Legislature(2007 - 2008)HOUSE FINANCE 519
10/22/2007 09:00 AM House OIL & GAS
| Audio | Topic |
|---|---|
| Start | |
| HB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB2001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
October 22, 2007
9:06 a.m.
MEMBERS PRESENT
Representative Kurt Olson, Chair
Representative Nancy Dahlstrom
Representative Mark Neuman
Representative Jay Ramras
Representative Ralph Samuels
Representative Mike Doogan
Representative Scott Kawasaki
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Bob Buch
Representative Mike Chenault
Representative John Coghill
Representative Harry Crawford
Representative Andrea Doll
Representative Bryce Edgmon
Representative Anna Fairclough
Representative Les Gara
Representative Carl Gatto
Representative David Guttenberg
Representative Lindsey Holmes
Representative Wes Keller
Representative Mike Kelly
Representative Bob Roses
Representative Paul Seaton
Representative Peggy Wilson
Senator Con Bunde
Senator Joe Thomas
COMMITTEE CALENDAR
HOUSE BILL NO. 2001
"An Act relating to the production tax on oil and gas and to
conservation surcharges on oil; relating to the issuance of
advisory bulletins and the disclosure of certain information
relating to the production tax and the sharing between agencies
of certain information relating to the production tax and to oil
and gas or gas only leases; amending the State Personnel Act to
place in the exempt service certain state oil and gas auditors
and their immediate supervisors; establishing an oil and gas tax
credit fund and authorizing payment from that fund; providing
for retroactive application of certain statutory and regulatory
provisions relating to the production tax on oil and gas and
conservation surcharges on oil; making conforming amendments;
and providing for an effective date."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: HB 2001
SHORT TITLE: OIL & GAS TAX AMENDMENTS
SPONSOR(S): RULES BY REQUEST OF THE GOVERNOR
10/18/07 (H) READ THE FIRST TIME - REFERRALS
10/18/07 (H) O&G, RES, FIN
10/19/07 (H) O&G AT 1:30 PM HOUSE FINANCE 519
10/19/07 (H) Heard & Held
10/19/07 (H) MINUTE(O&G)
10/20/07 (H) O&G AT 12:00 AM HOUSE FINANCE 519
10/20/07 (H) Heard & Held
10/20/07 (H) MINUTE(O&G)
10/21/07 (H) O&G AT 1:00 PM HOUSE FINANCE 519
10/21/07 (H) Heard & Held
10/21/07 (H) MINUTE(O&G)
WITNESS REGISTER
CLAIRE FITZPATRICK, Commercial Senior Vice President
BP Exploration (Alaska) Inc. (BP)
(No address provided)
POSITION STATEMENT: Provided comments during the hearing on
HB 2001.
MIKE UTSLER, Senior Vice President - Prudhoe Bay
BP Exploration (Alaska) Inc. (BP)
(No address provided)
POSITION STATEMENT: Provided comments during the hearing on
HB 2001.
KEVIN MITCHELL, Vice President
Finance & Administration
ConocoPhillips Alaska, Inc.
(No address provided)
POSITION STATEMENT: Provided comments during the hearing on
HB 2001.
JIM TAYLOR, Vice President
Commercial Assets
ConocoPhillips Alaska, Inc.
(No address provided)
POSITION STATEMENT: Provided comments during the hearing on
HB 2001.
KEN THOMPSON, Managing Director
Alaska Venture Capital Group (AVCG) LLC
Anchorage, Alaska
POSITION STATEMENT: Provided comments during the hearing on
HB 2001.
ACTION NARRATIVE
CHAIR KURT OLSON called the House Special Committee on Oil and
Gas meeting to order at 9:06:22 AM. Present at the call to
order were Representatives Dahlstrom, Doogan, Samuels, Olson,
Ramras, and Kawasaki. Representative Neuman arrived as the
meeting was in progress. Also in attendance were
Representatives Buch, Chenault, Coghill, Crawford, Doll, Edgmon,
Fairclough, Gara, Gatto, Guttenberg, Holmes, Keller, Kelly,
Roses, Seaton, and Wilson, and Senators Bunde and Thomas.
HB 2001 - OIL & GAS TAX AMENDMENTS
9:07:35 AM
CHAIR OLSON announced that the only order of business would be
HOUSE BILL NO. 2001, "An Act relating to the production tax on
oil and gas and to conservation surcharges on oil; relating to
the issuance of advisory bulletins and the disclosure of certain
information relating to the production tax and the sharing
between agencies of certain information relating to the
production tax and to oil and gas or gas only leases; amending
the State Personnel Act to place in the exempt service certain
state oil and gas auditors and their immediate supervisors;
establishing an oil and gas tax credit fund and authorizing
payment from that fund; providing for retroactive application of
certain statutory and regulatory provisions relating to the
production tax on oil and gas and conservation surcharges on
oil; making conforming amendments; and providing for an
effective date."
9:07:42 AM
CLAIRE FITZPATRICK, Commercial Senior Vice President, BP
Exploration (Alaska) Inc. (BP), began BP's PowerPoint
presentation by stating that the debate is about Alaska's
economic future. She stressed that the common objective for
both BP and the State of Alaska is to stem the decline in
production. Her presentation, she advised, would be from the
perspective of Alaska's resources, climate, costs, and geography
- in terms of the 800 miles of pipe and the 2000 miles of
shipping to West Coast refineries - because, she opined, that is
the perspective legislators should use in determining what the
state's fiscal policy should be.
MS. FITZPATRICK relayed that BP supports the net tax structure
under the current petroleum production tax (PPT) statute, but
continues to think that the [tax] rate is too high. Based upon
conversations with colleagues who were present during the
original discussions of the PPT legislation, Ms. Fitzpatrick
offered her belief that the policy behind the PPT was to
encourage investment in terms of getting barrels into the
pipeline. She then requested that BP be allowed another
opportunity for testimony should subsequent witnesses offer
differing economic viewpoints than BP's.
MS. FITZPATRICK stressed that the proposed changes will not
result in BP stopping further investment or leaving the state.
She said BP has done good business in Alaska for 48 years and
wants to do more; therefore, the discussion is about scale and
pace, not about there being no more investment.
9:11:31 AM
MS. FITZPATRICK noted that along with the PPT, royalty rates
also have a significant impact on the state's revenue and,
therefore, production will impact both royalty payments and
production tax. Delivering production will require billions of
dollars in investment, and that level of investment will need to
be higher than it has been in the last 20 years, she advised.
Price has been a huge benefit in recent years; however, BP is
not sure that basing fiscal policy purely on price is the right
approach.
MS. FITZPATRICK emphasized that fiscal stability is an important
consideration when making investment decisions. Having three
tax changes in three years does not increase Alaska's
attractiveness. The proposed bill will actually deteriorate the
economics of these investment decisions, and this, she
maintained, is recognized by both BP and the Department of
Revenue (DOR). She said that the sustained high oil prices of
recent years makes prospects more attractive now than they were
in the past, and while BP knows the resource is there, the key
issue is how to get it out of the ground economically, and that
is what enters into BP's investment decisions. Without
substantial reinvestment in existing resources, she explained,
it becomes harder to invest in new resources. So, the debate
for BP centers on investment because the profiles currently
being looked at are not yet "banked," she said. For Alaska's
economic future, now is not the right time to change the state's
fiscal policy.
REPRESENTATIVE DOOGAN requested a definition for the word
"strategy" as used in the third bullet point regarding
investment decisions on slide 2.
MS. FITZPATRICK explained that as a global company, BP looks at
strategic perspectives at the group level in terms of the global
risk that it is willing to take in a particular geographic area
of the world. The company also looks at its competitive
position and at where there is the greatest prospect in terms of
the resource base. On a group level, there are more strategic
decisions [to be made], often revolving around new country entry
or new location entry, and that is different than economic or
project specificity, so there are elements of both in any
investment decision.
9:14:41 AM
REPRESENTATIVE DAHLSTROM asked whether Ms. Fitzpatrick was
referencing the state's revenue department or BP's when she said
it was recognized that the bill could deteriorate the economics
of investment decisions.
MS. FITZPATRICK replied that she is referring to the State of
Alaska's DOR, and that it made that statement during its
[public] presentation on the bill.
REPRESENTATIVE DOOGAN asked whether "deteriorates the economics"
means that the projects would "make less money later."
MS. FITZPATRICK responded that it depends on the specific
project and its relative position to any other project, as well
as the very nature of the project. It does not specifically
make projects less economic later because that depends [on
numerous factors], but in overall terms it will make them less
economic. She acknowledged that this means it could result in
less money at any point along the line.
9:16:41 AM
MS. FITZPATRICK, referring to BP's PowerPoint presentation,
pointed out that production declined about 6 percent per year
between 1992 and 2000. However, she noted, the decline was
reduced to 1.5 percent per year between 2001 and 2004 because of
BP's increased investment in the late 1990s. The decline then
returned to about 6 percent per year from 2004 to 2007.
MS. FITZPATRICK, responding to a question from Representative
Samuels, confirmed that the investment in the late 1990s came
from Alpine and Northstar, and that the production decline
flattened out when these two units came on-stream. Once Alpine
and Northstar reached their plateau and started declining, she
continued, production returned to its historical annual rate of
decline of approximately 6 percent. In response to a further
question from Representative Samuels, she directed attention to
the graph on slide 3 depicting the plateau as lasting Three to
four years before production again began declining.
REPRESENTATIVE SAMUELS asked whether a two to three year peak
before the start of a decline is the norm for most reservoirs.
MS. FITZPATRICK replied that a peak, plateau, and then decline
are normal.
9:18:41 AM
MIKE UTSLER, Senior Vice President - Prudhoe Bay, BP Exploration
(Alaska) Inc. (BP), concurred that such is normal for a field.
And while it depends on the size and scale of the reservoir, he
said, a field will produce for as short as 9-12 months to for as
long as 7-8 years before beginning to decline, and that decline
then becomes a function of how the reservoir is managed and how
its performance continues to be developed and optimized.
REPRESENTATIVE SAMUELS asked how many barrels a day Northstar
produced at its peak.
MR. UTSLER offered to get back to the committee with that
information.
REPRESENTATIVE NEUMAN noted that recent information from the
administration shows a doubling of operating and capital costs
on the North Slope over the past year. He asked if that was
typical of what happens at BP, and whether it was all due to
cost increases or whether an increase in capital investment -
and thus the creation of more jobs and having more people
working - was the cause.
MS. FITZPATRICK explained that the doubling of operating and
capital costs on the North Slope over the past year was due to
both increased activity and increased costs. Activity increased
between 2005 and 2007, she said, with the number of BP
contractors increasing from about 5,000 to about 7,000, and with
the number of BP employees in Alaska increasing about 40-50
percent. High worldwide demand increased the costs of steel
rigs and skilled labor for the original activity, however some
of the increased costs were specific to Alaska. Part of BP's
long-term plan for addressing high labor costs, she continued,
includes hiring younger, less experienced talent and then
providing on-the-job training.
MS. FITZPATRICK then reiterated that the management of a
reservoir after it moves off its production plateau and goes
into decline is key to stemming that decline.
9:22:31 AM
REPRESENTATIVE SAMUELS asked whether a 15 percent decline rate -
if nothing is done - is typical for reservoirs around the world.
MR. UTSLER responded that around the world, typical natural
decline rates are 16-18 percent for a water-flooded reservoir
environment. And while it depends on the field, it is not an
unrealistic assumption to use a 16-18 percent natural decline
rate for most reservoirs that are under "secondary recovery,"
which is the term for operations that are under water-flooded
pressure support.
MS. FITZPATRICK added that the reason for the difference between
the 15 percent natural field production decline and [Alaska's]
current 6 percent decline is investment. In 2006, BP drilled
about 100 new wells, and about another 100 wells will be drilled
in 2007. Thus, between new wells and "well work" - the
maintenance necessary for keeping wells running at their best -
BP added about 70,000 barrels in 2006.
REPRESENTATIVE NEUMAN inquired whether any of the incentives in
PPT were factors in BP's decision to make new investments.
MS. FITZPATRICK replied that that decision was based on the
fiscal policy in place at the time. Currently, she said, BP is
looking at the next 50 years and at building a sustainable
business plan of activity, and [the state's] fiscal policy will
impact that. She submitted that it is impossible to say
whether, if BP had drilled 110 wells rather than 100, BP's
fiscal policy would have been different since she does not have
a retroactive viewpoint.
9:25:47 AM
MS. FITZPATRICK continued her discussion of new wells and well
work by noting that 70,000 barrels is equivalent to developing
the fourth largest producing field in Alaska, and that going
forward, BP is set to do it again. Over the last 10 years, BP
has invested about $4 billion in the drilling of 800 wells in
Prudhoe Bay and is also investing in facilities to pick up the
newer, heavier crude oil. Thus there has been lots of activity
to get the decline down to 6 percent, and because the best
prospects in any field are drilled first, BP must spend more
money and drill more wells just to keep that current decline
rate. The current level of spending on the North Slope will not
sustain a 6 percent rate of decline - it needs to be higher, she
opined, and even higher still in order to reduce the decline
rate further.
MS. FITZPATRICK, in response to a question from Representative
Neuman, confirmed her statement that BP drilled 800 wells in the
last 10 years.
REPRESENTATIVE NEUMAN questioned the discrepancy between 800
wells and a map he received the previous evening showing that
only 7 exploration wells had been drilled.
MS. FITZPATRICK explained that there is a difference between
drilling exploration wells in order to locate new discoveries
and drilling wells in existing reservoir areas.
