity. She explained, however:
The problem with expansions of pipeline capacity is
that FERC - the Federal Energy Regulatory Commission -
has at least no certain ability to compel expansion
over the objection of the pipeline owner. It is
arguable that they do have some ability, but there is
no certain ability to get an expansion, when and where
needed, by those other than those who, in fact, own
the pipeline.
Number 0930
MS. ROBSON again emphasized the primary importance of the open
season, not only to bring as many parties to the table as early
as possible - because they may not have the opportunity later -
but also from a royalty-in-kind perspective. Although the state
has the opportunity, with as little as six months' notice, to
switch from RIV to RIK, it can only sell to a buyer who has
"takeaway capacity" in the pipeline, procured in the initial
open season, or who can use it on the North Slope, which is a
fairly limited market. She added, "There is limited ability for
the buyer after this initial open season to say, 'Yes, I want to
buy gas - I want to buy royalty gas,' and have the ability to,
in fact, deliver that gas to the desired location."
MS. ROBSON concluded that while it's important to the state to
have its right for RIK or RIV, and to be able to switch between
the two, there will be a severe limitation on the ability to use
its right for RIK and to make that switch once this open season
comes and goes.
Number 0840
MS. ROBSON highlighted differences between pipelines. Oil
pipelines are "common carriers." Oil pipelines such as TAPS
allow for a monthly nomination of pipeline capacity; anybody who
wants to buy oil on the North Slope now can do that, and can get
the capacity and move the oil to the desired location. She
explained that first, TAPS is not at maximum capacity; it was
always envisioned that TAPS would operate for a short time at
maximum capacity, but then would have excess capacity. Second,
because TAPS is a common carrier and nominations are done on a
monthly basis, [a company] can always at least get its pro-rata
share of oil into the pipeline.
MS. ROBSON noted that in contrast, natural-gas pipelines are
"contract carriage." Furthermore, this gas line is envisioned
as being at maximum capacity for decades to come. And for a gas
line, Ms. Robson said, "If you don't participate in the open
season, you don't have any right to access to that line, and you
could not get your desired share or a pro-rata share of gas into
that pipeline at a later date in time."
Number 0744
CHAIR OGAN asked whether it would be prudent for the state and
the producers to work together to ensure there is enough
capacity - and perhaps even excess capacity - to use a portion
for other uses in Fairbanks or Delta, for example, with LNG
going to Valdez; perhaps there also could be future access to
gas for Anchorage. Referring to testimony in the Joint
Committee on Natural Gas Pipelines hearings [in 2001], he voiced
his understanding that once one molecule of gas is shipped
interstate, FERC will regulate the whole thing. Noting that Ms.
Robson is an attorney, he asked whether there is any way to get
state control to a hub point, perhaps statutorily moving the
wellhead down to Fairbanks, for example, or using another way to
ensure that open-season issues [don't prohibit] continuing
exploration. He asked: Who will invest in the foothills or
anywhere else to buy leases to look for gas if it can't be put
into the pipeline? He also asked Ms. Robson whether it would
require a change to federal law.
Number 0577
MS. ROBSON answered that she personally hasn't done that
research, but understands such research has been done by private
counsel retained by the Department of Law. There also has been
some examination of the issue by the Regulatory Commission of
Alaska (RCA). She offered the following:
Unfortunately, we don't have a lot of good news to
offer. We do see that if we are seeking certainty on
access in some of these issues, that a change in
federal law is the best and perhaps the only way to
accomplish that certainty.
The federal government, we think, will retain control
over the regulation of this pipeline, and that there
is really not the opportunity, as others have
suggested, of possibly moving the point of their
regulation downstream from the North Slope to, say,
Fairbanks or some other location, that they are going
to have primary control, that they may allow some
input by the Regulatory Commission of Alaska or the
state government, but at this stage they are not
compelled to give equal voice to the State of Alaska,
or primary voice to the State of Alaska. And, also,
they have limitations on their ability to do some
things like compel expansions of the pipeline in the
future, even if the party comes forward and proves
that it's economic to provide that expansion.
