Legislature(2011 - 2012)HOUSE FINANCE 519
04/25/2012 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB3001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
April 25, 2012
1:07 p.m.
MEMBERS PRESENT
Representative Eric Feige, Co-Chair
Representative Paul Seaton, Co-Chair
Representative Peggy Wilson, Vice Chair
Representative Alan Dick
Representative Neal Foster
Representative Bob Herron
Representative Cathy Engstrom Munoz
Representative Berta Gardner
Representative Scott Kawasaki
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Mike Doogan
Representative Neal Foster
Representative Lance Pruitt
Representative Kurt Olson
Representative Dan Saddler
Representative Pete Petersen
Representative Chris Tuck
Senator Albert Kookesh
Senator Cathy Giessel
COMMITTEE CALENDAR
HOUSE BILL NO. 3001
"An Act relating to adjustments to oil and gas production tax
values based on a percentage of gross value at the point of
production for oil and gas produced from leases or properties
north of 68 degrees North latitude; relating to monthly
installment payments of the oil and gas production tax; relating
to the determinations of oil and gas production tax values;
relating to oil and gas production tax credits including
qualified capital credits for exploration, development, or
production; making conforming amendments; and providing for an
effective date."
- HEARD & HELD
PREVIOUS COMMITTEE ACTION
BILL: HB3001
SHORT TITLE: OIL AND GAS PRODUCTION TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
04/18/12 (H) READ THE FIRST TIME - REFERRALS
04/18/12 (H) RES, FIN
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WITNESS REGISTER
SCOTT JEPSEN, Vice President
External Affairs
ConocoPhillips Alaska, Inc.
Anchorage, Alaska
POSITION STATEMENT: Provided ConocoPhillips Alaska, Inc.'s
comments on HB 3001.
DAN CLARK, Manager
Strategy and Portfolio Management
ConocoPhillips Alaska, Inc.
Anchorage, Alaska
POSITION STATEMENT: Provided ConocoPhillips Alaska, Inc.'s
comments on HB 3001.
DAMIAN BILBAO, Head of Finance
Developments and Resources
BP
Anchorage, Alaska
POSITION STATEMENT: Provided BP's comments on HB 3001.
TODD ABBOTT, President
Pioneer Natural Resources, Alaska
Anchorage, Alaska
POSITION STATEMENT: Provided Pioneer Natural Resources'
comments on HB 3001.
KARA MORIARTY, Executive Director
Alaska Oil and Gas Association (AOGA)
Anchorage, Alaska
POSITION STATEMENT: Provided AOGA's comments on HB 3001.
ACTION NARRATIVE
1:07:13 PM
CO-CHAIR PAUL SEATON called the House Resources Standing
Committee meeting to order at 1:07 p.m. Representatives P.
Wilson, Dick, Foster, Herron, Feige, and Seaton were present at
the call to order. Representatives Munoz, Gardner, and Kawasaki
arrived as the meeting was in progress. In attendance from the
House Special Committee on Energy were Representatives Foster,
Olson, Pruitt, Saddler, Petersen, and Tuck. Also in attendance
were Representative Doogan and Senators Giessel and Kookesh.
HB3001-OIL AND GAS PRODUCTION TAX
1:08:08 PM
CO-CHAIR SEATON announced that the only order of business would
be invited testimony from the oil and gas industry regarding
HOUSE BILL NO. 3001, "An Act relating to adjustments to oil and
gas production tax values based on a percentage of gross value
at the point of production for oil and gas produced from leases
or properties north of 68 degrees North latitude; relating to
monthly installment payments of the oil and gas production tax;
relating to the determinations of oil and gas production tax
values; relating to oil and gas production tax credits including
qualified capital credits for exploration, development, or
production; making conforming amendments; and providing for an
effective date."
ConocoPhillips Alaska, Inc.
1:09:15 PM
CO-CHAIR SEATON invited ConocoPhillips Alaska, Inc. to provide
its testimony.
1:10:17 PM
SCOTT JEPSEN, Vice President, External Affairs, ConocoPhillips
Alaska, Inc., reviewed an outline of the discussion that he and
Mr. Clark intended to cover today, which included the latest
financial performance of ConocoPhillips; the potential in
Alaska, particularly in terms of the legacy fields; the existing
fiscal framework; and ConocoPhillips' commitment to spend
additional funds in Alaska if there are substantial changes to
the fiscal framework in Alaska.
1:11:13 PM
DAN CLARK, Manager, Strategy and Portfolio Management,
ConocoPhillips Alaska, Inc., referring to slide 3 entitled
"Latest Financial Performance", began by stating that although
ConocoPhillips Alaska, Inc. ("ConocoPhillips") does make money
in Alaska, there are significant benefits to the State of
Alaska. For the first quarter of 2012 ConocoPhillips earned
$616 million and paid $1.5 billion in taxes and royalties, of
which about $1.2 billion went to the State of Alaska. On a
daily basis, $13.1 million of taxes and estimated royalties and
$16.5 million of total government take go to the state. He
acknowledged that ConocoPhillips' first quarter earnings were
$173 million higher than they were for the fourth quarter of
2011 and attributed it to the four tankers in the water between
Valdez and the West Coast as of the end of December, which
resulted in additional deliveries to the West Coast that were
beyond ConocoPhillips' production. Although there have been
several comparisons in regard to the earnings in Alaska as
opposed to the Lower 48, he opined that such comparisons are
difficult because the makeup of the production is very
different. In fact, over half of ConocoPhillips' production in
the Lower 48 is natural gas production. When one reviews the
equivalent per barrel oil price for gas in the first quarter,
it's around $15-$16 per barrel versus $100-plus for oil.
Furthermore, when one considers ConocoPhillips' liquid
production in the Lower 48, a good proportion of that is natural
gas liquids. Those natural gas liquids are recovered from the
natural gas production and are a lower value.
1:13:52 PM
REPRESENTATIVE TUCK inquired as to how many tankers
ConocoPhillips run per year.
MR. CLARK said he didn't know, but offered to provide it to the
committee. He then informed the committee that a tanker equates
to about 900,000 barrels and with annual production of about
225,000-230,000 barrels a day one can sort of do the math.
1:14:24 PM
MR. JEPSEN referred to slide 4 entitled "Production is Declining
in Alaska", which is a chart that shows Lower 48 production and
Alaska production. In terms of oil, the Lower 48 is going
through a Renaissance and has been on a substantial incline
since 2008 with production increasing by about 25 percent.
Production has declined by about 15 percent during the same
timeframe in Alaska. He attributed the increased production in
the Lower 48 to use of fracking/horizontal drilling for shale
gas, resource potential, and higher oil prices. In Alaska, the
resource potential, price, and technology exist. However, the
problem with Alaska is that under Alaska's Clear and Equitable
Share (ACES) as oil prices change an investment in Alaska
doesn't result in the same upside as in other places. Mr.
Jepsen opined that the aforementioned is the deciding factor
with regard to what's holding Alaska back because the
ingredients for a substantial increase in investment in Alaska
are present and would have a substantial positive impact on the
production from the North Slope. Moving on to slide 5 entitled
"Legacy Fields are Key to Future Production", he highlighted
that the legacy fields accounted for about 90 percent of North
Slope production in 2011. Furthermore, future production on the
North Slope is by far the largest resource [in the state]. Mr.
Jepsen informed the committee that the data on slide 5 is from
the 2009 Department of Revenue (DOR) report that reviewed
production for the years 2010-2050. This report is used because
it was the last year in which the data is parsed in such detail.
The data represents future cumulative production during 2010-
2050. The combined production of Point Thomson, Nikaitchuq,
Liberty, and Oooguruk don't compare to the opportunities in the
legacy fields. He highlighted that the cumulative production
isn't riding the base decline into the ground, it's going to
require tens of billions of dollars to achieve it. Whether that
production is achieved over the next 30 years is a function of
whether Alaska can attract the capital investment necessary to
make the investments.
MR. JEPSEN continued on to slide 6 entitled "Opportunities
within Legacy Fields" and noted that ConocoPhillips drills
designer wells. Coil tubing drilling units are used to drill a
sidetrack from an existing well. The sidetrack can be from 500-
3,500 feet long horizontal into targeted sands as thin as 10
feet. Therefore, ConocoPhillips is developing a field within a
field. For instance, in the Kuparuk River Unit there are
isolated fault blocks that are targeted with these designer
wells. This new horizontal drilling and targeting technology
allows production in these isolated fault lines. This
technology, he opined, has been extremely leveraging for the
development of Prudhoe Bay and Kuparuk River Units and will
continue to be a development opportunity in the future. This
technology is also being used to drill into thin sands. When
considering the entire opportunity suite, ConocoPhillips
believes there could be more rigs drilling in Alaska if there
was the appropriate fiscal framework to make the case that
Alaska is as attractive for investment as other locations.