MR. UTSLER further explained that undeveloped areas are
identified as exploration opportunities. In areas that are
already developed, productivity is optimized by drilling new
wells and "re-completing" existing wells. The aforementioned
800 wells have largely been in the existing, producing legacy
fields.
REPRESENTATIVE NEUMAN inquired as to how many well drilling rigs
are currently in Prudhoe Bay, in total between BP and other
companies.
MS. FITZPATRICK responded that BP currently has around 10 rigs
in the fields on the North Slope in which it has interest,
including Kuparuk.
MR. UTSLER further responded that at any given time, there are
about 21 rigs that are designed and equipped for operation on
the North Slope, and about 5 of those rigs are specifically
geared for winter-only exploration. About 16 rigs are available
at any given time to operate in existing fields, he continued,
10 of which are operated by BP.
9:29:34 AM
REPRESENTATIVE NEUMAN asked whether BP will be bringing any more
drilling rigs to Prudhoe Bay.
MR. UTSLER stated that BP is studying opportunities in the
Liberty Field. In order to drill that operation, he said, BP is
looking at building the largest land rig in the world. And
along with others in the industry, BP is also looking at
bringing new rigs to the North Slope to replace the aging fleet
and to increase capacity.
REPRESENTATIVE SAMUELS asked which areas BP held interest in.
MS. FITZPATRICK listed those areas as being Prudhoe Bay,
Kuparuk, Endicott, Milne Point, Northstar, Badami, and Liberty.
REPRESENTATIVE SAMUELS asked what BP's total Alaska oil
percentage is for each of those fields, adding that he assumes
that the vast majority comes from Prudhoe Bay and Kuparuk.
MS. FITZPATRICK agreed that the vast majority does come from
Prudhoe Bay and Kuparuk, and said she would provide the exact
percentages to the committee soon.
REPRESENTATIVE SAMUELS also requested nonproprietary information
regarding the percentage of BP's spending figures for each of
the fields, adding that he would like to know if costs correlate
with income.
MS. FITZPATRICK said she would provide that information once she
verifies that it is not proprietary.
9:32:15 AM
REPRESENTATIVE DOOGAN asked for further explanation of slide 3
of BP's presentation.
MS. FITZPATRICK explained that the numbers in orange on the
right side of the chart pertain to investment; the numbers in
green on the left side of the chart pertain to production; and
the bars depicted on the bottom of the chart indicate that
historically investment rates were around $1 billion, and that
in recent years the rate has risen above $1.5 billion.
MR. UTSLER clarified that the numbers in green represent barrels
of production per day and the numbers in orange represent annual
investment in billions of dollars.
REPRESENTATIVE DOOGAN asked what BP's profits were last year -
the time during which BP drilled 100 wells.
MS. FITZPATRICK said that BP recorded a profit of $2.15 billion
for last year.
REPRESENTATIVE RAMRAS asked what BP's posture would be should
production decline to the point where the State of Alaska does
not have enough royalty oil available to sell to the Flint Hills
Resources Alaska ("Flint Hills") refinery. He then offered his
understanding that there are two crossover points. The first is
when the state does not have enough royalty oil to fulfill its
commitment to Flint Hills, which would then require the state to
look to producers for augmenting the state's share. The second
is the notion of "batching" oil two to three times a week
because there is not enough oil to flow down the Trans-Alaska
Pipeline System (TAPS) seven days a week. Given that production
is declining, at what point does it become uneconomic to operate
the TAPS, he asked. Further, he asked, what happens to the
tariff cost per barrel of oil when production declines to
500,000 barrels per day, a volume at which the TAPS can still
operate but is a stress point for the state insofar as its [one-
eighth] share.
MS. FITZPATRICK, with regard to the tariff question, stated that
many of the costs associated with transportation are fixed;
thus, the fewer barrels going in, the higher the tariff.
Getting barrels into the pipeline is important, she said,
regardless of whether they are from state or federal leases,
because doing so lowers the unit costs which in turn is better
for everyone. With regard to what would happen should the
state's royalty share not meet its commitment to Flint Hills,
she said that [BP's posture] would depend on the circumstances
at the time since BP has no set policy in this regard. As for
what happens at various stress points, she said that that is a
question for Alyeska Pipeline Service Company ("Alyeska"), which
has been working to have flexibility as flow rates decline and
is looking at what is happening at the various points in terms
of investment.
MR. UTSLER further explained that with regard to Representative
Ramras's first question, the majority of Alaska crude oil goes
to the West Coast refinery market, three refineries in
particular. Those refineries are currently set up and designed
to take a particular blend of crude oil, and Alaskan crude plays
an important part for them. On a short term basis, those
refineries have the capacity to utilize the global market should
there be a disruption or variation in the Alaska crude oil
supply.
9:39:14 AM
REPRESENTATIVE RAMRAS offered his opinion that Alyeska is
becoming relevant to this discussion because an unstable tax
regime could diminish production, thereby moving Alyeska to a
stress point that would affect core jobs in the Interior. He
relayed that at a recent conference in Fairbanks, U.S. Senator
Ted Stevens advised the state to think about getting the next
barrel of oil, not the number of dollars being received in taxes
from the current barrel of oil. He requested BP's opinion on
what Alaska should do to best foster an environment that will
lead to that next barrel of oil.
MS. FITZPATRICK remarked that in order to get the barrels into
the TAPS, investment is required; thus any changes the
legislature makes should be considered in the context of whether
a particular change will increase or decrease the risk of
meeting the objective of getting more barrels into the pipe.
Again, the key is investment.
REPRESENTATIVE RAMRAS asked what BP's sentiment is when making
decisions for long-term development plans.
9:44:03 AM
MR. UTSLER remarked that because BP is operating above the
Arctic Circle in very harsh conditions, investment in
exploration and development - and specifically investment in
those technologies that will enhance the application of
technologies related to finding the oil and gas resources - is
an imperative for both BP and the state, both in the non-
explored areas of Alaska and in the existing fields. He went on
to say:
Secondly, then, you have the challenges of, "Now you
must drill to test and develop those resources." And,
again, [there are] the challenges of how we, together,
assure that we create an environment that encourages
the most efficient and effective development of those
resources.
MR. UTSLER said that from an operating standpoint, the
aforementioned arctic conditions result in some of the highest-
cost barrels in the world to develop and produce. Again, the
question becomes what can BP and the state do together to
enhance operability and increase efficiency in developing the
barrels. Furthermore, operations in the North Slope are
significantly disadvantaged because of the transportation
infrastructure that industry requires in order to get goods,
services, and materials to the North Slope. With regard to the
question of BP's sentiment, he said:
First and foremost we start with the barrels in terms
of where the barrels are, and our abilities to
understand the size and magnitude of the resource
that's in the ground. We then look at what is the
risk and the uncertainty of those barrels, in terms of
our confidence that they can be developed, in order to
be able to produce to the market place. The second
[thing] we then look at is ... what's the technology
required to actually develop those barrels - how and
what do we need to do once we've determined that there
is a 100 million barrels, 200 million barrels, or 10
million barrels - how hard is it to get those 10
million barrels, and what confidence do we have in
terms of the ability to develop and bring them to the
market place.
And then thirdly we look at what is the life of [the]
asset, what is going to be required in terms of
facilities, how long must those facilities operate,
what's the cost structure to operate those facilities,
is it a 10-year field development, is it a 20-year, is
it a [50-year, or an] ... 80-year. And each of those
decisions bring with it certain risks and view of what
is the full life of that asset's or that barrel's
development cost, so that we don't look at just the
front-end cost, but we have to look at the full field
life, and we have to be able to evaluate, in the
development of that barrel over the life of that field
for however long it is, with confidence, what is the
cost structure, the recovery, and the subsequent
environment in which we operate. And ... [we then]
compare those, on a global basis, from market, from
basin to basin to basin where hydrocarbons exist.
9:47:57 AM
REPRESENTATIVE RAMRAS posited that the DOR will argue that one
of those variables is the tax rate, whereas what members have
heard, he relayed, is that the tax rate is "pretty far down your
pecking order" and that it won't affect BP's investment decision
- that the other variables previously specified are much more
dominant in BP's determination of whether to invest. He asked
about investment climate, and whether an incremental increase in
taxes, after the large policy shift of a year ago, will have any
impact on BP's sentiment regarding whether to go forth with a
particular project.
MS. FITZPATRICK said that all of BP's investment decisions, at
the economic level, are made on an after-tax basis. So, does
fiscal policy come into BP's decision making? Absolutely,
regardless of whether the project is in Alaska or someplace
else. In terms of barriers, she remarked, there is not a fiscal
term that will enable BP to develop 50 million barrels per day
(mbd) of heavy oil tomorrow; rather, BP must first overcome
technological challenges. However, knowing that there is a good
fiscal policy in place makes it a lot easier for BP to say that
it is prepared to make the investment to actually work out how
to apply that technology, in this particular environment,
knowing that once BP has mastered the technology, it can then
work on getting the economics right to then progress the
project. That decision is impacted by fiscal terms.
9:51:34 AM
MS. FITZPATRICK, in response to a question by Representative
Doogan, relayed that there is an articulation of BP's strategy
at the group level that is in the public domain, and offered to
provide members with that information later. In response to a
further question, she said that the state has information that
BP is required to share with the state, and that there is also
some very detailed information available publicly - though some
[is only available through] subscription services - on every
single one of Alaska's fields, including information about
capital, tariffs, and production profiles. She said that she
would be happy to provide further information regarding how BP
views Alaska's resources.
REPRESENTATIVE DOOGAN asked whether there is also information
available publicly that will help member's determine whether BP
has the technology to drill a particular well.
MS. FITZPATRICK said she hopes that later testimony will provide
that information.
REPRESENTATIVE DOOGAN asked whether he will, at some point, be
capable of predicting the effect of any particular change in the
state's fiscal policy.
MS. FITZPATRICK pointed out that there is always a way to do
something via mathematical models, but such models will still be
wrong because they are based on assumptions and the world is not
static. "When we make our investment decisions, we're assessing
risk, and ... I've never seen a project that has actually
delivered exactly what we thought it was going to; some are
better, some are worse, and we're evaluating those risks to make
that decision," she added. For better or for worse, members of
the legislature are in the same position.
REPRESENTATIVE DOOGAN surmised that the term "risk" includes
economic risk but not exclusively.
MS. FITZPATRICK explained that for BP, the term "risk" refers to
resource risk, technology risk, economic risk, cost risk, and
fiscal risk - a wide variety of risks. In response to a
question, she said that although there should be sufficient
information made available to help guide members, it would be
impossible for someone other than the company to know what
decision it would be making under any particular set of
circumstances because there are many other factors that the
company takes into consideration when making such decisions.
REPRESENTATIVE SAMUELS surmised that the risk tolerance of
various companies is not information that would be available to
the public.
MS. FITZPATRICK acknowledged that each company will have its own
risk tolerance, which will vary depending on where a particular
project is as well as other variables. For example, a small
exploration company can take a lot more risk for its size than
one might think but it's basing its decisions on what it thinks
the rewards are. And the larger a company is, the more risk,
financially, it can take because it can actually cope with it,
whereas if a smaller company drills a $100 million dry hole,
that could have a fairly devastating impact on that small
company.
9:58:03 AM
MS. FITZPATRICK, referring to slide 4, said that production is a
key point - more barrels means more money for the state; that
the point of slide 4 is that investment leads to barrels, which
in turn leads to increased revenues; and that slide 4
illustrates a range of outcomes. For example, if the goal is to
stem decline down to 3 percent - as opposed to the current 6
percent rate of decline - it will require substantially more
investment than there has been to date. In response to a
question, she explained that according to the chart on slide 4,
the industry investment is "point forward," with the 3 percent
decline rate going out to about the year 2050. She added:
We've made an assumption, here, on the revenues of the
current tax structure. We've assumed 60 percent
dollars, [and] we've used the state's ... cost
forecast. It's merely to sort of point out two
things. One is, the lower the decline, [although] it
requires more investment, ... it does in fact generate
a lot more revenue, both from PPT but also from the
other revenues primarily driven by royalty. There's
actually a range of royalty rates. The average of
12.5 that's used actually belies the range that runs
from 11 to 27, depending on the field concerned. So
that can actually have quite a substantial impact if
it's more barrels in the pipe.
REPRESENTATIVE HOLMES asked in what year is the 15 percent
decline that's indicated on slide 4.
MS. FITZPATRICK reiterated, "That's point forward," and offered
to get more specific details to the committee.
10:01:36 AM
REPRESENTATIVE RAMRAS, referring to the term "opportunity cost,"
asked who BP competes against for limited capital dollars, and
how that position is arrived at. He said he wants to know
whether changing the tax policy in Alaska will affect BP's
investment behavior, and how BP will "go up against" its units
in other countries for capital.
MS. FITZPATRICK offered that BP's Alaska unit first looks at
what its set of opportunities are and what the opportunities
are, even within Alaska, that BP thinks are the right
opportunities related to short-term issues - getting production,
getting barrels in the pipe - and to mid- and long-term issues.
REPRESENTATIVE RAMRAS surmised that investing in operating
expenses is what generates profits.
MS. FITZPATRICK relayed that BP looks at the range of
opportunities, and at what activities the company can actually
execute with the equipment and personnel it has, though if there
is a project that can't be started right away but the company
wants to be able to do so in the near future, the company makes
plans that will enable it to start that project at the
appropriate time. Once a group within BP decides it would like
to go forward with a project, it then presents that "activity
set" and accompanying "financials" to the head office in London,
which in turn looks at the parameters of the project and its
potential short- mid- and long-term benefits to all of BP's
groups and at what is actually possible. At the group level,
the company then looks at all of its branches in various parts
of the world and considers the proposed project in terms of its
robustness and stability. She said that each individual project
is assessed on its own merits but within the context of BP's
strategic and financial frameworks. The more stable she can be
in Alaska, she remarked, the better her chance of saying to the
board that any incremental capital at the group level ought to
be spent in Alaska; thus stability is quite important.