There are other possibilities; I think one you
mentioned is negotiations with the producers, and
certainly this is something that we've ... raised with
the producers, and we are optimistic about future
conversations with the producers. It would, at least
theoretically, be possible that - short of federal
legislation - there could be a binding, written
commitment by the producers to provide access on terms
that are acceptable to the state, in lieu of giving
FERC the ability to compel access on terms other than
allowed under current law. ... We have encouraged [the
producers] to come up with a proposal on what they
would be willing to offer, and we have yet to receive
such a proposal.
Number 0421
CHAIR OGAN suggested the capacity would have to have been built
in from the beginning, however. If the pipeline were full,
access issues wouldn't be much of an issue, he suggested.
MS. ROBSON offered her understanding, based on conversations
with both the producers and the pipeline consortium, that both
groups now are looking at a pipeline with initial capacity of
about 4.5 billion cubic feet a day. She added:
Now, you would be able to optimize that pipeline or
tweak the system a little bit and raise the capacity
up to 4.6, possibly 4.7 billion cubic feet a day.
After that, you would be looking at one significant
expansion on the order of about 1 billion cubic feet a
day, bringing the capacity up to 5.5 - 5.6 billion
cubic feet a day. And that would come by putting
compressor stations between the existing or initial
compressor stations, and the system would be plumbed
to make that easy.
That would be an expansion that would be available at
a cost roughly equal to the initial cost of providing
capacity. That is, if you have a fixed tariff, we can
choose any (indisc.) we want for that initially for
the 4.5 billion cubic feet of capacity; you could make
one one-time, substantial expansion of 1 billion cubic
feet and retain approximately the same tariff. After
that, my understanding of what you're looking at is,
then, what they call full-line looping - running a
duplicate pipe. That's not cheap; you can't do it for
small amounts. And so just the very physical nature
of this pipeline puts substantial restraints on the
ability to put additional gas in at a future point.
Number 0265
For example, if you start out at 4.5-billion-cubic-
feet-a-day capacity, you tweak the system a little bit
and get up to 4.6, and then you have other groups that
come and are ready, willing, and able to pay the exact
same tariff to put their gas in the pipeline - but
they only have, for instance, in "incremental," 300
million cubic feet a day, or 500 million cubic feet a
day, or even 800 million cubic feet a day, that alone
is not at a level that may justify an expansion. And
it's possible that they could group their gas with
incremental gas from the three major producers off the
North Slope, but, again, that requires the full
cooperation and consent of those producers on the
timing and quantity.
So we have very real concerns about access. ... We
would like to see some changes made, whether it be in
federal law or through agreement with the producers,
that it would at least minimize some of these adverse
consequences of limitations on access.
Number 0178
CHAIR OGAN requested that Ms. Robson provide a list of suggested
changes. He added that perhaps the committee could assist in
formulating a resolution, for example.
MS. ROBSON agreed to his request. She then said it raises the
question of when the open season is going to be - if it is
important to at least proceed with the RIK procedures, prior to
an open season, in order to allow any prospective purchaser to
participate meaningfully in that open season. She added:
We have, as I indicated, a statement from the
producers, two days ago, that they do not currently
envision that they will conduct an open season in
2002. There's at least three problems that we have
with just postponing a royalty-in-kind sale, based on
that statement. The first is that it's not an
absolute guarantee that the producers won't conduct an
open season in 2002. So while they do not currently
envision an open season this year, that vision may
change, for instance, with the passage of federal
enabling legislation. As I indicated earlier, it
wasn't so long ago that they were looking at an open
season in either the first or second quarter of 2002.
The second is that while the producers may not conduct
an open season in 2002, they are now in discussions
with the pipeline consortium of Foothills, and that
entity could conduct an open season in 2002.
The third is that because any royalty-in-kind contract
must be approved by ... the legislature, it has to be
presented and approved in advance of an open season,
to provide the comfort ... [ends mid-speech].
TAPE 02-2, SIDE A
Number 0001
MS. ROBSON mentioned that December 2002 or January 2003 wouldn't
provide sufficient time to take up this issue and still allow
certainty to a prospective buyer.