ConocoPhillips is spending more capital in the Lower 48 because
it doesn't see the upside for investments in Alaska. However, he
emphasized that he didn't want to leave the committee with the
impression that ConocoPhillips isn't drilling or pursuing
opportunities in Alaska as it spends about $900 million a year
in Alaska, which is ConocoPhillips' net shares for Alpine,
Prudhoe Bay, and Kuparuk units. Furthermore, ConocoPhillips is
drilling wells, shooting seismic, and pursuing facility
expansions where they make sense. Again, with a different
fiscal framework, he opined that there could be more investment
in Alaska. He then addressed viscous oil and stated that the
viscous and heavy oil reservoirs on the North Slope are an
immense resource. ConocoPhillips, its predecessor ARCO, and BP
have spent the last 30-plus years trying to find technologies to
make viscous and heavy oil commercial. In fact, he recalled
that his first job in Alaska in 1982 was to find a way to make
West Sak and Ugnu commercial. However, after enough data was
collected, it was determined that the heavy oil doesn't float
and thus the focus turned to the viscous oil in West Sak. In
the intervening years, technological advancements have been
made. The best part of West Sak and Kuparuk is on stream and
producing about 14,000 barrels a day. Mr. Jepsen related that
although there have been problems, a lot has been learned. For
example, there was massive water breakthrough for which
technology was developed and is being tried on a well-by-well
basis. Furthermore, progress is being made in regard to the
problems with drilling the wells, pumps, and sand.
ConocoPhillips' current plan is to expand its West Sak
production from the core area to the Eastern North East West
Sak. Although it's an area that doesn't have quite as good oil,
ConocoPhillips believes it can be produced with the technology
that's available today. However, it's a high risk and
technologically challenging area. He noted that the extent and
pace at which ConocoPhillips pursues that opportunity depends
upon being able to make the case that capital investment in
Alaska is as attractive as other opportunities as other places
in the world and the Lower 48. In the price world of today with
the technology that has been developed, ConocoPhillips is
opportunity rich that is ConocoPhillips doesn't have enough
capital to pursue every opportunity around the world.
Therefore, the company has to consider those places where one
would get the best return on the investment. Alaska could do a
lot to improve its position, he reiterated. Mr. Jepsen told the
committee that exploration and satellite opportunities are still
available, particularly in the Alpine and Kuparuk River Units.
As some may know, ConocoPhillips has been active in lease sales
recently and the hope is that there will be sufficient change in
Alaska's fiscal framework so that more investment will be
attracted and ConocoPhillips can pursue some of those
exploration opportunities. He noted that ConocoPhillips is
advancing and pursuing engineering on some of the opportunities
in the legacy fields. However, ConocoPhillips won't make the
long lead time, highly capital intensive investment necessary to
pursue those until the case can be made that these investments
are the best place for ConocoPhillips to invest its money.
ConocoPhillips will continue to seek additional opportunities
[in Alaska], he said.
MR. JEPSEN then turned to heavy oil technologies. The heavy oil
is more viscous, and thus thicker and heavier than what is in
West Sak. Much of this heavy oil is located in very cold parts
of the reservoir and some of the heavy oil just doesn't flow.
Therefore, heavy oil is challenging, particularly in addition to
the environmental constraints in Alaska that require development
from central locations. Although ConocoPhillips has been
reviewing ways to produce this heavy oil resource for over 30
years, the commercial technology that would allow production of
this heavy oil doesn't exist yet. Therefore, he cautioned tax
changes that target heavy oil because the technology to address
heavy oil doesn't exist yet and placing an emphasis on it won't
bring that oil to market. Furthermore, he opined that long term
this isn't the prolific reservoir similar to Prudhoe Bay and
Kuparuk River Units. The rate of the heavy oil will be a small
percentage of what has been experienced with the light oil
reservoirs. Still, heavy oil is a large resource that
ConocoPhillips will pursue, but the focus will be on the
locations where results with significant impact to Alaska and
North Slope production can be achieved.
1:28:04 PM
MR. CLARK then directed attention to slide 7 entitled "ACES -
High Average Government Take" which presents a chart from PFC
Energy that compares worldwide fiscal regimes at $100 per
barrel. He noted that for those areas with private royalties,
the private royalties are included in the government take
numbers. He highlighted that the red bars on the chart
represent ACES, while the gold bars represent other countries
included in the Organization for Economic Cooperation and
Development (OECD). Relative to the other OECD countries, ACES
at $100 per barrel is a high government take, he pointed out.
He further pointed out that at $140 per barrel, the red bars
representing existing and new development in Alaska under ACES
would move up and there would be higher government takes.
Basically, the bar representing the existing producer in Alaska
would move above Norway and the bar representing the new
development in Alaska would move up above Trinidad. The
aforementioned highlights the effect of the progressivity
mechanism within ACES.
1:29:48 PM
REPRESENTATIVE PETERSEN asked if the chart on slide 7 takes into
account the tax credits offered in Alaska.
MR. CLARK replied yes.
1:30:05 PM
REPRESENTATIVE HERRON inquired as to the location of the red
bars representing Alaska under ACES if HB 3001 were implemented.
MR. CLARK said he hasn't seen such a chart from PFC Energy.
However, he opined that the fiscal outcome of the implementation
of HB 3001 would be similar to that of HB 110.
REPRESENTATIVE HERRON asked whether ConocoPhillips has done any
modeling on [the fiscal results of the implementation of
HB 3001].
MR. CLARK answered that he would provide analysis during his
presentation.
1:31:00 PM
MR. CLARK, referring to the chart on slide 8, reminded the
committee that progressivity is a situation in which as oil
price or margin increases the state/government take increases.
He explained that the chart on slide 8 relates the percent share
of the industry, the federal government, and the state. This
chart, he clarified, represents a marginal take rate.
Therefore, it measures the take by a party as the price of oil
increases. For example, if the price of oil rises from $110 per
barrel to $111 per barrel, the total government take of that
incremental dollar would be over 86 percent under ACES while the
industry share would be about 13.5 percent of that. Mr. Clark
then highlighted that progressivity has been impactful from $70-
$125 price range and takes a larger and larger share of each
incremental dollar. He pointed out that the chart on slide 8 is
based on Fall 2011 Revenue Source Book data for fiscal year
2013.
1:33:03 PM
CO-CHAIR SEATON pointed out that the chart specifies the prices
are based on Alaska North Slope (ANS) West Coast oil prices
although the percentages are based on production tax value,
which subtracts all costs. Therefore, he surmised that it would
be company specific such that the chart relates an average.
MR. CLARK replied yes, adding that since the chart is based on
Revenue Source Book data it's an amalgamation of the industry.
For this fiscal year, the price [of ANS West Coast oil] is about
$32 per barrel of oil.
MR. JEPSEN clarified that the chart is relating the incremental
dollar after all the costs and tax credits have been
subtracted. Therefore, it's the marginal share of the profit.
Once a $110 per barrel is earned, for the next dollar earned
after $110 there are no more costs, tax credits, or capital
costs to be subtracted from that dollar. Therefore, a pure $1
goes to the company and of that next dollar, at $110 per barrel,
the state and federal government will take about $0.86.
CO-CHAIR SEATON said members are familiar with effective tax
rates on the overall barrel price sale versus the marginal that
merely looks at an incremental price difference between one
barrel and another. Although the numbers used on the chart on
slide 8 may be from the Fall 2011 Revenue Source Book, he
surmised that they're company specific in terms of the
production tax value and that's from where incremental value
comes.
MR. CLARK offered that this slide could've utilized the
production tax value margin (PTV), which would mean that $32
would be subtracted from each of the price points to obtain the
margin.
1:35:27 PM
REPRESENTATIVE SADDLER asked if this chart refers to the
marginal share of the entire barrel of oil, not the profit.
MR. CLARK said that the basic presumption is that the
incremental dollar is all profit and nothing else is changing.
For further clarification, Mr. Clark specified that both profit
and the incremental price per barrel are the same.
1:36:03 PM
REPRESENTATIVE TUCK asked whether the chart assumes the
particular company isn't taking advantage of the tax credit as
it lowers the tax rate on progressivity in addition to what the
company can subtract for the credit.