10:12:45 AM
MR. UTSLER added that BP's first challenge is to grow the
business via replacing the barrels it's produced with new
barrels - "we need to find more barrels than we've produced the
previous years." Therefore the upstream decision is based on
the availability of oil in the world; the company's ability to
discover, develop, produce, and market that oil; and the
subsequent return on the oil that the company does sell.
CHAIR OLSON said he hopes that "maintenance has a voice and is
asking [for] more money."
MR. UTSLER said "Absolutely." He attempted to assure the
committee that BP first starts with complying with the law and
with understanding exactly what its operational costs are,
particularly those specific to the activity set required to
continue meeting the law and industry standards. The company
must then make decisions regarding what it is willing to spend
based on how long the life expectancy of a particular field is.
He offered that over the last five years, BP has spent four
times the amount on maintenance operations than it spent the
previous five years, and spent three times the amount on repair
operations in the last four years than it spent the previous
four years.
MS. FITZPATRICK relayed that there is no competition for
required maintenance capital.
MR. UTSLER remarked that the [North Slope field] is one of the
first arctic developments in the world; is the largest field
discovered in North America 35 years ago; is still the largest
producing field in North America; that although its original
lifespan expectation was 20 years, that lifespan is now expected
to be 80-plus years; that "it is a massive structure"; and that
the scale and significance of its hydrocarbon accumulation is
staggering on a global-scale basis. This size, however, creates
huge challenges. Greater Prudhoe Bay itself is over 60 square
miles in size; BP has over 11 major producing facilities
necessary to handle the oil, gas, and water produced from the
field's reservoirs; and BP has developed over 42 well pads
allowing the company to drill through 1,500 feet of permafrost
and into reservoirs that range from 3,000 feet below the earth's
surface to 9,000 feet below the earth's surface.
MR. UTSLER mentioned that approximately 1,200 of the wells that
BP has drilled in this field either are currently producing or
are being used to inject water or gas [into the reservoir] in
order to optimize resource recovery. He indicated that one of
the things that needs to be understood is that although the
total oil production is declining on the North Slope, the total
fluid production is actually increasing. Every day the company
has to handle more water being produced with every barrel, and
that water has no revenue value but does have disposal cost.
This increased fluid production carries with it greater risk,
greater cost, and greater complexity in terms of how the company
optimizes the next barrel of oil it produces from this field.
He went on to say:
Every day we produce somewhere between 6 Bcf [billion
cubic feet] in the summer to almost 9 Bcf of gas a day
from the reservoirs. We have to take that gas
production and re-inject it back into the ground.
That does two things for us. It provides pressure -
support - to the reservoir to enable us to get yet
another barrel out of the ground tomorrow. It also
provides an avenue of support by which we can actually
produce those barrels more efficiently from the
reservoir. ... At 9 Bcf, that's 40 percent of the
Lower 48's household gas consumption on a daily basis
that we are managing every day and putting back into
the ground.
Millions and millions of horsepower are required to
re-inject that gas across the field into the
reservoir, again, with no revenue benefit ... other
than the impact that it has on our abilities to
produce. So [it's] a significant set of challenges
for us. As we've continued to produce the oil, over
this 30-year period, the physical ability to recover,
every day, more oil from that reservoir becomes more
challenged - it's harder - and therefore we're looking
constantly for new ways and new technologies to be
able to enhance the scrubbing of the reservoir in a
way that allows us to get every possible barrel of oil
out that we can recover from this known resource.
REPRESENTATIVE SAMUELS asked what BP uses diesel for and how
much diesel BP uses in its day-to-day operations.
10:25:04 AM
MR. UTSLER explained that BP is looking to build - jointly with
ConocoPhillips - an ultra low sulfur diesel (ULSD) refining
plant in the Kuparuk field. This plant will allow the companies
to comply with federal law regarding the use of ULSD by January
1, 2010. The state, via legislation, has demanded that BP
instead achieve this goal by January 1, 2009. Currently in
greater Prudhoe Bay, BP uses approximately 3,000 gallons of
diesel per day in the company's over 750 vehicles - though the
amount varies greatly depending on the season - and in operating
its emergency generators and backup equipment. Furthermore, BP
uses diesel for a variety of other reasons such as well
stimulation. In response to questions, he relayed that the
diesel that BP currently uses either comes from Flint Hills or
is produced on site at BP's "crude oil topping facility"; that
he couldn't speak to how much diesel the other Prudhoe Bay
producers are using; and that the aforementioned refining plant
will only meet industry demands on the North Slope.
MS. FITZPATRICK added that if the refining plant produces beyond
what the companies needs, BP could provide a supply to North
Slope villages, though doing so would not be its primary aim.
Should BP and ConocoPhillips not be able to meet the state's new
timeline, it will result in a significant increase in supply
trucks on the road, and this in turn will have an impact on
environmental and safety perspectives.
MR. UTSLER, in response to comments and a question, acknowledged
that once Alaska has a gas pipeline, oil production will decline
considerably, though BP is working to address the "optimized
off-take of gas" since gas is an important part of the mechanism
by which BP extracts and recover hydrocarbons from the
reservoir; the consequences of gas production in Alaska will
have to be carefully managed with regard to the volume of "off-
take" and with regard to how to at least partially offset the
loss of that energy in the reservoir.
REPRESENTATIVE NEUMAN surmised that the change from oil to gas
will have an impact on the state's income.
MS. FITZPATRICK, in response to a question, offered that when
the gas pipeline becomes operational, there will be a change in
the mix of resources that are recovered, and that the issue of
how to maximize the molecules - whether they be oil or gas - for
the state's benefit will need to be addressed.
REPRESENTATIVE DOOGAN asked whether the aforementioned proposed
ultra low-sulfur diesel refining plant will meet industry needs
on the North Slope.
MR. UTSLER reiterated that it will, adding that the challenge
will be to move that diesel product to where it's needed.
10:35:36 AM
REPRESENTATIVE SAMUELS said that one problem with the state
giving BP a credit for the proposed refining plant is that that
same credit won't be extended to the other companies that have
an interest in the plant.
MR. UTSLER remarked that the North Slope is a complex
environment in which to produce oil and gas, and is getting more
complex every day in terms of technology needs and operating
costs. Referring to BP's PowerPoint presentation, he then spoke
of the volume of oil that's been produced to date from the North
Slope and greater Prudhoe Bay, and noted that this production
has come with tremendous challenges both technically and
opportunistically. He relayed that $19 billion has been
invested to develop [BP's holding] in greater Prudhoe Bay, and
although more money is being invested each year to essentially
produce fewer barrels, that investment continues to be an
important part of the company's ability to progress. After
starting with "natural production," he offered, the company
quickly realized that it needed to utilize additional pressure
support in order to optimize recovery, and since that time other
technologies have been utilized as well. Both BP and its
working interest owners have been focusing on "exploration
within the known," because even a mere 1 percent improvement in
recovery from greater Prudhoe Bay is equal to 250 million
barrels.
REPRESENTATIVE DOOGAN asked what is meant by the term,
"development investment" as it relates to the aforementioned $19
billion.
MR. UTSLER said that the figure of $19 billion reflects the
total capital invested since the beginning of the field's
development, and includes money spent on building facilities,
drilling wells, and delivery on a year-in-year-out basis, adding
that this year alone, BP will have spent upwards of $700 million
in "capital spend" and almost $900 million in "operating spend."
He again mentioned that developing the resources has become more
difficult each year, particularly in the environment in which it
is located, and so ongoing investment is necessary in order to
achieve the type of long-term success that will result in
another 50 years' of life for the field. He then spoke of the
various support facilities located in the area, and
characterized the facility 250 miles north of the Arctic Circle
as the largest gas processing plant facility in the world.
REPRESENTATIVE NEUMAN asked whether BP has plans for upgrading
or expanding that plant.
10:44:32 AM
MR. UTSLER said yes, BP does have such plans, particularly given
that in the future, the North Slope will change its primary
focus to gas production with associated liquids. Gas production
- especially if it is meant to continue for the next 50 years -
will require both the existing infrastructure as well as the
TAPS, because without an oil pipeline, there can be no gas
production since the oil and the gas and the water are produced
together. Furthermore, if the gas is not developed at some
point, then large value in terms of hydrocarbon resource
potential will be left in the ground. The facilities of the
future will not be the same as existing facilities, and folks at
BP are currently researching that issue further so as to be able
to optimize the North Slope infrastructure; some of the
questions being considered are, what types of facilities will be
needed, what levels of reinvestment will be required, and how to
go about leveraging the significant potentials of heavy oil.
REPRESENTATIVE NEUMAN surmised that transition to a gas pipeline
will require investment in new facilities.
MR. UTSLER offered that some existing facilities could still be
used, though some of the facilities will have to be changed.
One of BP's rationales for replacing the oil transit lines with
an entirely new system of piping is to allow the company to
deliver a 50-year future in a much more efficient and effective
way. Referring to another slide in BP's PowerPoint
presentation, he offered that currently there have been over
2,500 wells drilled in greater Prudhoe Bay - 1,200 of them are
currently active - and described what the slide showed, adding
that BP is currently drilling an average of 100 wells a year
across the North Slope. Significant continued investment is
planned, he reiterated, adding that infill drilling is part of
new development.
MR. UTSLER, in response to questions, said that BP has several
hundred gas wells that are being used to re-inject gas into the
reservoir cap, and has several hundred wells that are identified
from the "gas-cap standpoint."
CHAIR OLSON surmised that there is gas readily available if a
company had the means to develop it.
10:53:12 AM
MR. UTSLER concurred, but pointed out that as gas is produced
and is taken out of the top of the reservoir, oil migrates into
that void space and is lost if gas is taken out too quickly and
unless steps are taken to manage the pressure differential in
such a way so as to try to keep the oil where it was, so a
balance between oil recovery and gas recovery must be
maintained. In response to a question, he said that BP has been
working closely with the Alaska Oil and Gas Conservation
Commission (AOGCC) in a very cooperative manner to jointly
understand the reservoir and the characteristics of the off-take
levels.
REPRESENTATIVE SAMUELS asked how much it costs to drill an
infill well.
MR. UTSLER said that it costs an average of $4 million to $5
million to drill a well in greater Prudhoe Bay. In response to
another question, he indicated that reservoir by reservoir and
field by field, the cost of drilling a well varies depending on
where in Alaska that well is drilled.
MS. FITZPATRICK, in response to a question, said that the
aggregation of the satellite fields that took place under
economic limit factor (ELF) system meant that those satellite
fields were treated as a single taxing unit as opposed to
"differential" ones. At the time that the ELF aggregation
occurred, she recalled, the forecast was that doing so would
generate an extra $150 million in revenue for the state; this
aggregation made a significant difference in the development of
the satellite fields. In response to further questions, she
said that when investment decisions were being made at that
time, because the satellites were different, it was felt that
"we could make a differential decision where it was optimum from
an economic perspective" and that the tax consequences were
[acceptable] when deciding whether to drill an otherwise
uneconomic well.
MR. UTSLER referred BP's PowerPoint presentation, and said it
illustrates the nature of the impact to BP's long-term
recoverable resources from greater Prudhoe Bay. He indicated
that members were looking at "the bottom hole pressure" of the
reservoirs that BP is operating against, adding that as water,
oil, and gas were produced from those reservoirs, pressure began
to decline; with that decline comes a loss of energy in the
reservoir and this potentially results in less recovery over the
long-term. In looking at how to slow that energy loss, BP began
putting water into the reservoir, but this incurred a lot of
necessary operating costs, particularly since precision with
regard to where to re-inject the water was required. He
indicated that the slide members were looking at compared the
decline profile before water flooding commenced with the decline
profile after water flooding was commenced, and characterized
this increase in recovery as a significant contributor to BP's
having moved from 9 billions barrels of recovery to 11.5 billion
barrels. This technology will be "an important support" over
the next 50 years to the next 2-3 billion barrels of additional
light oils that BP expects to recover.
MR. UTSLER mentioned that currently BP is having to handle 1.2-
plus million barrels of water - some of it treated seawater - in
greater Prudhoe Bay everyday, though BP's goal is to eventually
increase its water injection, collectively, to over 2 million
barrels a day. This water, however, must then be separated from
the oil so that it can again be re-injected into certain other
wells to enhance their recovery. Also, from a technological
standpoint, BP has been researching how to add water to the gas
cap, thus compressing the gas in the reservoir and thereby
maximizing the sweep of oil in the reservoir. If flattened
pressure can be maintained, there will be an increase in long-
term ultimate recovery, but it will result in the company having
to handle more and more water and paying the extra costs
associated with doing so.
11:05:17 AM
MR. UTSLER, in response to a request, explained that BP needs to
achieve a balance between injection wells and producing wells,
adding that injection wells are "capital to drill" but then
"operating cost to operate" because they don't produce a revenue
stream. He indicated that of the $700 million invested in
drilling, 50 percent is capital investment for water injection
wells that have no rate of return other than helping long-term
oil recovery rates.
MS. FITZPATRICK, in response to a question, offered that all of
the aforementioned expenses are upstream and are thus impacted
by the PPT statutes or HB 2001's proposed changes. She added:
The treatment of whether it's capital or operating,
then you get the differential treatments within the
tax structure, recognizing that this is all talking
about Prudhoe Bay, and we then get to the issue of at
what point does the floor kick in versus the 25
percent net. And I know that the administration,
yesterday, said that they believe that was around $40.