MS. ROBSON highlighted the importance of not taking any action
that might delay an open season. For example, if the RIK sale
were postponed at this time, based on the producers' statement
that they don't currently envision an open season this year, the
producers then could obtain the desired federal enabling
legislation and their vision would change; in that case, the
state wouldn't want to be in the position of asking them to
delay that open season. She remarked, "I think the division,
and department, has been very conscious of taking no action
which would in any way obstruct or delay the construction of ...
this pipeline."
Number 0087
CHAIR OGAN reiterated his concern about how the amount of gas
produced would affect oil production and the revenue stream as a
result.
MR. MYERS responded that [the division] had very little
information until recently on how a proposed gas sale would
affect the Prudhoe Bay Unit and oil [production], or on what
might be done to mitigate oil loss. He stated:
Very recently, ... we've had people involved, again,
with this cooperative effort with AOGCC, with a joint
meeting, where we got fairly good information from the
producers ... on the effects. And ... it's not an
easy equation because it's a very dynamic thing ...
that depends on what mitigation measures you do. For
pressure loss in Prudhoe Bay, for example, ... gas cap
injection of water will keep pressure up and minimize
oil loss. So ... that project's going forward, called
the "pressure support initiative." That's a good
thing to mitigate oil loss either way - either with a
gas line or [not] - but particularly with a gas line,
it helps mitigate oil loss.
Another big issue is gas has other use on the Slope
now, for a miscible injectant to enhance oil recovery.
And it's not just in ... Prudhoe Bay, the main
reservoir, but it's in lots of reservoirs on the North
Slope. So ... the composition of that injection gas
varies; it varies not only the recovery rate, but the
kind of equipment you use to do that sort of miscible
injectant. And we expect, at some point in time,
ultimately, the producers would start using more CO2
for miscible injectants ... and then actually produce
and sell the gas that they're using. But ... when and
how that occurs requires modifications of facilities
and optimization, based on production scenarios.
So ... that one diagram I showed about ... a gas sale,
that was one of the reasons for showing you the gas
cap, the dynamic nature of the changes. There are
multiple ways to mitigate it. We're starting to have
those conversations. AOGCC and we believe we both
have to approve any sort of [gas] offtakes; so that's
another reason the engineering part is critical to it.
Certainly, ... the higher rate of offtake you do, the
more you have to do to mitigate oil loss. But I think
we're pretty confident there are ways to ... really
lower or make that loss-oil a fairly small number.
In converse, at Point Thomson we really have not had
those discussions, so we don't have any idea at Point
Thomson. And, of course, we're very early in the
development stage.
So, I think those conversations are starting to occur
now, for the first time. And ... that's very positive
news.
Number 0310
CHAIR OGAN surmised that the Department of Revenue might have to
crunch some numbers, depending on the engineering studies, for
example, to figure out the loss of revenue. He asked Mr. Myers
about it.
MR. MYERS replied that certainly both DNR and AOGCC would have
to approve the plan of production for gas offtake. There would
be a major discussion of those effects and approval of the plan.
Those would be the lead agencies on the issue, he added. He
continued:
The tricky thing is, we could start getting involved
with very confidential data, and our ability to share
that with you is limited. That would have to come ...
via the producers, other than general [information].
The Department of Revenue does run a model; the model
is entirely too simplistic to answer this question and
doesn't necessarily integrate the latest changes in
technology the producers are [using]. So we
definitely need more than a back-of-the-envelope model
... to deal with this issue.
Number 0376
CHAIR OGAN suggested although the data is confidential, the
bottom line of how it will affect production shouldn't be
confidential.
MR. MYERS responded:
Well, I think it's an appropriate discussion for the
producers to bring up again; where ... we're using
confidential data provided by them, we can't really
discuss the conclusions of that data, other than the
parts of the conclusions we can make public. So I
think it's a very appropriate issue to bring up again
with the operators of ... both the Prudhoe Bay and
Point Thomson fields.