MR. CLARK explained that the tax works as follows: the West
Coast revenue is calculated, transportation costs are subtracted
as are all the qualified operating and capital expenses to reach
a PTV, which is where the tax is calculated. Furthermore, for
qualified capital expenditures there is tax credit, depending
upon the type of expenditure. Once the tax is calculated, [the
qualified capital expenditures] can be deducted. He further
explained that in this particular analysis, when the price
increases by $1, there is no change in credits, investment, or
costs. Therefore, there's no particular impact on this marginal
share take in that scenario.
REPRESENTATIVE TUCK surmised then that in relation to this
chart, it's irrelevant whether a company took advantage of the
tax credits.
MR. CLARK clarified that at an oil price of $110, the tax
credits would've already been taken advantage of because there
is no change in cost when going from $110 to $111 per barrel of
oil. In further response to Representative Tuck, Mr. Clark
confirmed that whether a company takes full or partial advantage
of the tax credits, the chart remains the same.
1:37:58 PM
MR. CLARK, returning to the presentation, directed attention to
the chart on slide 9, which further illustrates the impact of
progressivity. This chart uses dollar per barrel in order to
take out the effects of changes in production. He highlighted
that the green line representing ConocoPhillips' net income
stays in a fairly tight range of plus or minus $20 per barrel,
regardless of oil prices. Therefore, it illustrates that the
upside isn't with the investor, ConocoPhillips. However, the
state's share, represented by the red line, tracks fairly
closely with oil price and thus when the oil price is up, the
upside/share goes to the state. Moving on to slide 10
entitled "HB 3001 Provides More Equitable Split", he explained
that the graphic illustrates the split of a barrel of oil in
terms of costs, industry share, federal income tax, and Alaska's
share at three different prices. Under ACES, when the price of
oil rises from $100 to $150 per barrel the industry share
increases from $20 per barrel to $28 per barrel, whereas the
Alaska share increases from $37 to $75 per barrel. Again,
that's the impact of progressivity in which the state takes the
predominant share of the upside. In comparison, the graphic
illustrates that under HB 3001 when oil is $100 per barrel the
industry share increases from $23 to $36 per barrel while for
the state the increase is from $32 per barrel to $62 per barrel.
Although under HB 3001 the predominant portion of the upside
still goes to the state, ConocoPhillips believes HB 3001 offers
a more equitable split between the state and the industry.
1:41:46 PM
REPRESENTATIVE GARDNER recalled that one of the goals of ACES is
to encourage investment of [the investor's] profits thereby the
tax rate is reduced on every dollar earned. She asked:
Does that do that at all in your first, say, $100
barrel oil under ACES you have $37, the state's got
$32. If you take ... $7 of those $37 invest in
Alaska, the state picks up however much in the credits
so of the $7 you invest it's roughly what would it be
that we pay for and then it takes your total tax
percentage rate down all the way, right?
MR. CLARK reminded the committee that the deductions for ACES
for capital and operating expenses are generous and all can be
taken in the first year. That and the credits are available
because the tax rates are so high. While this reflects a
similar level of investment, if a company increases its
investment it would reduce their tax rate. However, the company
would have to operate under the presumption that it's investing
in something that will generate a return.
REPRESENTATIVE GARDNER emphasized, "That's the whole point."
She opined that it provides an extra reason to invest and the
expectation is that a company would invest in something that
generates return, whether it's under ACES or HB 3001.
MR. JEPSEN explained that tax credits lower the tax bill, but
don't change the tax rate. The tax credits are applied after
the tax is calculated. Mr. Jepsen related his understanding
that Representative Gardner is referring to the effective tax
rate in which the tax paid is divided by taxable revenue, which
will change as a function of tax credits. However, the
statutory tax rate doesn't change and the marginal tax rate is
quite high.
REPRESENTATIVE GARDNER related her understanding that the point
of progressivity is based, in part, on the level of profit. If
the company's profit is less, then the progressivity decreases.
MR. JEPSEN specified that as the PTV decreases so does the
progressivity. Under ACES, the base rate is 25 percent until
the minimum is reached. Mr. Jepsen opined that the
aforementioned makes Alaska a good place for investment. If
there was ACES, with no progressivity, there would be more
investment in Alaska, he further opined.
1:45:10 PM
CO-CHAIR SEATON recalled the statement that the credits and
instantaneous deductibility need to be high because the tax rate
is high. In order to balance the aforementioned, does the
credit and instantaneous deductibility need to be lowered so the
two balance, he asked.
MR. JEPSEN answered that the committee should review that and
determine the appropriate balance between tax rates and tax
credits. He reminded the committee that ConocoPhillips reviews
the total government share and the industry share and whether
it's sufficient to attract incremental capital.
1:46:15 PM
REPRESENTATIVE GARDNER clarified that she meant that spending
lowers a company's tax rate and asked if that's correct.
MR. JEPSEN replied that is correct.
1:46:33 PM
REPRESENTATIVE HERRON referred to the historical data on slide 9
and asked if HB 3001 passed, would ConocoPhillips' net income
and the state's share remain the same [as it does under ACES].
MR. CLARK said that although he hasn't done that specific
calculation, the line representing ConocoPhillips' net income
and the state's share would move closer together and track
similarly.
1:47:22 PM
REPRESENTATIVE MUNOZ inquired as to how the return on capital in
Alaska compares to that of the Lower 48.
MR. CLARK, reviewing 2011 numbers for ConocoPhillips, related
that in Alaska the cash margin was about $31 per barrel, while
plays such as the Eagle Ford and the Bakken in the Lower 48 have
significantly higher cash margins, closer to $50 per barrel.
Although the earnings are less in the Lower 48, when one reviews
specific oil plays there are much higher returns and that's what
attracts the capital in ConocoPhillips.
1:48:41 PM
CO-CHAIR SEATON requested an explanation of adding depreciation
back in and how that influences the fact that Alaska has no
depreciation because Alaska allows the capital to be written off
in the first year.
MR. JEPSEN specified that Co-Chair Seaton is referring to net
income according to generally accepted accounting principles
(GAAP) rules. The deductibility under ACES affects
ConocoPhillips' tax rate, but doesn't impact the company's
federal depreciation. Therefore, it's basically an after tax
calculation that takes into consideration state and federal
taxes. While ConocoPhillips is able to deduct operating and
capital costs from revenue in order to determine the tax rate in
Alaska, it's not the same as the depreciation for the federal
tax return. Basically, it's the units of production, depletion
of ConocoPhillips' capital invested over the North Slope. He
said that it's a number that stays relatively constant over
time. [Depreciation] is added back in because it reaches a
[more accurate] cash position after tax than if it's subtracted.
Mr. Jepsen said that's how the accountants require
ConocoPhillips account for income as a large corporation. In
further response to Co-Chair Seaton, Mr. Jepsen agreed to
provide further information on the aforementioned calculation.
1:50:35 PM
MR. JEPSEN, continuing on to slide 11 entitled "ConocoPhillips
Capital Expenditures", directed attention to the chart that
relates ConocoPhillips' capital investment profile in Alaska
versus the Lower 48. As the chart indicates ConocoPhillips'
investment in Alaska is fairly flat, which he attributed to the
lack of returns in Alaska versus what is available in other
places. The capital is going to places in the Lower 48 such as
the Bakken, Eagle Ford, and Permian Basin. He noted that many
of these locations are very mature basins. For instance,
Permian Basin has been abandoned four to five times over the
course of its history and reopened due to a technological or
price breakthrough. Currently, Permian Basin is being reopened
due to technological and price breakthroughs. Mr. Jepsen
related his belief that there is a similar opportunity set in
Alaska, and to some extent it's not realized how good it could
be because Alaska doesn't have the same profit environment that
oil companies experience in the Lower 48.
MR. JEPSEN concluded with slide 12 that is a letter to all
Alaskans from ConocoPhillips. He acknowledged that there is
concern with regard to how the state can be certain that oil
companies will invest more money and produce the results
expected by the state enacting a tax change. However, by the
nature of corporations and the size of investments required,
it's difficult to sign a contract and move through the steps to
the commitment desired. He partially attributed the
aforementioned to the fact that a lot of these projects aren't
at the point of going to the board of directors for approval.
This letter attempts to place a lot of ConocoPhillips'
credibility on the table by saying that if it observes changes
in Alaska's fiscal system similar to those proposed in HB 110,
ConocoPhillips will pursue more drilling activities in the North
Slope, more satellite development and more exploration
opportunities, and work with partners at Prudhoe Bay. He opined
that the most underappreciated is that the $5 billion associated
with the aforementioned opportunities is the tip of the iceberg
and not the entire opportunity suite. Drawing from his years in
the business, Mr. Jepsen emphasized that ConocoPhillips doesn't
know today what it will be doing 20 years from now. The oil
industry isn't that predictable, particularly since advances in
technology continuously create new opportunities. For instance,
in 1982 ConocoPhillips thought it would be done with Prudhoe Bay
and Kuparuk River Unit by now. In fact, it was thought that the
Trans-Alaska Pipeline System (TAPS) would be shut down by now.