We've not finished doing our analysis, we wish longer
time to understand what was presented over the last
two days, but our current view at the moment is that
it would kick in at a rate substantially higher than
$40, driven off different views on production,
capital, et cetera. So these will be impacted.
MR. UTSLER, in response to a question, indicated that the chart
members are looking at illustrates the original greater Prudhoe
Bay field with seawater injection. Again, it reflects an
increase in the seawater being used to augment oil recovery.
REPRESENTATIVE COGHILL asked what the ratio of water injection
wells is to production wells.
11:11:29 AM
MR. UTSLER said he would be able provide those details later,
but mentioned that BP is producing oil in many different ways.
Referring to the chart, he said:
In the portion just below the gas cap, in this area,
approximately, of the field, we actually use gravity
to help us produce, and so it's called, "gravity
drainage." And it's actually oil producing wells that
are using gravity effects of the steep dip ... of the
reservoir to actually drain oil to the well bore set
low in the structure and help us recover oil from
that. We're actually not using water to move the oil,
but we're using water, then, in the next band,
basically along these areas.
And that's why you can see these blue; along this area
of the reservoir, below gravity drainage, we actually
are using a water flood pattern where we use injection
wells with a center producer, and we're pushing water,
on all sides, towards that [center] producer. And so
we use water flooding on the lower portions of the
reservoir, gravity drainage in the center, gas re-
injection in the crest, and water "injectivity" on the
base to try to keep that oil moving but also contained
within the boundaries of not wanting to see oil
migrate into the gas cap where we would then lose
resources ultimately recoverable.
REPRESENTATIVE COGHILL observed that members will need to have a
concept of the capital and operating expenses necessary for
enhanced production.
11:13:00 AM
MR. UTSLER offered that BP uses several technologies in an
effort to increase oil recovery by the aforementioned 1 percent.
One of those new technologies developed by the industry is
called "Bright Water" and it has proven to be very encouraging
in its early stages of application. Because water that is
injected tends eventually to travel only on the path of least
resistance towards the producing well, standard water injection
technology ultimately leaves bypassed oils - oils that aren't
being swept up by the water that's been injected - and Bright
Water technology makes use of a polymer that once injected, sets
and hardens and creates obstacles around which the injected
water must flow, thus resulting in the formally bypassed oils
being pushed by the injected water towards the producing well.
This technology is costly, however; to illustrate, BP spent $1.8
million in chemicals alone on a three-well pilot program. In
response to a question, he indicated that the industry has been
working on the concept of this technology for the past 20-plus
years, though this particular seemingly successful method - with
the specific set of polymers and compounds that were used in the
pilot project - has only been applied in the last 3 years.
MR. UTSLER said that while exploration is an important part of
Alaska's future, 70 percent of all the hydrocarbon values that
are expected to be developed in the North Slope sit in already-
found fields; again, the challenge for industry involves
focusing on optimizing the recovery of that oil. Referring to
BP's PowerPoint presentation, he indicated that the chart
members were now looking at illustrates that if the goal is to
sustain field production performance, continuing investment in
the technologies to drill, develop, infill, and optimize the
reservoirs is imperative. For example, 50 percent of the oil
today that's moving through the TAPS came from wells that were
only drilled during the last four years. Referring to another
chart, he said it illustrates that the investment of over $250
million which occurred in 2002 produced a lot of barrels; a
similar amount of investment in 2003 and in 2004 produced fewer
barrels of oil. This decrease is not a function of a decreased
ability to operate, he remarked; rather it is a function of the
technical challenges of finding oil on a daily basis inside a
very mature field. Thus more investment is required if industry
is going to significantly impact the production decline referred
to earlier.
MR. UTSLER, in response to a question, acknowledged that the dip
in the number of barrels that were produced as illustrated in
one of the aforementioned charts reflects the period of time
during which BP's pipeline leak was discovered and BP had to
partially shut down its production in Prudhoe Bay. He mentioned
that dips also occur, generally during the summer months, when
BP engages in major repairs and maintenance of its facilities.
In response to a question, he indicated that that chart reflects
production from 2002-2007. There is less oil to be developed
today than there was yesterday and it's getting harder to
develop that oil; industry must continue to find ways to
encourage investment in existing fields.
11:26:34 AM
MR. UTSLER, referring to another set of charts, relayed that it
reflects that new technologies have enabled increased
development. For example, just 20 years ago the approach by
industry was to just drill single a vertical well from the
surface down through the reservoir and then produce the oil in
that well. New technology, though costly, now allows for
multiple horizontal drill routes to be established from only one
downward "mother bore"; technology such as this can unlock
previously unrecoverable resources.
REPRESENTATIVE SAMUELS asked what the cost is of horizontal
drilling compared with the cost of vertical drilling. He
observed that the charts appear to indicate that horizontal
drilling is accurate to within 20-30 feet.
MR. UTSLER concurred, adding that vertical drilling can be
controlled to within 1-3 feet, and that experience and
technology allow BP to have a relatively accurate picture of the
reservoir's makeup. Two of the advantages with a horizontal
well, he explained, are that the cross sectional area is
significantly enlarged and the pressure drop is significantly
reduced, both of which result in enhanced oil recovery (EOR).
He mentioned that the cost of drilling horizontally after first
having drilled a vertical well increases the cost by about
another 60 percent.
REPRESENTATIVE SAMUELS surmised that the credits for drilling a
well apply to both vertical wells and horizontal wells.
MS. FITZPATRICK concurred, but acknowledged that there could be
a legislative change made to that credit.
REPRESENTATIVE RAMRAS asked who [within the administration] sees
the information about BP's innovations related to lengthening
the life of the oil field.
11:35:55 AM
MR. UTSLER said that from a Department of Natural Resources
(DNR) standpoint, BP updates its plans of development every
three years, and that BP also works with the AOGCC with regard
to the reservoir and hydrocarbon stewardship. Furthermore, the
wells must be permitted, and so BP has to provide various state
agencies with information regarding proposed well designs.
REPRESENTATIVE RAMRAS asked whether the DOR is provided with
this information as well.
MS. FITZPATRICK said that BP has given presentations to the DNR
regarding certain aspects of the industry, and mentioned that
most of the information requested by the DNR has been either
financial data or production data, both historical and
projected.
MR. UTSLER, in response to questions, said that BP generally
attempts to use its existing vertical well bores to start its
horizontal drilling operations, though sometimes new well bores
are drilled specifically with the intention of then using them
for horizontal drilling operations; that such operations don't
qualify for exploration credits; and that both operating funds
and capital funds are used for such wells, depending on the
actual procedure BP engages in.
REPRESENTATIVE DOOGAN asked whether proposed wells compete for
approval.
MS. FITZPATRICK relayed that generally wells are looked at on a
program basis, though sometimes, depending on the actual nature
of a proposed well, it will be considered separately.
MR. UTSLER added that the complexity of a horizontal well is
much greater than a vertical well, so the decision regarding
whether to drill a vertical well - or a multi-lateral well - is
considered in terms of the risk and reward of the potential
hydrocarbons to be developed and how to best develop them with
the capital deployed.
REPRESENTATIVE DOOGAN asked whether a proposed horizontal well's
potential return has to be proven before it is approved.
11:43:35 AM
MR. UTSLER said yes, adding that one of the questions that must
be answered is whether a horizontal well will recover at least
the same amount of reserves as a vertical well will. In
response to a comment, he indicated that the operating costs for
a horizontal well are somewhat higher than for a vertical well.
MR. UTSLER, in response to a question, indicated that when
operators develop a program, each well being recommended for
drilling must be presented to the working interest owners in the
form of an authorization for expenditure.
MS. FITZPATRICK added that if the information on individual
wells within the program of wells changes over time, these
changes are also discussed with the working interest owners,
though such changes won't necessarily have to be relayed to
company headquarters.
MR. UTSLER relayed that when BP develops an Alaskan plan, it is
presented internally to BP's president and the other working
interest owners in Alaska; this plan then faces competition from
BP's other operations around the world.
REPRESENTATIVE SAMUELS asked what happens if the other working
interest owners don't agree with the proposed Alaska plan.
MR. UTSLER said a compromise is then sought, though the working
interest owners with less interest are given less say.
MS. FITZPATRICK, in response to a question, said that within
Alaska, there is a fairly continuous cycle of business planning,
though data is submitted to BP's main office during specific
timeframes.
MR. UTSLER relayed that BP submits its yearly proposal to its
working interest owners in September of each year.
MS. FITZPATRICK, in response to questions, relayed that BP does
annual plans, 3-year plans, 5-year plans, 10-year plans, and 20-
year plans; and that BP is currently planning for calendar year
2008 and beyond.
REPRESENTATIVE DOOGAN surmised that there must have been a plan
of development under the ELF after the satellite fields were
aggregated, and under the PPT. He asked whether BP has a
similar prospective plan under the proposed Alaska's Clear and
Equitable Share (ACES) legislation - HB 2001.
11:56:35 AM
MS. FITZPATRICK said that BP is not working on a plan of
development or a long-term plan under the proposed ACES
legislation; such plans are only created based on current law,
not pending legislation. She mentioned that BP's past plans
under the ELF and under the PPT are not comparable and would not
be helpful to look at because production profiles have since
changed, different technologies have been engaged, and there are
now very different cost structures and price environments.
MR. UTSLER mentioned that there is now technology that allows BP
to control the amount of water used in the injection wells.
Referring to BP's PowerPoint presentation, he indicated that the
slide members were now looking at is intended to demonstrate
that there are other reservoirs to be developed in greater
Prudhoe Bay; that there are four new reservoirs that have been
developed since the year 2000; and that there is a project
[underway] that will develop viscous - or heavier - oil inside
the west flank of the field. He relayed that BP has already
spent over $80 million in the early engineering design,
development, and testing of "these" reservoirs, which are now
producing viscous and heavier oils at a rate of about 25,000
barrels per day.
MR. UTSLER offered that BP is also looking to propose a
development project that would represent nearly $2.1 billion-
plus in expenditures for wells, facilities, and necessary
infrastructure to develop what could represent 250 million
barrels of additional oil recovery from greater Prudhoe Bay and
between 40,000 and 60,000 barrels of incremental production per
day. However, this will be very different from the existing
production stream; it will have to be managed within the
construct of the existing field development, and therefore does
require specific infrastructure such as the gas partial
processing plant, which would need to be built as part of the
field's development, and other equipment specific to producing
heavier oil. This will require the employment of a significant
number of people as these facilities are constructed. He
indicated that this project will be extremely sensitive to
economics because of its investment scale and complex nature.
MR. UTSLER then remarked that the third significant resource
development at Alaska's disposal on the North Slope is heavy
oil, which lies, largely, over Kuparuk, Milne Point, and a
portion of the western side of greater Prudhoe Bay. He
mentioned that the main reservoirs of greater Prudhoe Bay have
approximately 25 billion barrels of oil in place as well as
approximately 50 trillion cubic feet (Tcf) of gas. The
shallowest oil - heavy oil - is estimated to amount to between
20 billion and 25 billion [barrels] in place. He emphasized
that although heavy oil represents a significant opportunity for
the state and participating operators, it is also significantly
challenged with regard to technology, the ability to develop the
heavy oil, and the necessity of having to have a robust light
oil with which to produce the heavy oil.
12:07:21 PM
MR. UTSLER, in response to a question, relayed that although
some heavy oil is currently being produced on a limited basis,
it is not the heaviest of the heavy oils, which makes up the
lion's share of Alaska's heavy oil and which is being developed
only on a trial basis.
MS. FITZPATRICK, in response to a question, relayed that BP does
produce some heavy oil in Venezuela, and that there are
different types of technology suitable to the task.
MR. UTSLER explained that the portion of BP's PowerPoint
presentation that members were now viewing illustrated the
challenges associated with producing heavy oil, which, in
general, is physically difficult to handle because it is so
thick and tar-like, particularly under arctic conditions. Heavy
oil is also of lower quality and hence lower value because it is
more expensive to refine into product that the public can use; a
barrel of heavy oil can be discounted as much as $10-$12
compared to a barrel of light oil. Heavy oil is currently being
produced in California, Canada, and other parts of the world via
the use of steam, which is an expensive process, and, with
varying rates of success, via the use of other types of
technology. He mentioned that in Alaska, at Milne Point, the
test process being used is Cold Heavy Oil Production with Sand
(CHOPS), and briefly described how the CHOPS process is supposed
to work. If this process is to prove successful, it could
require the drilling of thousands of wells. He offered that for
Alaska's oil resources, the more light oil that's available and
the longer that light oil is available, the more heavy oil can
be produced; the faster light oil reserves decline, the less
heavy oil will ever be developed.
12:16:29 PM
MR. UTSLER, in response to questions, relayed that in speaking
about the heavier oils that have been produced thus far in
Alaska, he is referring to viscous oil, not specifically heavy
oil, and that BP is examining some of the heavy oil technologies
being employed in the oil sands in Alberta, Canada. In response
to a further question, he offered that BP is hoping to develop -
over the long-term - a significant [heavy oil] resource base
that could produce 50,000-plus barrels per day, and that
currently only about 2,000 gallons of diesel a day are produced;
therefore, if diesel were to be used as a diluent to produce
Alaska's heavy oil resource, the state's capacity to generate
diesel must be massively increased. In other words, in Alaska,
diesel is not an economically viable diluent mechanism under
current technologies. He remarked that although heavy oil is a
huge resource for the state and participating operators,
bringing that resource to market will require massive technology
and massive investment.