Number 0425
MS. ROBSON returned to page 4 of the handout:
Let me just mention briefly two other reasons why we
felt it important to begin with the process for a
royalty-in-kind sale now. One is that the governor's
policy council on the gas line indicated that the
state's right to take in-kind was important, should be
retained, and recommended some split of how the state
takes its royalty between in-value and in-kind. And,
again, to effectuate that recommendation would require
selling at a time for a buyer to participate in the
open season.
And the final reason is simply that we have had many
expressions of interest by potential buyers in
conducting a royalty-in-kind sale, and we think it is
important to respond to their interest.
Number 0483
CHAIR OGAN remarked that timing is everything with regard to
buying or selling. He said, "Basically, what we're doing is
we're selling gas that can't be marketed at this point, on
speculation that it might be marketed. And would ... we get
more money for the gas ... if we waited until we know it could
be marketed? It seems to me it would be worth more if they know
they have a pipeline." He noted that there has been talk of
marketing the gas for 25 years.
MS. ROBSON replied:
In terms of what we obtain for the gas, I think there
are a couple [of] elements of the terms on which the
gas is being offered ... that play into the
consideration that would ... be received. First of
all, the floor or base price, in any proposal that
might be accepted by the state, would be the royalty-
in-value number. So we do not do a royalty-in-kind
sale unless we're going to get at least as much or
more than we would get if we left the royalty share
in-value with the producers (indisc.--coughing).
Now, the producers are sophisticated marketers of
their gas. And you can bet that they're going to
obtain if not the best price, one of the best [prices]
in the marketplace for the gas. And because there are
a number of them, between the several of them you can
expect that they're going to be commanding the premium
prices in the marketplace when and if that gas gets
delivered to market. So if that's our base - that's
our floor value for a royalty-in-kind sale - any buyer
must pay "that amount plus" to obtain this royalty
share.
Number 0603
The second is that we are asking potential buyers to
offer a premium - in terms of cents per mcf or mmBtu -
on top of the royalty-in-value.
And the third is that we're asking that they provide -
or indicate whether they are willing to provide - some
special commitments to the state that may take the
form of in-state investment, whether, as you
indicated, in a petrochemical plant or additional
exploration in the state, whether it would be for in-
state use of gas or supply to in-state buyers of gas.
So we feel that this is actually an optimum time to be
offering the gas, because of the keen interest of a
number of parties and the ability for those parties to
plan ahead ... for the utilization of that gas, as
well as the absolute floor on price: we can get no
less for our royalty-in-kind than we do for royalty-
in-value. And I think we have very good ...
protections, in the producers' own marketing
practices, providing that floor.
And again, there would be the obstacle, if we decided
later we wanted to market it: how do we get the
pipeline capacity to move that gas to market?
Number 0694
CHAIR OGAN asked, "Where did you come up with 70 percent?"
MS. ROBSON answered:
That is what we set as the ceiling on what will be
sold. There, again, has been no determination to sell
any volume at all or, if there are sales, to come up
with 70 percent. ... We think it important to keep
some in-value, for several reasons. Let's just [look
at] numbers on the 70 percent. If we're looking at a
4-billion-cubic-feet-per-day pipeline - and I use that
instead of 4.5, even though that's more probable,
because the math is easier with 4 billion cubic feet -
the state's royalty share is a half billion cubic feet
per day or 500 million cubic feet per day; 70 percent
of that is 350 million cubic feet per day. If ... one
of your buyers is a large, commercial entity, they
need substantial volumes; they may need volumes in
that vicinity to be of value to them. So there was
one concern of offering enough to attract the largest
buyers. ...
The second was that by retaining the 150 million cubic
feet per day, we have ample additional gas to sell at
a later point in time, if we can overcome these
pipeline-capacity problems for in-state use. For
instance, the Fairbanks market is envisioned [to
perhaps] ... use 10, maybe 20 million cubic feet a
day. Again, we'd be reserving 150 million cubic feet
a day. Anchorage, if we could get additional gas to
it, ... could theoretically take 100 million cubic
feet a day. Again, we're reserving 150 million. So
there's plenty for incremental, in-state use of future
buyers at a later point in time, and yet it is still a
quantity that would draw the biggest and most
attractive buyers willing to offer the most
significant premium or special commitments to the
state.