However, the situation is far from the aforementioned. Mr.
Jepsen closed by relating that if Alaska implements a fiscal
framework that allows investors to invest in the best
opportunities, it will result in the best situation for the oil
companies as well as the state. Such a change in the fiscal
framework will result in more production, investment in
[opportunities] with the nearest-term impact and the most
profitability. Oil companies are resource focused, and thus
they will continue to focus on heavy oil; there is no need for
special legislation or tax breaks to incentivize the oil
companies to invest. Oil companies have been doing so for 30
years, without the tax focus. Rather, he emphasized that oil
companies need a tax regime that makes Alaska welcoming in terms
of investing money and applies across the board. In parting,
Mr. Jepsen related that the legacy fields hold the key to
Alaska's future. Although the North Slope Basin has such
potential, the fiscal framework in Alaska poses a challenge.
1:56:15 PM
CO-CHAIR SEATON highlighted charts from the Alaska Oil and Gas
Conservation Commission (AOGCC) regarding the number of wells
drilled by ConocoPhillips, which doesn't seem to have any
relationship to the price or the tax regime. Therefore, he
questioned why the legislature should anticipate that a change
in the fiscal framework would result in a change in the number
of wells per year that ConocoPhillips drills.
MR. JEPSEN informed the committee that from 1996 to now there
has been a significant difference in the type of wells drilled.
In the past, ConocoPhillips drilled rotary wells with a big hole
and a single bore, whereas now they might enter 15 well bores
and drill three to six horizontal wells from that individual
well bore. Therefore, the wells ConocoPhillips drills today are
more cost effective wells. The difference between 1996 and
today is the type of well drilled and how they are counted.
ConocoPhillips is not drilling 66 new holes in the ground from
the surface down every year, rather the total number of wells
includes the well bores being drilled from existing wells.
From 1996 until a few years ago, there was a relatively stable
oil price environment. Although the price of oil has increased
dramatically since 2007/2008, the response that has been
experienced elsewhere hasn't occurred in Alaska. He attributed
the aforementioned to the fact that Alaska doesn't have the same
overall economic impact of other locations.
1:59:02 PM
REPRESENTATIVE SADDLER surmised then that in 1996 ConocoPhillips
drilled 60 wells and now it's drilling multiple well bores from
those 60 wells. Therefore, it's 60 times a factor of three to
five.
MR. JEPSEN replied no, and clarified that ConocoPhillips might
have 10-15 existing well bores from which multi-laterals are
drilled. In further response, Mr. Jepsen said that he would
need to review the AOGCC data set before answering further
because there are many ways in which to define wells.
REPRESENTATIVE SADDLER then asked if more drilling is occurring
now.
MR. JEPSEN answered no, but confirmed that more well bores are
being drilled from existing wells. Again, he expressed the need
to review the AOGCC data.
2:01:05 PM
REPRESENTATIVE P. WILSON inquired as to how long after a new tax
regime is in place would the state see an increase in revenues
because of an increase in production.
MR. JEPSEN explained that when ConocoPhillips increases its
capital investment one would likely observe more jobs,
businesses, and a boost in the local economy across the state.
However, he cautioned that it takes time to get a drilling rig
to the North Slope. In fact, if a rig has to be built it could
possibly take two to three years, whereas refurbishing a
drilling rig from the Lower 48 might only take a year. If there
is the need for a substantial capital investment in a new
facility, it could take five to eight years before full
production. Therefore, the timeframe depends upon how
complicated the project. Mr. Jepsen confirmed that there won't
be an instantaneous response in terms of production as a result
of incremental capital investment, although there will be a
response in the local economy. He told the committee that
ConocoPhillips makes it a point to hire as many Alaskans as it
can.
REPRESENTATIVE P. WILSON asked if ConocoPhillips could provide
any idea how long it would take to make the pipeline fuller than
it is now.
MR. JEPSEN said that ConocoPhillips shares that goal of making
the pipeline fuller. However, how long it will take to flatten
and potentially reverse the decline will be a function of the
type of fiscal framework the state implements. In his opinion,
ACES doesn't work and is broken from the standpoint of
attracting additional investment in places where necessary. Mr.
Jepsen opined that the response from the producers will be
proportional to the change in the fiscal framework.
2:04:37 PM
REPRESENTATIVE PETERSEN requested an explanation of
ConocoPhillips reported 11,000 barrel per day increase in
production.
MR. CLARK reminded the committee that there was a shutdown on
TAPS for over a week, which was related to a leak. The
aforementioned was a significant impact to production, and thus
ConocoPhillips production last year was understated because of
the shutdown.
REPRESENTATIVE PETERSEN, referring to slide 11, pointed out that
the chart illustrates that the investment increases in the Lower
48 while remaining steady in Alaska. He asked whether
ConocoPhillips is drilling in the North Dakota area where he
recalled there is shale oil that requires drilling more often to
ensure constant production. In such a situation Representative
Petersen surmised that ConocoPhillips would need to invest more
in order to maintain production as compared to traditional oil
wells such as those on the North Slope.
MR. JEPSEN acknowledged that shale wells typically have steep
declines. If the goal is to maintain a flat or an increasing
production profile, one must drill at a fairly steady pace in
order to build upon past results. Therefore, Representative
Petersen's conclusion is fairly accurate. However, he noted
that on the North Slope the base decline in the existing fields
is about 15 percent and when horizontal wells are drilled there
are fairly steep declines after initial production as well.
2:07:07 PM
CO-CHAIR FEIGE remarked that the committee is reviewing all the
factors that go into investment decisions that companies make in
order to determine what the legislature can do with the state's
tax regime to encourage more production on the North Slope. He
then asked if the committee is going down the right path of
analysis.
MR. JEPSEN answered that it's appropriate for the committee tp
pursue the issues it believes necessary to better understand
where ACES ranks in comparison to other opportunities around the
world while trying to understand what's important to the
companies. The aforementioned is why ConocoPhillips wanted to
provide its insights to the committee in terms of how it makes
decisions with regard to where to invest capital. Mr. Jepsen
emphasized that ConocoPhillips isn't a single variable decision-
making company that is ConocoPhillips doesn't just review
present worth and rate of returns of a given project and invest.
ConocoPhillips considers political stability, size of the
resource, and long-term cash flow that might be generated from
that investment. In Alaska, when a company invests it receives
the capital and the tax credit, but once production begins the
[well] is part of the base and subject to the high tax rates of
ACES. Mr. Jepsen said that the long-term cash flow
opportunities in Alaska don't match up with other opportunities
that ConocoPhillips has. To the extent the committee can
understand and focus on the aforementioned, it would be helpful
in understanding what it will take to change the investment
climate in Alaska, he opined.
2:09:44 PM
CO-CHAIR SEATON related his understanding that Alaska represents
about 58 percent of ConocoPhillips' liquid production in North
America and 63-65 percent of ConocoPhillips' profits. He asked
how Alaska would balance that in terms of cash flow when the
reports that the cash flow per production from Alaska is higher
than that of the other investments ConocoPhillips makes.
MR. JEPSEN explained that when one reviews the data in terms of
liquids to liquids, Alaska isn't higher than the Lower 48 and
the places where ConocoPhillips is investing its money today.
Statistics that indicate Alaska is better include natural gas
production and natural gas liquids. There is a substantial
portion of ConocoPhillips business in the Lower 48 that account
for a lot of ConocoPhillips' production. Therefore, when all
those things are rolled together on an amalgamated basis for the
Lower 48, it amounts to a net income or cash margin per barrel
that's less than Alaska. However, if the low value portions
that ConocoPhillips isn't investing in any more are stripped out
and only ConocoPhillips' liquid plays are considered, it's an
entirely different story.
2:12:05 PM
REPRESENTATIVE GARDNER, referring to slide 12 and the
commitments to Alaska if HB 110 or similar legislation is
passed, asked whether the inverse statements are true if nothing
passes or nothing similar passes.
MR. JEPSEN responded that if things stay the same, Alaska should
expect the same focus as exists now. ConocoPhillips is still
drilling, shooting seismic, and considering other opportunities.