MR. UTSLER offered that Alaska has a unique resource and
hydrocarbon basin; it is massive in terms of opportunity, but
because of its location, the cost of developing those
hydrocarbons is disadvantaged to most of the global market
place. On average, the costs of acquiring seismic and
geotechnical data are much higher, it is more costly to drill
and develop the wells, and the scale of infrastructure necessary
to produce Alaska's fields results in still further cost
disadvantages. In fact, the state's own data, in its 2007
spring forecast, indicates that per barrel, the cost of
operations, transport, and taxes averages $16 as compared to
only $10 for oil produced elsewhere in the United States.
MR. UTSLER, in response to a question, offered his understanding
that according to the state's information, each barrel of Alaska
oil costs $6.04 to transport, is subject to a production tax of
$2.77, and has forward operating costs of about $7.75.
REPRESENTATIVE KAWASAKI surmised that transportation costs are a
significant component of that $16 average.
MR. UTSLER concurred.
REPRESENTATIVE KAWASAKI noted that despite the higher costs of
developing Alaska oil, BP still reported a significant profit.
He asked how much of that profit could be attributed to Alaska's
resource.
MS. FITZPATRICK said she would be able provide that information
later on in the presentation. In response to comments, she
indicated that the average $16 per barrel figure provided by the
DOR excludes the capital costs of producing that barrel, and
that those figures might need to be crosschecked with other
data.
12:28:51 PM
MS. FITZPATRICK, on the issue of profits, relayed that for 2006,
according to BP's U.S. Securities and Exchange Commission (SEC)
reports, for its holdings in the U.S., including Alaska, BP
showed a profit of $6.2 billion. She mentioned that copies of
another of BP's SEC reports are forthcoming and will be
distributed to members as soon as they arrive.
MR. UTSLER, in conclusion, offered that from an operations
perspective, the legacy fields - greater Prudhoe Bay and Kuparuk
- are critical resources for the state and have many, many
challenges if industry is to optimize their remaining lifespans,
which BP believes to consist of at least another 50 years. That
future, for greater Prudhoe Bay, can only be "unlocked" with
continued strengthening of investment, a focus on developing new
technologies, and continued application of existing
technologies. Over the next 50 years, it will be critical for
BP to redevelop the infrastructure and begin focusing more on
gas production with associated liquids.
MS. FITZPATRICK offered that although working on the North Slope
is becoming more challenging and more expensive, that does not
mean that the work to date has been easy. Referring to BP's
PowerPoint presentation, she noted that the 15 billion barrels
of oil that have already been produced is 20 percent more than
was originally anticipated. Additionally, the resources in the
existing mature fields represent only 70 percent of the North
Slope's future resource potential. She too indicated that the
sustained development of Alaska's light oil is paramount in
developing Alaska's heavy oil.
MS. FITZPATRICK, referring to BP's PowerPoint presentation,
relayed that it is extremely difficult to break down statistics
in terms of molecules; that substantially more investment is
required than has occurred to date; and that at least 50 percent
of the additional investment in new developments is coming from
heavy oil, with the remaining 50 percent coming from the use of
technology and new discoveries within existing fields and
beyond. With regard to new developments, she pointed out that
they take years in terms of design and permitting before
actually achieving first production. She remarked that 70
percent of production for the next 20 years will come from
Prudhoe Bay and Kuparuk; therefore, a key point is to ensure
that the right investment activity takes place in those
locations.
12:38:56 PM
MS. FITZPATRICK, referring to BP's PowerPoint presentation,
relayed that what members were now viewing illustrates the
percentage increases in costs, which have increased overall,
adding that this "cost movement with price" is one of the
reasons why BP supports a net tax - everyone is aligned with
what's actually happening and the dynamics of the market. She
added:
Another factor just to be aware of ... is that for
companies like us, we often enter into long-term
contracts. So the timing of when cost inflation hits
through will also be dependant on when our contracts
happen to run out. And they'll then be renegotiated
based on market prices at that time.
MS. FITZPATRICK offered that [investment] activity has gone up
significantly on the North Slope in terms of people working, rig
counts, seismic activity, and various other activities. When
thinking about costs in the context of tax, she observed,
although costs are often thought of as being bad, she tends to
think of costs as being good in a broader economic sense; if
money is being spent on the North Slope, for example, it means
that contractors are being engaged and they in turn employ
people who are then spending their wages and in this way helping
the economy. She offered her understanding that a 2001 study
indicated that 1 percent of employees in Alaska are directly
employed by the oil industry, that 12 percent of the jobs in the
private sector are attached through the multiplier effect to the
oil industry; and that 20 percent of salary and wages in the
private sector are linked to the oil industry.
MS. FITZPATRICK, in response to a question, relayed that some of
[BP's employee] growth in recent years is due to technological
advances, contract costs, and various other factors; in other
words, a change in the tax structure cannot be pointed to
specifically as the reason for this growth. Furthermore, BP's
business isn't annual - some of the investment decisions that
were made a couple of years ago have simply taken time to take
effect with regard to employee growth.
REPRESENTATIVE RAMRAS asked how many people BP employs globally.
MS. FITZPATRICK said 100,000-plus employees, but noted that that
figure includes "downstream" employees.
12:44:49 PM
MR. UTSLER indicated that almost 10 percent of "upstream" BP
employees are located in Alaska.
REPRESENTATIVE RAMRAS said that that is also indicative of the
human resource component and its accompanying capital that
[Alaska's branch of] BP competes for.
MS. FITZPATRICK concurred. In response to questions regarding
BP's increased labor costs, she indicated that for all positions
at all levels, accessing, recruiting, and retaining skilled
experienced people now costs more, and offered to provide
specific information on that point. On the issue of taxes as
they relate to economics, she said:
The question ... was asked earlier ..., "How do I
know, if I move one percent or two percent of tax,
what's it going to do." Sadly, I don't have a magic
answer. ... It's complex, there's a lot things that go
into it. All we can say is that when we look at our
economics, on the very simplest level, increasing tax
will decrease the value of my post-tax investment,
therefore my economics have [gotten] worse. What I'm
interested in then is, ... "Where does that then sit?"
There's a number of projects which I know were already
marginal but were on the right side of marginal when I
take into account all of the risks. They will all get
looked at again, [though] I can't say, definitively,
where they will be.
The other thing to note is, when we look at a project
and ... at first light ... it doesn't look economic,
we don't throw our hands up and say that's it; the
first thing that ... [Mr. Utsler] and his team do is
... [consider the question], "What do we need to do to
make it economic?" We work very hard at that. We're
also aware that there is a huge amount of investment
that we do, that we will continue to do, under the
terms of our lease, to prudently develop the resource.
So this is around what's beyond that. [Because] 70
percent of the resource is in existing fields, 70
percent of the production for the next 20 years will
come from those fields, that's the area that we're
obviously particularly focused on - how do we maximize
those investment opportunities.
Changing the policy doesn't help; changing the policy
to meet a forecast doesn't feel like good policy, and
it will impact behaviors, not only of incumbents, but
also of people looking to enter Alaska. The other
thing that we've put up there [on the presentation] is
not only the 70 percent of future investments within
[Prudhoe Bay] and Kuparuk, [but] the floor - the 10
percent gross - when that kicks in, will also have a
significant impact on the investment decisions within
those legacy fields - remembering they're covering
heavy oil, viscous oil.
Getting the decline to 6 percent to start with before
you even start building on it, ... that infrastructure
needs to be there, not only for the base production,
it needs to be there for the new stuff, it needs to be
there for heavy [oil]. There's a whole activity set
around that that's beyond just what's actually
producing barrels but which is needed in order to make
the barrels the most efficient and effective that they
can be, for us and for everyone else who will
hopefully be on the [North Slope] in the future. ...
Hopefully our key points are fairly self-apparent.
This is about investment, to stem decline. The
barrels are getting harder; technology is needed, more
investment is needed. Economics will get worse if tax
increases. The question for me should be not so much
how do we stem decline per se but what would it take
to get a million barrels in the pipe from the current
sort of 700. The last point I've put up there is, the
current bill ... does create uncertainty; this would
be the third tax change in three years which I don't
need any consultant to tell me creates concerns over
fiscal stability.
REPRESENTATIVE SAMUELS asked whether BP buys credits.
MS. FITZPATRICK said it is not corporate policy to buy tax
credits. In response to a question regarding transportation
costs, she said that when BP is looking at its projects, it's
looking at them purely from an upstream perspective. There is a
requirement, under the Federal Energy Regulatory Commission
(FERC) regulations, to have [firewalls]. So there is a lot of
information regarding BP's business and its interests in the
TAPS that certain employees will know about but that other
employees won't know about; for example, there is a requirement
that shippers and producers are not privy to the same
information.
12:54:46 PM
MS. FITZPATRICK, in response to another question, reiterated
that of the resource base that is yet to be developed, 70
percent is in the known fields, and that when viewing where
production is coming from for the next 20 years, according to
the DNR's forecast, 70 percent of that appears to be coming from
Prudhoe Bay and Kuparuk.
REPRESENTATIVE RAMRAS asked who is ultimately making the
decisions regarding Alaska. He said he is interested in how
minor tax-policy changes affect the behavior of those who are
ultimately making the decision to go forward with a particular
project.
MS. FITZPATRICK said such decisions are made at various levels.
For example, with regard to a proposed project in Alaska, after
the planning process is complete and the parameters of the
project are given, the decisions can be made within Alaska by a
collective leadership team. So while the president of the
company ultimately makes the final decision, he/she looks to the
Alaska team to see what its members collectively think about the
proposed project in terms of whether it will be good for BP
Alaska.
REPRESENTATIVE RAMRAS asked whether BP finances projects from
earnings, and how does Alaska compete for those earnings that
could then be re-circulated into Alaska's oil fields and
economy.
12:59:55 PM
MS. FITZPATRICK explained that the BP group sets its financial
framework based on its strategic objectives. This financial
framework will include how much [the BP group] believes it's
appropriate to be reinvesting capital globally across its entire
business. It's not a definitive number to the dollar - it's
usually a range. Within that, the group then looks to see how
it wants to allocate [resources] in terms of global risk -
whether with regard to refining and marketing or with regard to
exploration and production - and where it wants its geographic
risk spread. For the Alaska project, the group is looking at
very different strategic objectives than it would be for a new
project elsewhere in the world. With regard to the
exploration/production segment, BP still operates within a
financial framework. She added: "When we go forward with our
annual plans and our five-year plans, it's within the context
of, what [is] the exploration/production division looking to
achieve, and how does that fit with the group strategy."
MS. FITZPATRICK said that BP has a financial strategy of a
certain band of debt that it will have as debt-to-equity ratio,
and that will move up and down depending on what happens with
[the company's] cash-flow generation. Some of [the company's]
cash is used for repurchasing shares, though the decision
regarding how many shares are repurchased and when is done as
part of a global and group policy; it's not done on the basis of
individual earnings from any particular location, it's done in
the aggregate. Getting funding for the Alaska project is
dependant upon the [Alaska team's] being able to put together a
compelling business plan which illustrates that the project
would constitute a good investment for BP on both a short-term
basis and a long-term basis. She added:
We have put together what we believe is a good 50-year
future strategic view. And certainly, as I've said
earlier, my ability to go back and defend that will be
impacted by my ability to say, "This is what we said
is going to happen, and this is what will happen."
REPRESENTATIVE DOOGAN asked how, if taxes are increased, the
legislature will know whether doing so was a mistake in terms of
BP's investment strategy.
MS. FITZPATRICK said that such cannot be known until after the
event; for example, in five years time, the legislature could
come to realize that investment was not generated as
anticipated. "We believe it's too soon to look at this," she
remarked, particularly given that BP has not had an audit yet.
So although investment has increased, the ultimate goal is to
keep investment going as opposed to making a change that could
cause things to go the other way. Noting that BP does have
contractual obligations, she indicated that she is not saying BP
won't invest, but there will be issues "at the margin" that will
have to be considered very carefully.
1:05:04 PM
MS. FITZPATRICK, in response to comments, suggested that the
best way [for members] to evaluate the situation is to look at
what they are trying to achieve - for example, more investment -
and consider whether the proposed changes will achieve that
goal. Members could also look at the production forecast put
together by the DNR, for example, as well as at some external
factors. "The fundamentals for me on the economics are,
increasing taxes will decrease the economics; therefore, by
default, some of the projects are going to become more
marginal," she added.
REPRESENTATIVE NEUMAN asked whether BP has an estimate of how
many barrels of oil will be going down the TAPS in 10 years, and
what conversations is BP having with the administration with
regard to oil, gas, and the future of Alaska.
MR. UTSLER offered that if there is a 6 percent rate of decline
over the next 8-10 years, that would result in approximately
350,000 barrels [per year] going through the TAPS; this amount
constitutes a critical threshold for the TAPS, thus risking a
shutdown. He surmised, though, that "the TAPS' ownership" would
have been working to address options before any shutdown
actually occurred. He mentioned that BP is willing to talk to
[the administration] about the facts as BP understands them, and
has been speaking with the AOGCC and the DNR about its plans of
development.
MS. FITZPATRICK added that BP is not currently having any
conversations with the administration regarding a gas pipeline,
and that BP was very open and transparent, at the time of the
Alaska Gasline Inducement Act (AGIA), when it said it would not
be able to make a conforming bid.
MR. UTSLER, in response to comments, acknowledged that if,
internally, the decision is made to not advance a particular
project - whether it be because of Alaska's proposed tax changes
or some other reason - the reasons for not doing so may not ever
be made known to the public.
MS. FITZPATRICK, in response to further comments, offered that
the only answer that might become available would be in the form
of an economic model, which would be known to be wrong. She
added, "Yes, you're absolutely right, you'll never know
definitively; what you can know (indisc.) it's a risk you're
taking and it's around pace and scale." Generally speaking,
projects don't just disappear; rather, they simply get revisited
if they are not initially gone forward with.