Number 0828
MS. ROBSON continued:
The next slide [page 5] just shows a series of ...
processes that are part of any royalty-in-kind sale.
And, in fact, we have made a special effort to double
up on some of the findings and public comment for this
process, to make sure that we get maximum input,
maximum interest from potential buyers, and maximum
hearing on what is the public's interest, the
legislature's interest, [and the] industry's interest
in this sale.
We have currently a solicitation of offers on the
street requiring the submission of proposals the last
day of this month. There will be an opening of those
proposals on the first day of February, to be followed
with negotiations based on those proposals, additional
public comment period, additional royalty board
hearing, additional findings by DNR, and, of course, a
submission of any contract to this legislature for
approval or disapproval by April 1st for action this
year.
Again, one of the terms for the offering is that a
contract must be approved, if at all, under this
offering by - I believe it is - August 1st of this
year; otherwise, we would have to repeat the process
at a later point in time, or we could, prior to
January 31, extend that deadline.
Number 0911
MS. ROBSON addressed basic terms incident to the offering. She
pointed out that the offering is for up to 70 percent of
production from the Prudhoe Bay Unit and Point Thomson Unit,
which the division understands will be the "cornerstone" for a
pipeline. She told members:
The price, as indicated, includes a number of
components, the base being the royalty-in-value
number, any premium a bidder's willing to offer, as
well as a bonus. And the bonus bid, which would be
due upfront, is an amount equal to $1 per 1 mcf of
daily delivery.
MS. ROBSON informed members that the terms of sale aren't
summarized in the handout, but the offering and a sample draft
contract can be found on the division's web page. She noted
that there were approximately 100 pages and offered to make hard
copies available, if requested. She called it a "detailed
solicitation and finding."
CHAIR OGAN said he had a copy but offered to ensure that other
members get a copy as well.
MS. ROBSON continued:
I'll just mention a couple of other key terms in our
proposed disposition. One is duration. We're asking
that those interested in purchasing indicate what
duration they are interested in purchasing the gas
for. And we are willing to consider sales for as long
as that period for which pipeline capacity nominations
are required in the initial open season. We don't
know what that period will be yet, but whether it's 15
or 20 years, that is the maximum duration we would
consider for initial sale, because a buyer may be
constrained by the need to nominate and fill pipeline
capacity for that duration. But we are also willing
to consider offers for a shorter duration.
The point of delivery for the gas would be on the
North Slope, at the same place that the gas is
tendered by the producers to the state. So the state
never gets in the business of itself transporting the
gas.
And finally, another provision that we have put in the
request for proposals is - as an accommodation to the
producers, as I indicated before - the state has the
right to switch between royalty-in-kind and royalty-
in-value on six months' notice. Often, a royalty oil
or gas purchaser will know well in advance of six
months of change in plans that substantially affect
how much oil or gas they want to buy. So we built in
a mechanism to encourage them to give two years'
advance notice of significant changes in the quantity
of gas that they do want to take.
Number 1097
MS. ROBSON continued:
I will just touch on one additional point: the
remaining ten or so pages [of the handout] all are
based around a single scenario, and I don't think we
want to explore that scenario this week; you may want
to do it at a later point in time. But they are
designed to show the impacts of a royalty-in-kind sale
on the sizing [of] the pipeline, on the pipeline
company itself, and on the Prudhoe Bay and Point
Thomson producers.
And I will just summarize the conclusions, and then,
if there are specific questions, I'd be happy to
address those now or, if you want to go back, take a
look at this graphic, have some more conservations,
and we can pick up the conversation later.
We think, if anything, that the impact a royalty-in-
kind sale will have on ... the sizing of the pipeline
is to provide for a larger-size pipe and, ultimately,
more flow of Alaska's gas to market at a sooner point
in time, and early monetization of our stranded gas
resources.