The difference is in terms of how fast the opportunities will be
pursued and whether ConocoPhillips can fully exploit those
opportunities. Mr. Jepsen opined:
So, really changing ACES is about realizing potential
that we have here in the state. If you don't change
ACES, ... we're not moving everything out of Alaska
tomorrow. We're still here, but you're basically
going to see the same kind of investment that we see
today. And I think we can have a much better future,
a stronger economy, more jobs, more business
opportunities in this state if we have a robust oil
and gas business here.
2:13:43 PM
REPRESENTATIVE FOSTER recalled the mention of the potential
reversal of the decline, and requested that ConocoPhillips
comment on that statement versus merely slowing the decline.
MR. JEPSEN reiterated that the results ConocoPhillips achieves
will be proportional to the changes in the fiscal framework. A
robust fiscal framework that allows investors to invest where
they think the best opportunities are will result in
opportunities that may not have been thought of earlier. He
expressed hope that shale oil, Great Bear, will be successful.
Although he acquiesced that there is more potential in the
legacy fields than the oil companies are willing to discuss, he
was fairly confident that there won't be much change in what's
happening in these fields if the fiscal structure doesn't
change. He pointed out that going from 6 percent to 4 percent
or 2 percent represent a substantial change to the state as it
enhances the economic future of the state and oil business.
2:15:03 PM
REPRESENTATIVE TUCK inquired as to ConocoPhillips' definition of
reasonable profit in order to result in more activity.
MR. JEPSEN clarified that ConocoPhillips has always and will
continue to meet its lease obligations. The discussion today is
regarding how to make Alaska a more attractive place for capital
investment. Under all the variables used to make investment
decisions, Alaska is handicapped by ACES.
REPRESENTATIVE TUCK then inquired as to what percentage of every
dollar Alaska gives to the industry is reinvested in Alaska.
MR. JEPSEN said he couldn't answer that at this time, but
offered that ConocoPhillips' response would be proportional [to
Alaska's fiscal framework]. He then encouraged the committee to
keep in mind that ConocoPhillips invests in Alaska because it
does make a profit. Although he predicted additional
investment, he maintained that ConocoPhillips will still have
profits that come out of the state.
2:17:07 PM
REPRESENTATIVE SADDLER inquired as to how long ConocoPhillips
will continue to do [business] in Alaska if there's no change
[in the fiscal framework]. More specifically, he inquired as to
what kind of future ConocoPhillips would predict for Alaska if
the pipeline continued for 50 years, as has been assured by a
judge, with no changes [in the fiscal framework].
MR. JEPSEN responded that he didn't want to discuss ongoing
litigation. With regard to how long ConocoPhillips will do what
it's doing, Mr. Jepsen said that will be a function of the price
environment, costs, profitability, and technical risks that tend
to increase as the fields mature. In further response to
Representative Saddler, Mr. Jepsen confirmed that the committee
can't assume that if the state does nothing, things will be fine
forever.
2:18:27 PM
CO-CHAIR FEIGE related his understanding that there is a limit
on the well spacing allowed in the Kuparuk River Unit, and asked
whether it would be a factor. Specifically, he asked whether
ConocoPhillips would be able to increase production if the well
spacing was reduced.
MR. JEPSEN, noting his presumption that Co-Chair Feige was
referring to well spacing for producers and injectors, he said
he wasn't aware that additional well spacing requests were
rejected. Typically, if a case for closer well spacing can be
made, it's brought before an entity such as AOGCC who determines
whether that's the best way to recover the resource from the
reservoir. Mr. Jepsen further said that he wasn't aware that
ConocoPhillips had any issues with well spacing, particularly in
the Kuparuk River Unit.
2:20:00 PM
CO-CHAIR SEATON asked whether ConocoPhillips considers the
reduction of the maximum production tax rate from 75 percent to
60 percent in HB 3001 as significant.
MR. JEPSEN remarked that if the maximum production tax rate was
reduced to the point that impacted the price range in which
ConocoPhillips is operating would be beneficial. However, if
the reduction only impacts the $180-$220 per barrel environment,
then it's not very helpful.
2:20:55 PM
REPRESENTATIVE MUNOZ requested examples of ConocoPhillips'
decision not to proceed with certain projects due to ACES.
MR. JEPSEN replied that the Eastern North East West Sak (NEWS)
project is very much at risk. Although ConocoPhillips may
pursue part of the Eastern NEWS project under ACES, no change to
ACES may impact how fast and the extent to which it's pursued.
The aforementioned is probably the case for most potential
projects. Currently, the magnitude of the state tax is fairly
significant, he remarked.
2:21:57 PM
CO-CHAIR SEATON highlighted that a royalty reduction application
is available for an uneconomic project. He inquired as to why
that isn't a factor for a project that's marginally economic.
MR. JEPSEN advised that he's not an expert on what's required to
seek royalty relief, but opined that the royalty relief statute
wasn't crafted to address [the fact] that every field, even with
a change in ACES, will have some accumulation that's uneconomic.
CO-CHAIR SEATON encouraged Mr. Jepsen to investigate the royalty
relief statute further.
2:22:57 PM
REPRESENTATIVE OLSON inquired as to states, provinces, or plays
in North America where ConocoPhillips is currently aggressive.
MR. JEPSEN answered that ConocoPhillips is aggressive in the oil
sands of Canada, the Bakken, Permian Basin, and Eagle Ford, all
of which are liquid plays and located in places with much more
favorable tax regimes than Alaska.
2:23:39 PM
MR. JEPSEN, in response to Representative Foster, explained that
Eastern NEWS is the next tranche of West Sak or viscous oil that
ConocoPhillips is considering developing.
2:24:03 PM
REPRESENTATIVE HERRON recalled that at the hearing yesterday
consultants advised the committee to negotiate a decline curve
and incentivize incremental production. He asked if a 2 percent
decline curve would be reasonable to negotiate.
MR. JEPSEN answered that a 2 percent decline curve would take a
lot of investment. Furthermore, he didn't believe it would
change much.
2:24:52 PM
REPRESENTATIVE GARDNER asked if a reduction in taxes by 30
percent would result in ConocoPhillips experiencing an increase
in investment by 30 percent.
MR. JEPSEN explained that the changes wouldn't be proportional
since the changes would be a function of the available projects
that make sense in the existing fiscal framework. Mr. Jepsen
clarified that he's saying that making the fiscal framework
better will result in more investment whereas a small change in
the fiscal framework will likely not result in any change in
behavior [from the producers].
2:26:09 PM
CO-CHAIR FEIGE inquired as to the best method to incentivize new
production in terms of the decline curve.
MR. JEPSEN responded that he would want to give that answer some
thought and consideration. ConocoPhillips believes there needs
to be a blanket change to the tax framework that applies to all
production in order to avoid complications arising from managing
a decline curve and tracking new, old, and incremental oil.
ConocoPhillips is looking for a way forward that makes Alaska a
good place to invest. Mr. Jepsen said that the focus of
ConocoPhillips is to establish a framework similar to what's in
Australia where the industry takes 40 percent of the net
[profits].
2:28:48 PM
CO-CHAIR FEIGE acknowledged that each well has its own decline
curve, but opined that tracking each individual well's decline
curve wouldn't be the most efficient method. He highlighted
that the North Slope has a decline curve that's aggregated over
all the companies and the fields across the North Slope. If the
state was to set a decline curve, what would be the appropriate
level of aggregation, he asked.
MR. JEPSEN again related the need to give additional thought to
the question.
2:30:23 PM
CO-CHAIR SEATON encouraged Mr. Jepsen and the upcoming industry
representatives to make all the considerations and get the
information back to the committee.
2:31:00 PM
REPRESENTATIVE SADDLER expressed the need to provide
ConocoPhillips the opportunity to dispel any misconceptions or
fallacies about ConocoPhillips and its operations in Alaska that
have been portrayed in the public discussion.
MR. JEPSEN agreed that here has been a lot of rhetoric, but
didn't believe there was any particular point worthy of focus.
He expressed hope that the testimony today illustrates that
ConocoPhillips is a diligent operator that's here to stay,
although it would like a different tax environment so that there
could be more investment in Alaska. With regard to the
discussion surrounding "harvest", Mr. Jepsen opined that harvest
isn't drilling wells, shooting seismic, considering new recovery
techniques, and pursuing technology. He mentioned that he has
worked in places where there has been harvest assets and there
is a large difference between what's done with a field that's on
its last leg and is about to be divested versus what's occurring
in Alaska.
2:32:59 PM
CO-CHAIR SEATON asked if the unanimity aspect of some of the
working interest owner agreements on the North Slope has been a
problem.