1:14:38 PM
MR. UTSLER spoke of some of the projects that Alaska's projects
will be competing against, adding that more than twice as much
investment is occurring in the Lower 48 and Alberta - and more
than five times as much in the Gulf of Mexico - than is
occurring in Alaska. There are many factors responsible for
these differences in investment amounts, though one is the
disadvantaged price of Alaska's barrels of oil and another is
Alaska's already existing "significantly higher tax structure."
MS. FITZPATRICK offered that based on upstream numbers, the
total capital spending "on EMP" for 2006 for the U.S. was $4.5
billion.
REPRESENTATIVE SAMUELS noted that the economic consequences of
being wrong with regard to the proposed tax increases will
affect his constituents, and yet the legislature won't actually
know what those consequences are, or whether the taxes imposed
are too high or too low.
CHAIR OLSON offered his understanding that BP has global
development projections going out at least 50 years.
MS. FITZPATRICK offered that BP has a variety of views going out
over a very long period of time and they are [being considered]
at the strategic level. In response to a question, she said
BP's view on Alaska covers the next 50 years.
The committee took an at-ease from 1:19 p.m. to [2:37] p.m.
2:37:29 PM
KEVIN MITCHELL, Vice President, Finance & Administration,
ConocoPhillips Alaska, Inc., referring to a PowerPoint
presentation, first relayed that ConocoPhillips Alaska, Inc.
("ConocoPhillips") is the largest oil producer, the largest gas
producer, and the largest holder of exploration acreage in
Alaska, adding that the company is also a very sizable tax and
royalty payor in Alaska; has a major position in all major
sectors of the oil and gas industry in Alaska - ConocoPhillips
is heavily involved in the Prudhoe Bay area, is an operator with
a significant ownership interest in the Kuparuk area, operates
the western North Slope with sizable ownership interest in the
various satellites to the Alpine field, is in the Cook Inlet,
and is active in exploration; has been in the state for
approximately 50 years; and will continue to maintain its
presence in the state because Alaska is very important to
ConocoPhillips.
MR. MITCHELL offered his belief that ConocoPhillips and the
state are both seeking to nurture the growth of the industry and
progress its future because, as history has shown, when industry
is successful, so too is the state, and when industry struggles,
so too does the state. He said it is ConocoPhillips' view that
it is too early to change the PPT legislation - there are a lot
of unanswered questions regarding its performance - and that a
review of that legislation should be held only after sufficient
time has passed and there is then adequate data from which to
draw some conclusions. The uncertainty created by changing tax
legislation on a frequent basis cannot be [overstated], and
although investment decisions are not made entirely on the basis
of the tax structure, this uncertainty becomes a risk factor
during the investment evaluation process. The potential impact
of the proposed bill on investment is the most significant point
to consider, particularly with regard to the legacy fields.
MR. MITCHELL, referring to a chart in his PowerPoint
presentation, indicated that it illustrates three different
revenue projections for 2007. The first one, by the DOR,
represents the revenue the state would have received had the ELF
still been in place - around $.5 billion; the second one
represents what the PPT's fiscal note projected the state would
receive - a little bit under $2 billion; and the third one
represents the DOR's projection of revenue under the PPT
legislation - a little bit over $2 billion. He explained that
the differences between the actual revenue received under the
PPT legislation and the projected revenue were due to increased
costs as well as many other variables, and surmised that in any
given case, the actual revenue will never equal the forecasted
revenue, because such forecasts are based on inputs regarding
price, production, operating costs, and capital costs, and these
inputs generally end up being inaccurate. In the case of the
PPT legislation forecast, for example, it showed the effects of
changing prices, but did not reflect any changes to the other
aforementioned components.
2:46:46 PM
MR. MITCHELL relayed that in general, ConocoPhillips supports
the additional transparency provided for in HB 2001, and
understands the need for the DOR and the DNR to be able to share
information. There are some concerns with the bill, however.
In the context of exploration, the bill allows the DOR to share
all information with the DNR without exception, and so there is
some degree of confidentiality concern with regard to non-state
lands. The DOR has information on all lands - private
corporation lands and federal lands - and the DNR is responsible
for managing state lands and, to some degree, is in competition
with those federal and private corporation lands; thus there is
a potential conflict of interest with regard to sharing data to
the extent outlined in the bill.
MR. MITCHELL, with regard to the process pertaining to
exploration credits, relayed that the DNR is able to make a
determination of a well's geological success before granting the
credit, but the appropriate data must be provided prior to the
granting of that credit - and thus prior to the final auditing.
So a company gives up information before it knows for sure that
it will be receiving the credit, and this feels a bit one-sided,
he remarked. Furthermore, the exploration credit application
waives confidentiality rights, and hence there is some concern
that a company would choose not to apply for a credit because it
would prefer to keep certain information confidential;
therefore, this waiver could be viewed as an added impediment to
exploration activity.
MR. MITCHELL offered, therefore, that HB 2001 does have some
provisions that make it slightly less attractive to explorers
than the PPT legislation was.
MR. MITCHELL in response to a question, offered his
understanding that HB 2001 contains language allowing the
administration to request whatever "other information" it deems
necessary to accomplish its goals. A concern with this language
is that the bill also contains a penalty, on the order of $1,000
per day, for every day the requested "other information" is not
provided. In response to another question, he indicated that
the concern centers on the fact that that "other information" -
whether it be confidential information or not - might not be
easily gathered within the set time limit before the $1,000 per
day penalty starts applying.
MR. MITCHELL, on the issue of forecast data, said:
As an industry, we typically are very nervous whenever
we get into any discussions around providing our
projections and forecasts anywhere other than within
our own corporate entities, and what we would plead is
that ... those requests are limited to that same
information that is provided to partners in our unit -
unit operations. That is information that is shared
anyway, and I don't believe ... any other participant
in the industry here in Alaska would have too much
concern over sharing that same information. And we
would like to see those specifics contained [in the
bill] ..., and stay away from other corporate-type
projections and information.
2:55:55 PM
MR. MITCHELL, in response to comments and a question, opined
that the bill's language allowing the administration to request
"other information" is written very broadly. He then noted that
the bill also extends the statute of limitations "for audit"
from three years to six years. If the department were to
utilize this proposed new statute of limitations to its full
extent, "by 2011, when that review is scheduled to be complete,
they, in theory, might not be through one audit in that time,"
he offered; this proposed change could mean that the results of
a first audit might not be available until 2012. On the issue
of cost deductibility, he said that the PPT was set up on a net
profit approach, and this follows the federal code in
determining what expenses are allowable as deductions - the
terminology that's used is something along the lines of,
"ordinary and necessary expenses" in the operation of the
business. Adoption of those federal standards has simplified
the lives of the producers because they already follow the
federal code when preparing their financial statements and tax
returns.
MR. MITCHELL said that a deviation from those standards could
add another layer of complexity to what is currently being done,
and this impacts ConocoPhillips as an industry and the DOR as it
goes through the audit process. House Bill 2001, in contrast,
is proposing that the regulatory agency - the DOR - define what
deductions are allowable; this will create a lot of uncertainty,
he opined. In addition, the bill contains a provision allowing
the DOR to issue nonbinding advisory bulletins regarding its
interpretation of AS 43.55; this takes away any assurance
regarding how the information provided in such a bulletin will
be treated by the auditor. This has also engendered discussion
regarding whether the producers would simply claim the maximum
amount of expenditures possible and then battle out the details
during the audit process; however, while currently there is no
penalty for doing such, the interest accrued on over-claimed
expenditures is a minimum of 11 percent per year, and this
accrued interest and any subsequent penalties would constitute a
significant additional financial burden, particularly given the
bill's proposed six-year statute of limitations.
3:02:10 PM
MR. MITCHELL referred to "exclusions for cost deductibility,"
one of which is the exclusion of maintenance that is unscheduled
and that results in an interruption of production. Any
exclusion, he opined, adds complexity to the legislation, and
this particular exclusion could potentially create an auditing
nightmare and does not reflect the reality of producing oil on
the North Slope. This exclusion is for maintenance that
ultimately brings production back online, and therefore is the
very type of expenditure that should be the most incentivized.
All the exclusions [from cost deductions], he surmised, penalize
the very maintenance and repair activities that are necessary to
bring production back on line as quickly as possible. In
addition, the bill contains a retroactive provision stipulating
that the cost of any such maintenance occurring as far back as
April 1, 2006, can not be used as a deduction; he said he is not
sure how practical or possible such a provision will be to
implement.
MR. MITCHELL noted that there is an exclusion for dismantlement
costs. Dismantlement costs are those expenditures that are
necessary at the end of an asset's life; they are meant to
return the site to the condition it was in prior to any of the
[oil and gas] activity having occurred there. This a legitimate
cost, the companies are required to undertake this activity, and
this cost was listed as an allowable deduction under the PPT
legislation. To first allow such costs to be deducted and to
then preclude such costs is another "item" of instability, he
remarked.
MR. MITCHELL, in response to a comment and question, remarked
that under the PPT legislation, the "abandonment allowance"
could be accrued on an ongoing basis from the present to the end
of the field's life, and that everything that ConocoPhillips
would deduct as a lease operating cost are those costs that are
incurred as operator of the Kuparuk area, and all those costs
are shared among the various unit owners.
3:08:24 PM
REPRESENTATIVE SAMUELS questioned whether the state, in
accessing that shared cost information via one of the owners,
then has access to that information as it pertains to the other
owners.
MR. MITCHELL indicated that it did. Referring again to his
PowerPoint presentation, to the issue of cost deductibility, and
to the crude oil topping plant at Kuparuk, he explained that
currently there is a significant amount of diesel being used on
the North Slope, and noted that both Prudhoe Bay and Kuparuk
have their own topping plants and manufacture their own diesel.
Both state and the Environmental Protection Agency (EPA)
regulations will require the use of ultra low sulfur diesel
(ULSD), and ConocoPhillips has evaluated various options that
would allow it to meet those requirements. The company has
concluded that the most effective way of meeting the needs for
ULSD on the North Slope is to upgrade the plant at Kuparuk with
a Hydrotreater so as to be able to meet the low sulfur
specifications. That project [will cost] approximately $300
million, and, at its construction peak, could employ
approximately 300 people. The alternative to building this
plant is to transport/import the necessary fuel to the North
Slope either from somewhere else in Alaska or from the Lower 48;
he surmised that this alternative would not be the most cost-
effective option to pursue.
MR. MITCHELL, in response to comments and a question, offered
his understanding that if the company were to use fuel it
manufactured on site, it would not be allowed to deduct the
purchase price of the fuel, but if the company purchased fuel
from another source, the cost of that purchase is deductible as
an expense. The company's concern, he indicated, is whether the
cost of [building the Hydrotreater and] upgrading the current
facility so as to produce ULSD would be considered an allowable
expense and thereby be eligible for a credit. In response to
another question, he said that if that credit isn't available,
then ConocoPhillips will simply resort to importing fuel and
deducting the cost of its purchase.
3:15:14 PM
JIM TAYLOR, Vice President, Commercial Assets, ConocoPhillips
Alaska, Inc., added that ConocoPhillips has worked carefully
with refiners so as to be able meet the EPA's standards. The
proposed plant is designed to meet industry requirements and
those of any existing local market. If, through the building of
the Hydrotreater, the company has the ability to produce what it
needs locally while also complying with the spirit of law, which
is to reduce emissions, then to not build the Hydrotreater will
increase the demand for the product and the amount of
importation traffic, thus causing emissions to increase as well
as risk. Building the Hydrotreater is not intended to allow
industry to set prices.
REPRESENTATIVE SAMUELS asked whether there are any federal
credits available for that project.
MR. MITCHELL said he is not aware of any.
MR. TAYLOR, in response to a question, offered his understanding
that the future demand for ULSD will be about 700 barrels per
day at Kuparuk, and about 1,000 barrels per day at Prudhoe Bay.
He also offered to provide further details on that point.
MR. MITCHELL added that those numbers translate into roughly
100,000 gallons of ULSD per day. In response to a question, he
offered that ConocoPhillips's assumptions are that the local
market is competitive without the tax break, and that this is
slightly preferable from an economic standpoint.
CHAIR OLSON noted that Tesoro Alaska Company ("Tesoro") just
completed a similar facility for approximately $200 million
"with no tax break, and they seem to be making money."
MR. MITCHELL indicated that building something in Kenai is very
different, in terms of construction costs, from building
something on the North Slope.
CHAIR OLSON surmised that ConocoPhillips is seeking a similar
cost advantage by adding to an already existing facility.
MR. MITCHELL concurred. In response to a question, he indicated
that if ConocoPhillips didn't build a Hydrotreater on the North
Slope, the ULSD that it would need would have to originally come
from the Tesoro facility and would then have to be trucked in
from Fairbanks.
REPRESENTATIVE DOOGAN surmised that Tesoro would have to expand
its present facility - without receiving any state tax credits -
in order to meet future demands on the North Slope should
ConocoPhillips and BP not build the aforementioned Hydrotreater.
MR. TAYLOR concurred.
3:23:35 PM
MR. MITCHELL, referring to his PowerPoint presentation, noted
that the PPT provided for transitional investment expenditures
(TIE) credits, which recognize investments made under a prior
tax structure, and are meant to provide equity and stability
with regard to the treatment of expenditures. Removal of these
TIE credits, as HB 2001 proposes to do, will hurt those very
companies that have been actively investing in Alaska. One
example of where this change will have an effect is the "Fiord
development," which is an "Alpine satellite." He explained that
on the chart members are now viewing, "the blue bars" represent
capital investment, and "the red line" represents production.