We think there will be no or a positive impact on the
pipeline company itself. While there may be some
impact on the size of the pipe, what will happen in an
open season is there will be nominations for specific
quantities of gas, and the pipe will be built to
accommodate those quantities. And so the pipeline
company will have ship-or-pay commitments for the
entire volume, from day one, and so there will not be
a negative impact on the pipeline company itself.
There may be an impact on the producers at Prudhoe Bay
and Point Thomson. There are some aspects in which
the impact would be positive, and there are some
possible aspects in which the impact may be negative,
although we think any negative impacts could be
mitigated.
Number 1205
MS. ROBSON summarized possible impacts, whether positive,
negative, or neutral:
First, it's possible that the impact on the Prudhoe
Bay and Point Thomson producers might be that ... some
portion of their stranded gas reserve could be ...
brought to market sooner and they could monetize that
stranded asset at an earlier date and time, and due to
the time value ..., actually increase the value of the
project to themselves.
The second way in which it may affect [the producers]
is that if we wind up with a larger pipeline as a
result of this royalty-in-kind sale, due to economies
of scale the pipeline tariff may, in fact, be less.
And that would, of course, work to the benefit of the
Prudhoe Bay and Point Thomson producers, as well as
all other shippers on that pipeline.
The third way in which they may be impacted is the
level of use of the planned gas-treatment plant may be
impacted by a royalty-in-kind sale. And, again, I
won't go through the hypothetical here, but we do
think there are ways to accommodate or minimize that
impact.
So while we do note that the producers have indicated
a reluctance for the state to conduct this sale, we do
think that it could have a positive or neutral impact
on the desirability of the project to the producers.
And we do think there is room to accommodate their
concerns.
We have also asked the producers to quantify any
negative impact that this sale may have, and they
have, at this stage, declined to make that
quantification. So while there [are] some purported
negative aspects of a royalty-in-kind sale to the
producers, we are sympathetic to any negative concerns
but we want to see a quantification and identification
of those negative aspects, and we have yet to receive
that.
CHAIR OGAN asked whether [the producers] have indicated they
will provide that [quantification or identification].
MS. ROBSON said no.
Number 1326
MR. MYERS added:
Another factor is ... we've had extensive
conversations with potential buyers of gas, one of
those buyers' groups being a consortium of ... various
explorers for gas. They have expressed to us their
number-one concern and risk is in exploration for new
resources in the sense of finding, discovering, and
producing those resources - it's getting those
resources to market. ... So it is a risk that's shared
by other companies that have a lot of expertise in
finding, producing, and shipping gas.
Number 1354
MS. ROBSON concluded:
I do not want to end on a negative note by indicating
the producers have not gotten back to us on that
issue. We have had a number of conversations with the
producers on many issues. I think we are
"progressing" the issues in many areas; there are
areas where there is still disagreement or [where]
interests are different. Access and this royalty-in-
kind sale is one of those. But I do think that the
interests of the state and the producers are being
advanced by the conversations and the cooperation to
date.
Number 1387
CHAIR OGAN asked whether there were further questions. He
remarked that he would like to hear from the producers and
possibly take some public testimony at the next meeting, if
anyone wished to speak on the issue.
CHAIR OGAN pointed out that committee packets contain the
following: a letter from the Alaska Gas Producers Pipeline Team
[representing BP Exploration (Alaska) Inc., ExxonMobil
Production Company, and Phillips Alaska, Inc.] to [Commissioner
Pourchot of] the DNR, dated January 15, 2002, asking for a
reconsideration of the best-interest finding; an e-mail from Ken
Thompson [dated January 14, 2002, to committee aide Linda Hay]
relating to the issue and some findings from a commission that
Mr. Thompson had worked on regarding in-kind sales and so forth;
and a copy of [AS 38.05.183] dealing with the sale of a royalty
and legislative approval. He requested that committee members
become familiar with those materials.
CHAIR OGAN thanked the committee aide for the House Special
Committee on Oil and Gas, Linda Hay, for the excellent job she
has done.
ADJOURNMENT
Number 1495
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at 12:01
p.m.
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