MR. JEPSEN, drawing from his experience working in Alaska since
the early 1980s when much of his work was with partners and
peers, said he wasn't aware of a situation when partner
differences delayed or put off production or investment in
locations that were good investments. Although there were times
when companies had different positions from an analysis
perspective, they all had the same goal of reserve additions,
production, and generating net income for the companies.
Generally, those things line up and move ahead.
2:35:03 PM
REPRESENTATIVE FOSTER asked whether outside of Alaska
ConocoPhillips is subject to an incentive program that involves
declining curves.
MR. JEPSEN and MR. CLARK both said they weren't aware of any
other location with such an incentive program.
2:35:43 PM
The committee took an at-ease from 2:35 p.m. to 2:49 p.m.
BP
2:50:06 PM
CO-CHAIR SEATON invited BP to provide its testimony.
2:51:01 PM
DAMIAN BILBAO, Head of Finance, Developments and Resources, BP,
began by relating that BP believes HB 3001 would deliver
meaningful tax change for Alaska and result in a progression as
much as $5 billion in new projects, as a first step. Referring
to slide 3, he highlighted that BP opened its office in
Anchorage in 1959. A year later geologists arrived and began
working on opportunities on the North Slope. In the last 10
years BP has invested over $13.4 billion just with Alaska firms,
which doesn't include BP's total investment over the last 10
years. Along with the investment has been a lot of learning,
including a deep understanding of the opportunity to partner
with the state in the development of local talent and resources.
Over the last 10 years, BP has worked closely with the
University of Alaska system and other institutions to support
the capability in the state. Currently, BP in Alaska has over
2,100 employees, of which over 80 percent are Alaska residents.
He characterized hiring Alaskans as just good business. He then
highlighted the 275 Alaska Process Industry Careers Consortium
(APICC) students that have been hired in the last 10 years, the
54 internships BP has offered over the last five years. Mr.
Bilbao related an example that illustrates why BP believes its
partnership/work with the state's institutions has paid off. In
addition to the 2,100 employees BP has over 6,000 contractors
who work primarily on the North Slope. Of those 6,000
contractors, about 5 of 6 work to renew the infrastructure on
the North Slope in order to ensure that the infrastructure is
fit for the next 30 to 50 years of opportunity that BP foresees
in Alaska. One of the six or about 1,000 contractors is focused
on bringing new barrels into production, which reflects the
investment climate in Alaska. He then highlighted BP's $70
million of direct community investment since 2001.
2:57:18
2:58:01 PM
MR. BILBAO turned the committee's attention to how BP makes
investment decisions. He noted that he listened to the hearing
in which PFC provided a presentation regarding how investment
decisions are made. While BP doesn't agree with PFC on every
point, PFC's analysis was sound and based on deep experience
with the industry. Therefore, he said he is comfortable talking
within the framework PFC presented to the committee. He then
echoed ConocoPhillips' testimony that the investment fund isn't
an unlimited amount of money. In the year prior to a project,
the corporation determines what the appropriate total level of
investment for the next year is based on factors including the
view on oil price, the suite of opportunities, circumstances
around the globe, and the obligation to manage the balance sheet
and meet the commitment to shareholders and other stakeholders.
The year begins in competition for a defined amount of money,
which is particularly impactful on the growth projects given the
fact the underlying activity to support the safe and efficient
management of the fields will occur as needed. The growth
projects, in particular, have to compete globally for the
limited amount of funds. Mr. Bilbao moved on to the graph on
slide 5 entitled "Global investment is limited and goes to the
most attractive regions." The chart shows production curves for
the following four different oil producing regions: Texas,
Alaska, North Dakota, and Alberta as well as the price for each
barrel of oil over that time. The chart spans the timeframe of
1977 to 2010. He mentioned his understanding from the
Department of Revenue's (DOR) testimony that just last week
North Dakota passed Alaska in total production volume. The
graph relates just four examples of regions competing for
investment, and thus growth projects from these regions or other
regions have to compete for the same group of funds on a
consistent set of metrics. The chart illustrates that despite
the increasing price of oil globally over the last few years,
production in Alaska has declined and continues to do so whereas
the other three regions have experienced increased production.
3:01:03 PM
REPRESENTATIVE KAWASAKI recalled from PFC's testimony that of
all three majors on the North Slope, BP's portfolio illustrates
more of a harvest situation for upstream investment. He
inquired as to how to guarantee under HB 3001 that Alaska would
get more money for future development if BP is spending more
money where there is growth.
MR. BILBAO clarified that the growth follows the investment
opportunity, and thus if the investment climate is more
attractive, the funds and investment will follow and result in
growth. The growth won't occur without the appropriate
investment climate. Mr. Bilbao emphasized that Alaska remains
BP's largest resource base globally, with the exception of
Russia. Therefore, it's not a question of opportunity and
resource but rather is a question of investment attractiveness.
If Alaska isn't competing in BP's portfolio as the graph
illustrates, then the investment will not come to Alaska at the
same velocity it does to other regions and as a result there
won't be growth.
3:03:13 PM
CO-CHAIR SEATON recalled that in the 1990s it was said that
[BP's focus was] harvest, and questioned then why one would
anticipate a reversal if the state changes the tax regime.
MR. BILBAO specified that there are periods of time in any field
where funds will flow in to build the infrastructure and the
wells, as was the case in Alaska, and during those times funds
come out of other regions to fund the infrastructure on the
North Slope. After that massive initial investment, there's a
period of production during which funds are used for ongoing
operations and growth in other areas. He said that's how all
companies work as it's managing the portfolio. Therefore, it's
important to consider the longer term investment in that
context. With regard to what will change going forward, Mr.
Bilbao stated that if Alaska is competitive globally, the funds
will flow. However, currently Alaska is not competing for
growth projects. As the graph illustrates, Alaska in comparison
to three other North American oil producing regions, the funds
aren't flowing. Furthermore, Alaska's production decline for
the past five years continues to drop. In fact, from last April
to this April, BP's production has dropped by 8 percent.
Therefore, the [tax regime] has a real impact on how BP competes
for those funds with other locations.
3:05:34 PM
MR. BILBAO, in response to Representative Saddler, stated that
the chart is from a DOR slide that's BP felt was representative
of a broader process. For BP, there would be alternatives such
as Russia and Angola where there have been a production
increase. Although the messages/conclusions would remain the
same, he offered to provide the committee with further
information if it so desired.
3:06:26 PM
REPRESENTATIVE KAWASAKI pointed out that ConocoPhillips' slide 7
entitled "ACES - High Average Government Take" shows that
Azerbaijan's tax rate is well above that of Alaska under ACES
new development. Furthermore, the chart shows that Angola's tax
rate is similarly placed with Alaska under ACES for new
development and Russia's tax rate falls slightly below Alaska
under ACES for existing producers. Representative Kawasaki
opined that although taxes may move companies in a certain
direction somewhat, BP is working in places with higher taxes
than Alaska. Therefore, he invited discussion on that point.
MR. BILBAO informed the committee that over the last three years
he has been working with Indonesia supporting some of BP's
liquefied natural gas (LNG) operations. Indonesia is comparable
to Alaska on the chart presented on slide 7. However, the chart
doesn't relate that the production sharing contract framework
Indonesia employs allows companies to cost recover their
investment earlier on, which is a significant impact on the
economics. Similarly, the fiscal mechanism of other areas on
the chart allows the economics to be competitive. He
acknowledged that the total government take is higher overall,
but pointed out that to be the case because there is an
incentive earlier on to make the investment. The aforementioned
isn't the case in Alaska. Mr. Bilbao emphasized the need to
consider the entirety of the structure, not just individual
pieces, in order to obtain a good sense of the investment
decision.
REPRESENTATIVE KAWASAKI commented that legislators haven't
received much [detailed] information from the administration or
other [stakeholders], and therefore legislators don't have much
detailed information.
3:09:37 PM
REPRESENTATIVE TUCK directed attention to the obligation that BP
may have with Russia and the maintenance of the existing
pipelines BP acquired in Russia. With BP's desire to build
assets elsewhere, he questioned how the state can be assured
that the money Alaska gives BP won't be used elsewhere.
MR. BILBAO said that Russia is a great example of a joint
venture that has had difficulties, but the financial performance
of the unit has been strong. Furthermore, to a large extent the
venture has self-funded much of its own growth. While the
fiscal system in Russia does present certain limits, the unit
has remained effective and the material is a very strategic
material part of BP's portfolio. Mr. Bilbao surmised that
Representative Tuck is inquiring as to how to ensure Alaska will
receive the benefit from a meaningful tax change. He echoed Mr.
Jepsen's comment that good projects move forward.