Most of the capital investment in the Fiord development was made
prior to the enactment of the PPT legislation, when taxes were
calculated under the ELF, but when production comes on line, the
company will be paying tax under the higher PPT rate.
MR. TAYLOR offered that the "10 percent gross floor" can and
will impact investors' views and risk tolerance for the future,
will affect companies' planning processes, and can come into
play in both high- and low-price environments. Preservation of
an investment climate in the legacy fields is an important
attribute of keeping oil in the pipeline. He explained that the
chart members are now viewing uses information from the DOR's
spring revenue forecast, and said that it will take significant
capital to curb a 15 percent rate of decline in production.
MR. TAYLOR pointed out that resource developers inventory their
opportunities on a regular basis as a part of their ongoing
planning process, and offered that a "company hurdle rate" is a
function of the risk associated with an investment and can vary
from company to company. This rate is something investors also
consider when deciding what order to make their investments in.
A tax change, particularly if such changes are made frequently,
will cause investors to take a different view of their risk
tolerance, and marginal projects could be delayed.
MR. MITCHELL, in response to a question, offered his
understanding that "Pioneer" obtained royalty incentives from
the state that allowed it to move forward with a particular
project.
MR. TAYLOR, in response to comments, acknowledged that different
investors have different risk tolerances, and will therefore
make different decisions regarding which projects to go forward
with; there are many factors that go into a company's analysis
of whether to go forward with a project.
3:38:46 PM
REPRESENTATIVE SAMUELS asked whether a larger company needs
"larger finds."
MR. TAYLOR reiterated that there are a variety of factors that
can motivate an investor to pursue a particular project.
MR. MITCHELL clarified that ConocoPhillips still has an interest
in smaller, incremental projects.
MR. TAYLOR, referring to a chart in the PowerPoint presentation,
offered that it illustrates that the "10 percent gross floor"
can impact investment in six specific marginal projects, and
said that it could put at risk between $3.5 billion and $4
billion in investments.
MR. MITCHELL, in response to comments and questions, said that
two things could trip the 10 percent floor - lower prices or
higher costs; both have the effect of reducing the taxable
margin.
MR. TAYLOR, in response to comments, made references to a chart
members had looked at on a different day, and said his
conclusion is that none of the projects listed on that chart are
economic at $40 per barrel. He went on to say:
Costs are higher. The reserves are more challenged to
get because they're not the conventional, traditional
light oil developments of the past; they're heavy oil,
they require steam in many cases, and they're far more
complex to recover [and they] require a lot of
directional, horizontal wells. ... The [costs] to
develop those projects are much higher. And so
anything that is going to add more risk or more
taxation is going to erode and make those projects
riskier. So what I showed you here in a color code
was something that probably more resembles the $50 to
$60 oil price. It shows that there are some projects
that can be done. But there are projects, though,
that should the attributes of the bill that's
currently being evaluated be passed, could render
those uneconomic at this time.
MR. TAYLOR, in response to a question, said that when capital is
pulled out of the system fairly rapidly, production also
declines fairly rapidly. He offered that the PowerPoint
presentation illustrates that the largest potential that remains
on the North Slope under current projects exists inside the
legacy fields. Preserving that investment environment is very
important, not only for investors but also for the state. He
said that ConocoPhillips believes that it is too early to make
changes to the PPT legislation, particularly given that the
uncertainty of frequent tax changes does alter investors' risk
tolerance. Increased taxation erodes after-tax cash flow, which
in turn impedes a company's ability to reinvest, and the "10
percent legacy floor" is a disincentive to investment in both a
low-price environment and in an opportunistic high investment
environment, he concluded.
MR. MITCHELL, in response to a question, said that
ConocoPhillips does purchase credits.
3:58:16 PM
MR. TAYLOR, in response to a further question, offered his
belief that there is good resource potential on the North Slope,
though there are challenges with regard to the pursuit of
technology, the addressing of the heavy oil reserves, and the
continuation of a healthy price forecast. The rate of
production over the next 10 years will depends on the amount
that investors are willing to risk and pursue, and with a
healthy investment environment and a returning of investments in
the legacy assets, there is a lot of potential.
REPRESENTATIVE NEUMAN asked whether ConocoPhillips has had
discussions with the administration regarding the future of oil
and gas in Alaska.
MR. TAYLOR said that ConocoPhillips is very open to such
discussions, but is not currently involved in any specific
negotiations.
The committee took an at-ease from 4:00 p.m. to 4:20 p.m.
4:20:18 PM
KEN THOMPSON, Managing Director, Alaska Venture Capital Group
(AVCG) LLC, paraphrased from his written testimony, which read
in part [original punctuation provided along with some
formatting changes]:
I am the Managing Director for Alaska Venture Capital
Group, or AVCG LLC, an independent oil exploration
company formed with a sole focus on the North Slope of
Alaska. AVCG is a privately held member LLC comprised
of private equity investors made up of 15 independent
oil and gas companies and individuals from Kansas and
me as an owner/member partner from Alaska. AVCG has a
technical and operational services' subsidiary company
called Brooks Range Petroleum, with offices and staff
in Anchorage. In Alaska and on the North Slope, we
operate under the name Brooks Range Petroleum.
AVCG has lease holdings and explores currently only in
Alaska...and nowhere else. AVCG/Brooks Range
Petroleum likes to think of our company as "Alaska's
Independent Oil and Gas Company."
AVCG LLC has been very active in the past seven North
Slope areawide lease sales and active in acquiring
acreage held by other companies where we see
potential. We and our partners currently hold over
300,000 acres of exploration leases in five
exploration prospect areas on the Slope. Our
exploration strategy is to explore in the central part
of the North Slope for fields in the 10-100+ million
barrels range, fields that may be too small for the
giant producers but satisfy as niche fields that can
be "company makers" for a small independent. We
believe there are hundreds of millions if not billions
of barrels of oil left on the central North Slope in
smaller fields of this size for small independents
like ours that want to take this type of exploration
risk.
Last year, AVCG LLC announced joint venture agreements
with two Canadian independents, TG World Energy and
Bow Valley Energy, and with a private exploration
company from Houston, Ramshorn Exploration. Together,
as working interest co-owners we are exploring the
central part of the North Slope.
In the winter of 2006, AVCG participated with an
ownership interest in the Cronus exploration well
about 10 miles southwest of the Kuparuk Field,
operated by Pioneer Natural Resources. Unfortunately,
that well was a dry hole.
This past winter for the first time, our operations
subsidiary, Brooks Range Petroleum operated the
drilling of two exploration wells for our working
interest partners in the Gwydyr Bay area of the North
Slope, just northwest of Prudhoe Bay. One well, the
Sak River #1, was a dry hole, but we were excited to
announce earlier this year that our Northshore #1 well
northwest of the Prudhoe Bay Field did strike oil. We
plan to complete and test this well this winter. In
addition, we ran a 130-square mile 3D seismic survey
over our acreage and surrounding area in the Gwydyr
Bay area on the North Slope. In total this past
drilling season, our JV Group invested over $44
million on land, seismic and drilling activities.
This winter our Joint Venture Group will be among the
most active of explorers as we plan to shoot over 200
square miles of new seismic data on the extreme
western and eastern sides of the Central North Slope
and to drill up to four exploration wells. We plan to
test the Northshore #1 well and also drill one or two
other exploration wells nearby to see if we can
discover a sufficient volume of oil to warrant a
commercial development at Gywdyr Bay. We will drill
our Tofkat #1 well south of the Alpine Field and also
drill a fourth exploration well on a prospect to be
named. In total, our group will spend over $40
million in seismic and exploratory drilling in winter
2008. If our Northshore oil completion test is as
suspected and one of the wells strikes oil close by,
we may proceed with Northshore development with more
substantial capital investment in the second half of
2008.
My comments today represent the perspectives of a
small, independent exploration company that is
actively exploring on the North Slope with a good
level of activity, generally on prospects that because
of smaller size no longer interests the major
companies. At the end of next drilling season, AVCG
since 1999 and our partners since last year will have
jointly invested over $100 million in Alaska even
though none in our group have generated any revenues
yet from Alaska oil, so we sincerely appreciate being
listened to. We think in the long run we can bring
substantial, incremental value to the State of Alaska.
Please wish us good luck.
Many of you also know me as the past President of ARCO
Alaska, Inc. from 1994-1998. I also served as
Executive Vice-President for ARCO and head of global
oil and gas exploration for ARCO. I do have
exploration and production experience in 10 U.S.
states and in over 20 countries throughout the world,
so I'll also share my perspective in how I see the
ACES bill in the context of competitiveness in the
United States and in the world.
General Comments On ACES Legislation
At this point, I would like to address various key
points in the ACES legislation.
First, our company prefers that the PPT be allowed to
run its course in the next few years, and that ACES
not be approved with its current provisions. I agree
with Dr. Pedro van Meurs that in the light of
declining oil production in the state of Alaska and
prospectivity trending to smaller field sizes, the
State should not once again increase its taxes after
having done so last year. I will tell you that when
recruiting companies to join in our Alaska ventures in
2005 and 2006, many were concerned about the threat of
tax increases in Alaska. PPT proved tax increases
were not a threat but a reality. Adding yet another
tax increase via the ACES bill this year shows
instability in Alaska's tax policy which results in
uncertainty and risk when making investment decisions.
I heard that consultant Daniel Johnston differed
strongly from Dr. van Meurs and urged the oil industry
to understand the "cloud of corruption" over the
existing Petroleum Profits Tax, or PPT, and that this
alone provides a good reason to change PPT. I
challenge Daniel Johnston that the bushel should not
be thrown out because of a few bad apples.
In fact, last year during the PPT debates, I recall
those who are guilty of paying bribes and some who are
accused of taking bribes actually supported a 20% base
tax rate, not the 22.5% base rate that was finally
adopted. In fact, I'd like to think that the almost
all in the Legislature and in Industry were honest,
that they could be trusted in their deliberations last
year, and that the final answer of PPT was a good
answer and an honorable answer.
It is also very important to keep in mind that the
progressivity tax was added at high oil prices to
drive the real tax rate to even higher levels than
22.5%, with a range exceeding 30% now possible at
certain prices. And let's not forget to tack on the
royalty, the corporate tax, the ad valorem property
tax, and environmental and permitting fees. It
appeared to me that the checks and balances in the
system worked in the Legislature last year, and I
applaud the honesty of the legislators who in the end
made a positive difference.
But I sit here feeling as if the honest and
trustworthy investors in this industry are being
punished alongside the guilty. I personally think
this will have negative consequences for Alaska in the
long haul in relationships and even in sustainable
increased value.
But I am politically astute enough to know that the
ACES train is moving fast down the track, so I can
stand out of the way or jump on board and try to make
the ACES bill better before we reach derailment in the
long-term relationships between this industry I love
and this State I love.
So, I have some suggestions of things not to change
and things to change in the ACES proposal.
Five Things Not To Change In ACES
1) Keep the exploration and development investment tax
credits. For a small explorer startup company like
AVCG LLC, the exploration economics with the
exploration tax credits ranging from 20-40% as
provided by PPT and with ACES are more favorable with
an improvement in the investor's rate of return as
compared with Alaska's old severance tax system.
Near-term cash flow because of the investment tax
credits is higher which improves the return on
investment. Plus refund of cash to companies like
AVCG and our working interest partners via the credits
mean that we can apply that cash to our capital budget
the next year to run adequate seismic and do
additional drilling that increases the chance of more
oil production and reserves for us and for the State.
Likewise, the credits for losses for a startup company
like ours while we establish production and also the
development investment credit can take substantial
risk out of development of smaller fields that our
company is focusing on. May of these smaller fields
can add up over time and provide significant
incremental revenue to the State.
2) Keep the "standard tax deduction/exemption" for
smaller companies. The "Small Producer Tax Credit"
that exempts up to the first $12,000,000 in production
taxes for smaller companies can allow us to return a
larger share of our annual cash flow for exploration
and investment while we build the company to a
critical mass of reserves and production necessary to
expand staffing and have a routine level of major
capital spending each year.
3) Keep the new ACES tax credit allowance for
qualified delineation wells. A new proposal in the
ACES bill that was not in the PPT law is the possible
tax credit allowance for the investment in up to two
delineation wells following a discovery. This would
be very helpful to small explorers as well as for
large companies on the North Slope where often one
well is not enough to determine if field size is large
enough to warrant development.
A real case in point is that should we have a
discovery this coming winter at our Tofkat exploration
well on the western side of the Slope, we will have to
drill one or two delineation wells to confirm if field
size is sufficient to develop the resource at this
remote location. Often, due to the nature of these
complex stratigraphic traps where sands unpredictably
come and go, the delineation wells can be almost as
risky as the initial exploration well. Having a
credit where the State, in a real sense, is sharing in
the risk will - I think - expedite delineation of new
fields and advance development for revenues.
4) Keep the revised progressivity tax rate at 0.2% per
dollar increase in oil price. The PPT tax law had an
incremental tax rate of 0.25% per each dollar increase
in oil price above a trigger price while the new ACES
reduces this incremental tax rate to 0.2% per dollar
increase in oil price at a trigger price. While we
can debate all day long the competitiveness of
Alaska's tax rate with other countries' fiscal
systems, giving some reduction in this surcharge keeps
the government take at more reasonable levels.
However, as I'll outline below, I would change the
ACES trigger price back to $40 per barrel net and not
the proposed $30 per barrel net if Alaska wants to
better balance revenues with industry capital
investment at low prices as I'll more fully discuss.
5) Do establish the Oil and Gas Tax Credit Fund for
the purposes of purchasing certain tax credits from
explorers and producers. This ACES provision would
establish a procedure and standard for appropriation
into this fund and management of this fund. Having a
clear and transparent way for small explorers to
receive their credits at full value is extremely
important for AVCG to then be able to plow those
credits back into seismic and exploration on the North
Slope.
MR. THOMPSON, in response to a question, said that under the
current PPT legislation, an exploration well, for example, can
get a tax credit of up to 20 percent; however, if that well is
more than 25 miles away from an exiting unit, it could get a tax
credit as high as 40 percent. Those credits can be refunded by
the state, or they can be sold to producers. For a company like
AVCG, that is very important. Also under PPT, as well as under
ACES, there is a 40 percent tax credit for "new seismic" that
qualifies. Such credits allow the state to share in some of the
exploration risk, and allow companies such as his to perhaps
drill [an] extra exploration well per year, and this improves
the chance of exploratory discovery.
4:38:13 PM
REPRESENTATIVE NEUMAN surmised that Mr. Thompson is in favor of
keeping progressivity at .2 percent and start at $40, and keep
the PPT rate at 22.5 percent.
MR. THOMPSON concurred, and opined that the state's consultants
didn't show enough with regard to the competitive position of
Alaska relative to other states and other countries. He also
opined that the government's percentage may need to be adjusted
if the goal is for Alaska to remain competitive with the Gulf of
Mexico or a few other states.
CHAIR OLSON mentioned that the administration has been asked to
provide the committee with the tax information and tax structure
of four of the states that Mr. Thompson's written testimony
refers to.
MR. THOMPSON said that a DOR update will be helpful, and
mentioned that most of the AVCG's investors only invest in
projects in the U.S.
4:40:38 PM
MR. THOMPSON continued paraphrasing from his written testimony,
which read in part [original punctuation provided along with
some formatting changes]:
Four Things To Change In ACES
1) Change the recovery of tax credits from two years
as proposed in ACES back to the recovery of credits in
one year currently provided for in the PPT law. In
the PPT law, a company could file for the various
credits, and if approved, would receive those full
capital credits not to exceed credits of $25 million
per company. In the new ACES law, while the cap has
been removed which is very positive, the credits are
refunded over two years instead of over one year,
e.g., 50% of qualified credits can be applied for in
the first year once a well is completed or abandoned
and 50% in the following year.
For a small company like ours, this will definitely
affect our capital spending in a given winter as we
plow all the credit refunds back into seismic or
exploration drilling. As a very real example, AVCG
and our working interest owners are projecting to
spend $41 million in seismic and exploration drilling
this coming winter and likely around the same in 2009.
We calculate that we could receive $16 million cash in
qualified credits in mid-year 2008. So essentially,
our working interest owners are planning to provide
cash out of pocket of $25 million for the 2009
drilling season; this is a fixed number based on cash
availability in these small companies to spend toward
the Alaska portfolio. If the State refunds only one-
half of this credit in the first year, or only $8
million instead of $16 million, AVCG and our partners
will still provide $25 million out of our pockets as
now planned and budgeted...meaning our overall
spending in 2009 will be $33 million, not $41 million,
i.e. $25 million from our available funds and only
$8MM from the State. This would mean one less well
that will be drilled by our group in 2009. And one
less chance for another discovery that eventually
could provide revenues to us all. With small
companies, this is just the way our cash flow
situation works. And for some of our AVCG investors
like me, when I say "out of pocket," I mean "out of
pocket."
So, we hope the full credit can be applied for and
refunded in a given year. We hope this happens for
all of industry. As an innovative compromise,
however, the Legislature may consider a "Small Company
Refund" provision that allows for companies that meet
the no production or low production measures in the
"Small Company Tax Credit" provision of the PPT law -
that remains in ACES - to receive tax credit refunds
that are fully refunded in the first year for
qualified costs. Once a company grows in production
beyond this "small company" measure with more
substantial cash flow, perhaps refunds of 50% each
year would apply as outlined in ACES.
MR. THOMPSON, in response to a comment, said that refunding
credits in the first year would allow a smaller business to
reinvest those funds that much sooner.
REPRESENTATIVE RAMRAS noted, however, that if the state spread
the refunding of those credits over two years, the state would
then have that much more money with which to provide state
services.
MR. THOMPSON argued that refunding credits over a two-year
period of time could defer the exploration of, and thus the
development of, resources that could help fund state services in
the future.
REPRESENTATIVE RAMRAS acknowledged that point.
4:47:36 PM
MR. THOMPSON continued paraphrasing from his written testimony,
which read in part [original punctuation provided along with
some formatting changes]:
2) Change the base tax rate in ACES from 25% back to
the PPT tax rate of 22.5%, and re-review again in 2011
after some time has passed as allowed for in current
law. As I mentioned in my introduction, I felt the
22.5% base tax rate was reasonable. And the real tax
rate is much higher with the tax progressivity factor.
But what is fair, and how exactly is "fair"
determined?
I saw a copy of a presentation entitled "Guiding
Principles For A New Production Tax System" by the
Department of Revenue urging the changes in ACES,
arguing that the average government take in various
international countries averaged 67% for all types of
fiscal regimes internationally, averaged 74% for
production sharing agreements, but only 55% for tax
and royalty regimes internationally. Somehow, the
Department of Revenue representatives concluded an
average of 68% as provided for in ACES would be close
to the average of 67% for all types of regimes
internationally.
First, the average recommended to Alaska is the
average of all regimes, i.e. the averaging of
government take from tax and royalty regimes with the
government take from production sharing agreement
(PSA) regimes. In some countries that I worked in
that had production sharing regimes, the risk profile
for capital development was often much different that
in regimes that use a tax and royalty regime such as
Alaska. In PSA countries, it was not unusual for a
producer on capital projects to have a very low
initial tax burden until the capital investment was
fully recovered plus a negotiated rate-of-return was
achieved. Then and only then was the government take
increased substantially...thus giving the average take
for such countries as 74%. But the risk profile was
often much better than Alaska, i.e. there was up front
recovery of capital and a preferred investor rate-of-
return. That is not the risk profile of Alaska when a
company first has production...the ACES high tax rate
and the added progressivity tax will start immediately
along with royalties, corporate taxes, property tax
and other charges rather than allowing for recovery of
capital and a contractual rate-of-return.
REPRESENTATIVE NEUMAN asked how most countries in the world,
with safe, but difficult environments, compare with regard to
the percentage of "government take."
MR. THOMPSON offered his understanding that the average
government take in countries where the fiscal system is most
like Alaska's is around 55 percent. Currently, in Alaska, under
the PPT legislation, the government take is approximately 60
percent. He reiterated that in countries with a PSA system, the
average government take is 74 percent, and suggested that the
legislature should spend more time looking at other regimes.
4:54:33 PM
MR. THOMPSON continued paraphrasing from his written testimony,
which read in part [original punctuation provided along with
some formatting changes]:
As another distinction, most of the individual people
and company investors specifically in AVCG, LLC, do
not consider international regimes as areas to
consider as competition for our investment dollars
with Alaska. Rather, the main competition for most
AVCG Owners' cash is in other states in the U.S. I
found it astounding and concerning that the average of
67% for all international regimes did not consider
weight-averaging in the major American producing
states. As examples, the current government takes in
the Gulf of Mexico offshore - one of the main
competing areas for Alaska investment dollars -
averages 45%. This is under consideration by the U.S.
government for increase, but it is highly doubtful
with the boom going on in deep water exploration and
development that the U.S. government would increase
the government take from 45% to 68%.
In other producing states that compete for investment
by our AVCG investors, the state and federal combined
government takes in 2006 were as follows and averaged
45-57%:
U.S. Gulf of Mexico 45%
Colorado 51%
Wyoming 52%
Kansas 53%
Texas 53%
New Mexico 53%
Oklahoma 53%
California 53%
Louisiana 57%
To my knowledge, these states do not have the added
progressivity surcharge tax which further separates
Alaska in government take from these competing states.
I would argue that Alaska should have a government
take of 55% if we were to maintain long-term
competitiveness with these other states for investment
dollars. Having said that, some of these states do
not have the prospectivity of Alaska, so Alaska could
command some premium in take, but certainly not as
high as being proposed in ACES.
REPRESENTATIVE DOOGAN asked whether Alaska's government take
includes royalty payments.
MR. THOMPSON said it does.
4:58:00 PM
REPRESENTATIVE DOOGAN surmised that if one were to compare tax
rates between Alaska and Texas, one would have to subtract
royalty payments.
MR. THOMPSON concurred, and then continued paraphrasing from his
written testimony, which read in part [original punctuation
provided along with some formatting changes]:
If Alaska set a government take at 60% to the
government and 40% to the investor, the ACES
legislation should be amended to allow for a base tax
rate of 22.5% not 25%, should be amended to allow for
a trigger price of $40 per barrel and not $30 per
barrel, and the incremental progressivity tax rate
increase should be 0.2% per dollar.
3) Change the trigger price to $40 per barrel net and
not $30 per barrel. If the government take is to be
the fair and equitable 60% and not the unfair 68%, the
trigger price should stay the same as in the PPT law,
i.e. $40 per barrel net. If Alaska is to share in
high prices with the progressivity surcharge tax, then
Alaska should share in the pain of low prices. To
amend the trigger price lower when and if prices
collapse will be a false economy measure for the State
of Alaska. When prices fall and a company's cash flow
is sharply reduced, capital spending will fall. A
"double whammy" to be taxed more with a progressivity
tax at lower prices further reduces the amount of
capital for reinvestment.
4) Consider some type of "Transitional Investment
Expenditure (TIE)" tax credit. This provision allowed
for in PPT was repealed in ACES. While this provision
does not greatly benefit our company, AVCG, because we
did not have large seismic or exploration drilling
costs between March 31, 2001, and April 1, 2006, it is
important to other major investors in Alaska.
As an example, the largest explorer and developer in
Alaska, ConocoPhillips, now with the ARCO heritage
assets was hardest hit in tax exposure with the change
from the old severance tax law to the PPT and now to
ACES. I simply think allowing a good steward who is
the largest explorer in Alaska some transition
allowance to ease the pain of greatly increased taxes
is the right thing to do and can only build better,
more trusting relationships. Again, this provision
does not greatly benefit our company, however.
Concluding Remarks
This concludes my remarks. I tried to share the
perspective of an independent exploration company that
only invests in Alaska. My ultimate wish would be for
the State to leave PPT alone and re-review it under
the law as planned in 2011 or perhaps even in 2010.
But if the ACES train has left the station and cannot
be stopped, I urge you to at least consider the five
things our company would not change in this bill and
the four things we would change.
The above comments are offered with a hope that there
can be an eventual win-win solution to this complex
subject of the State realizing more revenues at higher
prices while attracting exploration and development
investors who can also realize upside at higher prices
for the substantial risk they have taken in the remote
and harsh environment of the North Slope. In the end,
I hope both sides get a fair and equitable share at
all price levels.
And my comments are offered with the highest sincerity
that the State and Industry can someday restore a
mutual trust at all levels.
REPRESENTATIVE NEUMAN asked Mr. Thompson how he feels about
sharing seismic data.
5:04:07 PM
MR. THOMPSON said that he would love to acquire older seismic
data more readily at more reasonable prices, but acknowledged
that some things ought to be considered proprietary for awhile
because disclosure of such information might hurt a company's
competitive position. He relayed that he wishes there were a
"more reasonable" timeframe in which to share proprietary data,
whether it be 5 years or 10 years, because that could help
exploratory companies like his. He spoke of equipment and
technology that [such companies] use, and explained that this
use is possible because of "the seismic tax credits of 40
percent" that the state offers.
REPRESENTATIVE NEUMAN noted that the legislation contains the
phrase "on request, furnish records, files, and other
information ...", and asked Mr. Thompson to comment.
MR. THOMPSON opined that there are certain types of data that
really should be held confidential; there are some types of data
on federal acreage, for example, where the state is actually
competing in lease sales and although it would certainly be
appropriate for the DOR to see that data to ensure that the
provisions of statute are being complied with, making that same
data available to the DNR could affect competitiveness between
state and federal leases. He said that the AVCG is willing to
provide the necessary data, and that he agrees with earlier
comments that on all types of data, there are definitions of
certain things that have been worked out over the years, and so
his hope is that the state could adopt all those standard
definitions and accompanying procedures.
MR. THOMPSON said he does have a concern regarding agencies
being able to redefine things, because it just means one more
set of things to try to calculate. "I think what's revealed to
all investors in financial statements and to the [SEC] is the
right and fair way to go in providing different types of data,"
he remarked. With regard to the issue of providing forecasts,
such as cost forecasts, he said he doesn't mind providing
forecasts, but noted that Mother Nature doesn't always
cooperate.
REPRESENTATIVE RAMRAS asked Mr. Thompson whether the bill, if
passed as currently written, will improve the investment climate
in Alaska.
5:11:06 PM
MR. THOMPSON said he thinks it will diminish the investment
climate for his type of company. For example, if the AVCG does
not get its tax credits back next year for this winter's
activity, the company won't have as much capital for the
following winter, and this could result in one less well being
drilled then. He then reiterated some of his written comments
to illustrate another example.
MR. THOMPSON, in response to another question, said he thinks
that passage of the bill as currently written will help the
state realize a lot more income, at least in the beginning, but
it could have a different effect as time passes because there
will be a faster decline rate with regard to production on the
North Slope. He offered his belief that his suggested changes
to the bill will help the state and the industry find a better
balance, create more capital investment, lessen the decline
rate, and create more wealth for all parties. In response to a
question, he added, "I think the ... decline in the production
rates from ... all of Alaska will be less under ACES in the
three to four or five years than it would be under PPT.
[HB 2001 was held over.]
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at 5:16
p.m.
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