Unfortunately, projects [in Alaska] aren't in the conversation
because they don't compete globally.
REPRESENTATIVE TUCK pointed out that recently the oil industry
has been making more due to the rising price of oil rather than
production itself. Therefore, he pondered whether producing
more works against the company's best interest because there
would be more available supply and reduced price, which would
decrease the profit per barrel. Besides competitiveness, he
inquired as to what other major factors are reviewed for
strategy planning when considering markets.
MR. BILBAO specified that BP doesn't enter and control markets
as a first leader. Although BP may be the largest
producer/leaseholder when it enters a market and takes a
material position, BP doesn't control the markets. He
reiterated that BP progresses good projects. Furthermore, BP
never looks to consider the impact of its decisions to the price
of oil globally. As a company, BP's total production is a small
portion of the global oil production, and therefore one project
isn't going to impact the global price of oil. Therefore, BP
considers projects and does what it can to ensure the projects
leverage the best technology and are efficient, and the projects
move forward if they are good projects.
3:14:25 PM
REPRESENTATIVE TUCK inquired as to what happened under the
economic limit factor (ELF) when 15 out of 19 wells weren't
paying any production tax. More specifically, he inquired as to
what decisions prevented more investment in the state.
MR. BILBAO responded that he isn't prepared to answer that
question as his experience is primarily under the ACES
environment. Under ACES, BP is running fewer rigs than in the
past and hasn't sanctioned a major resource progression project
since the passage of ACES. However, BP is investing to ensure
that the infrastructure is renewed for 30 years and would like
to invest in projects that use that infrastructure for 30 years,
but ACES doesn't that allow to happen.
3:15:19 PM
CO-CHAIR SEATON highlighted that Alaska has the number one or
two ranked credit system in the world in terms of credit
allowances on capital infusion as well as immediate deduction
and no depreciation. Therefore, Co-Chair Seaton inquired as to
how the return on capital [in Azerbaijan] is quicker than the
100 percent deduction and the credit system that's allowed in
Alaska.
MR. BILBAO said he could discuss the production sharing contract
BP has with Indonesia, with which he is more familiar. Since
it's tremendously complicated, he agreed to do so in writing.
Mr. Bilbao remarked that in BP's view, it isn't able to attract
the investment it would like. In terms of oil and gas rates,
Alaska is last.
3:18:12 PM
MR. BILBAO, returning to his presentation, directed attention to
slide 6. He told the committee that Alaska has really good
rocks and it's BP's largest resource base outside of Russia.
The three things that move the opportunities to production
growth/additional investment include efficiency, technology, and
tax change. Efficiency and technology are within the producer's
control. He noted that efficiency ensures that the appropriate
people are working on the appropriate things in the appropriate
way. Alaska hire is one way to achieve the aforementioned.
With regard to technology, Mr. Bilbao said that Alaska has a
fantastic track record of developing and implementing new
technologies, which he would continue to expect. The third
lever is the fiscal environment, which is the tax change that is
within the legislature's control. Therefore, BP does what it
can with the first two levers, efficiency and technology.
However, the more the lever on tax change is pulled, the lower
the obstacles surrounding efficiency and technology become.
Although it's a combination of the three that result in more
investment, it's ultimately a tax change that will determine how
many projects move out of the funnel. As has been publicly
stated by BP Alaska's president, there is a minimum of $5
billion in first phase development of potential projects that
would move forward with meaningful tax change. However, if
taxes don't change, the hurdles for efficiency and technology
become larger. Frankly, if the taxes don't change, the business
will have to change because the hurdles around efficiency and
technology become much larger. Mr. Bilbao pointed out that the
$5 billion in projects has been consistently mentioned by the
three producers and will be pursued once the efficiency and
technology challenges have been overcome. Still, a reduction in
taxes would make those technology and efficiency challenges less
difficult to overcome.
3:22:01 PM
REPRESENTATIVE PETERSEN inquired as to the timeframe of the
potential $5 billion in new investment.
MR. BILBAO responded that the majority of the new investment
would be over 5-10 years. He noted that most of the activity
listed on slide 6 will be drilling led, and thus it will depend
upon getting the rigs on the North Slope. Mr. Bilbao stated
that BP would start the drilling the day after a tax change
passed.
3:23:19 PM
MR. BILBAO, in response to Representative Gardner, clarified
that the day after a tax change passed BP would move forward
with the projects [listed on slide 6] by getting the equipment
to the North Slope. If BP knew the right fiscal environment was
in place, BP would work on procuring and moving more rigs to the
North Slope.
REPRESENTATIVE GARDNER asked whether BP would have to perform
the calculations to determine whether projects are competitive
or have those calculations already been done.
MR. BILBAO said that although BP would have to go through the
process, there have been internal and external conversations on
many of these. Therefore, BP has a fairly good idea of where it
stands on the projects. Drilling opportunities are among the
least difficult conversations as they tend to be more about
equipment availability and less so about economic hurdles. Once
drilling opportunities become economically viable and
competitive, they tend to progress more quickly.
3:24:51 PM
CO-CHAIR SEATON asked whether the Parker rigs were a problem.
MR. BILBAO said that BP always ensures that all the equipment
that it uses is ready to be used in the manner expected. Once
the Parker rigs are deemed ready to be put into service, BP
would need to decide whether they should be added to the
existing fleet or replace existing less efficient rigs in the
fleet to maintain the overall level of activity. The
aforementioned will revolve around how many of BP's
opportunities are economic, and therefore it's more about
equipment than the economic threshold.
3:26:16 PM
REPRESENTATIVE GARDNER recalled hearing from all the companies
repeatedly that no one can promise that a project can be green
lighted [merely because of a tax change], although it will
improve the possibility/opportunity. She clarified that she's
asking whether this spending commitment has already been made
and it's just a matter of timing or does the project, due to a
change in the economics of the project, have to obtain approval
to move forward.
MR. BILBAO answered that those projects haven't been green
lighted because they aren't economic currently. If economics
change through improved efficiency, technology, or a tax change,
BP would reevaluate the projects. He clarified that his comment
was that those discussions about drilling opportunities tend to
be less difficult because the technology and efficiency
challenges are typically better understood as is the inventory.
The company knows there are great rocks it just needs to ensure
that it's pursuing economic projects.
3:27:24 PM
CO-CHAIR SEATON, referring to the deployment of capital,
inquired as to the availability [of capital] for Prudhoe Bay or
any of the North Slope developments in terms of being able to
sanction those projects.
MR. BILBAO replied no, the only challenge BP faces in Alaska for
attracting more capital is the investment climate.
CO-CHAIR SEATON asked if any projects have been delayed by one
of the three partners not being in alignment with the others.
MR. BILBAO related his experience that good projects move
forward. Although he acknowledged that the partners may not
always agree on the technical details and execution of the
project, he opined that the cumulative debate is best for the
state and the producers.
CO-CHAIR SEATON surmised that Mr. Bilbao agreed with
ConocoPhillips that some projects may have been delayed, but
those delays were due to internal debates. He further surmised
that there weren't projects that were canceled by one party
being in a different strategic point in time as the investments
were going forward.
MR. BILBAO replied that he wasn't aware of such.
3:29:57 PM
REPRESENTATIVE PRUITT inquired as to the meaning of additional
drilling in legacy fields and how BP would differentiate
additional drilling in legacy fields from the drilling BP would
do if there was no change in the tax structure.
MR. BILBAO clarified that additional drilling at the legacy
fields means that there are drilling opportunities at Prudhoe
Bay and Kuparuk River Unit that currently don't meet BP's
thresholds to compete for funds globally, which is why BP has
less rigs running on the North Slope than it has historically.
If costs continue to increase on the North Slope, those
increases would put further pressure on the opportunities, which
would mean BP would continue to monitor those in terms of the
global competitiveness of those opportunities.
REPRESENTATIVE PRUITT asked whether there are certain types of
drilling that's absolutely off the table. For instance, is BP
doing down hole work, but not new wells starting at the surface.
Or, are there opportunities in the legacy fields that are
productive under the current system such that drilling can start
at the surface, he asked.
MR. BILBAO replied yes, adding that the largest opportunities on
the North Slope are within the legacy fields. However, he noted
that BP is on an ongoing basis entering and sidetracking
existing well bores. The biggest addition of new rate is when a
new reservoir or a new pad is constructed. The aforementioned
are the type of growth investments that have the most difficult
time competing under ACES globally. For example, constructing a
new pad on the west side of Prudhoe Bay would be a significant
investment because of the high upfront capital investment
required for such a project. While it would be the most
effective way to manage the decline, it would be among the most
challenged for investment under the current tax regime.
REPRESENTATIVE PRUITT surmised then that there are still
opportunities, "ground down infrastructure", in the legacy
fields that have not been touched.
MR. BILBAO opined that what's lost in the conversation is the
appreciation for how much work goes into reaching that 6-8
percent. Considering the rock itself with no investment and
only ensuring that the operations were safe and efficient, Mr.
Bilbao related that the rocks would produce 16-18 percent less
the next year than the year prior. He then emphasized that BP
invests a significant amount of money with a lot of people just
to reach the 6-8 percent decline. The aforementioned is one of
the reasons not to ignore those operations and only focus above
a certain decline rate. He surmised that Representative Pruitt
is getting to the point that the best place to look for oil is
in the [legacy] fields. There are billions of barrels left in
the legacy fields within Prudhoe Bay and Kuparuk River Unit,
which is why BP focuses on that and doesn't explore outside of
the legacy fields.
3:36:05 PM
REPRESENTATIVE P. WILSON surmised that BP means that it wants to
wait to develop until it's economic as compared to other
projects in the U.S. and the world.
MR. BILBAO clarified that when he says that [Alaska's] projects
aren't competitive globally he's saying that while BP continues
to work on projects [in Alaska] to better understand what can be
done with the efficiency and the technology, the gap between
where the projects stand now competitively and where BP would
like them to be as even an option versus where they would need
to be to materially compete is quite large. Although BP is
reviewing ways to gain efficiency and technology to address the
gap, the gap can be narrowed significantly with the appropriate
tax system in place.
REPRESENTATIVE P. WILSON maintained that because the tax regime
is better elsewhere, it's more economic for BP to do business
there than in Alaska. The economics aren't related merely to
whether a project can be done in Alaska rather it's whether a
project is economic in the broad scheme.
MR. BILBAO agreed with Representative P. Wilson's summation
broadly, but added that Alaska is a high cost operating
environment with one of the most restrictive fiscal environments
on the planet.
3:39:19 PM
REPRESENTATIVE SADDLER asked whether the term "economic" is a
relative or absolute term when BP uses it.
MR. BILBAO answered that it's a combination, but noted that
there are certain minimum expectations. He recalled that PFC
testified that companies will have minimum expectations in
regard to what a project will deliver.
REPRESENTATIVE SADDLER asked whether BP has to reshuffle the
deck every year and compare opportunities globally.
MR. BILBAO explained that typically the company has a fairly
good idea of where [projects/opportunities] are from the
previous year. Typically, the analysis will be in regard to
what has changed whether it is efficiencies, new technology, or
a tax structure change.
3:41:03 PM
CO-CHAIR SEATON recalled being told that companies have
different hurdle rates, although the testimony has been that
projects haven't been canceled [because one partner is at a
different point]. Therefore, he surmised that the goal [for
Alaska] is to make something work for the toughest in the group
[of producers].
MR. BILBAO pointed out that the various producers are discussing
the same projects and magnitude of changes, which is a fairly
strong statement given the legal constraints the producers are
under. He specified that tax change is one aspect of the
challenges that must be overcome [in Alaska].
3:43:28 PM
MR. BILBAO, returning to his presentation, announced that he
would now focus on what growth in investment could mean for
Alaska's future. He then directed attention to slide 8, which
presents a graphical representation of the OMB data that
compares state revenue versus state expenses. In response to
Co-Chair Seaton, Mr. Bilbao explained that the 4 percent growth
line represents a 4 percent growth on expenses. Therefore, the
OMB data assumes that from 2014, expenses grew by 4 percent. He
pointed out that BP added some lines to OMB's graph. BP had
concerns with regard to the forecast in revenue versus the track
record of production decline over the last several years.
[Alaska] has experienced a 6-8 percent decline and the revenue
forecast is largely a flat line. The line for revenue at a 6
percent decline provides an idea of what the difference would be
if production wasn't flat but was declining at 6 percent. The
graph illustrates that if prices were flat and production
declined at 6 percent, one would expect a budget deficit in 2018
of about $1.8 billion. BP also added a line that denotes a 4
percent decline. If there was a way to manage the production
decline at 4 percent through additional investment, the deficit
would be just under $1 billion less than it would be with a 6
percent production decline. Mr. Bilbao then recalled DOR
Commissioner Butcher's testimony estimating that next year the
break-even price for the budget to be $95 per barrel of oil. He
further recalled DOR testimony relating that over the last five
to six years the price of oil has been above $100 per barrel
about 20-30 percent of the time and below $100 per barrel 70-80
percent of the time, which raises concerns with regard to the
reliability of $100-$110 price forecasts. Furthermore, that
challenge can't be managed overnight and one can't wait until
2017 or 2018 to produce more. More production has to begin now
because projects take four to six years before they bring forth
material production. Mr. Bilbao then told the committee that
with a 6 percent decline, the only way the general fund revenue
forecast works is to assume the price of oil is rising by 6
percent per year. "If you assume production continues to
decline at 6 percent, then the only way the revenue stays flat
is if the price of oil goes up 6 percent every year, which
basically would mean that the state is betting its future on a
high oil price." He suggested that there's an opportunity for
the state and the producers to work together to begin to
progress some of the projects that will deliver an impact to the
projected deficit now, not in five or six years.
3:48:50 PM
CO-CHAIR SEATON asked whether a change from a 6 percent decline
to a 4 percent decline would be a realistic change if HB 3001
was enacted.
3:49:24 PM
MR. BILBAO, in response to Co-Chair Seaton, directed attention
to the chart on slide 9. He explained that the bar on the left
represents 2012 production and is broken down between the
natural base decline and the continued well work and drilling.
The drilling and well work that occurs annually generates 40-
50,000 barrels a day. In the context of the North Slope, the
Oooguruk field is currently producing 6,000 barrels a day.
Therefore, annually there would need to be about eight new
fields producing at the level of the Oooguruk field to replace
what BP is bringing in new drilling and well work annually. He
then turned to the bar representing 2020 production, and
highlighted that the natural base decline is 16 percent plus.
Therefore, if BP did nothing production from the North Slope
would be about 150,000 barrels a day. He opined that it's only
because BP is spending billions of dollars with many capable
people that BP manages the decline at closer to 6-8 percent.
Turning to the continued well work and drilling in 2020, Mr.
Bilbao pointed out that continued well work and drilling makes
up two-thirds of the production in 2020, which is generated from
activity between 2012 and 2020. The activity and nature of the
challenge to deliver production from a 16 percent decline to a 6
percent decline is significant. Furthermore, one must keep in
mind that those barrels of oil are slightly more expensive than
the prior year because of the impacts of inflation and the fact
that the best wells are drilled first. He encouraged
consideration of not only the investment and production above
the 6 percent decline but also the ongoing, increasingly more
expensive and more marginal activity that gets to the 6-8
percent. In response to Co-Chair Seaton's question about the 4
percent decline, he pointed out the portion of the 2020
production bar representing the $5 billion in new projects with
meaningful tax change as represented in HB 3001. As has been
mentioned before, the $5 billion is the first opportunity/phase.
He confirmed that it would be possible with legacy and non-
legacy opportunities to manage that decline to closer to 2
percent. Further, it's probable that with meaningful tax change
[the production decline] could get closer to 4 percent with the
$5 billion. Although it will take more than just the legacy
fields, it will have to start with the legacy fields because
that's where most of the oil is located.
3:53:29 PM
MR. BILBAO, returning to slide 6, emphasized that to move from
today to the 2020 profile would mean that BP would have to do a
lot with efficiency and technology, which will only happen with
meaningful tax change.
3:54:17 PM
REPRESENTATIVE PETERSEN, referring to slide 9, inquired as to
what BP considers additional opportunities on the 2020 bar.
MR. BILBAO clarified that the $5 billion of projects is the
first step and represents the projects that BP has worked most
thoroughly and understands more definitively. Beyond those,
more opportunities will be found when the economic environment
is right. The first place one will find opportunities is in the
existing fields. Due to the current economic environment, BP
doesn't have the attention it could to the next phase. With the
right investment climate, more opportunities could be found and
moved forward. However, he noted that BP has a sense of some of
the candidates for the additional opportunities, where they
would fall in BP's natural progression of projects, and what it
would take to move them forward. He opined that it's premature
to specify the opportunities because they could very easily be
passed over.
3:55:53 PM
MR. BILBAO, referring to slide 10 entitled "Key Messages,"
concluded his presentation. He related BP's opinion, which he
said the evidence supports, that ACES is a no growth policy as
growth projects don't compete for investment. Furthermore, ACES
bets Alaska's future on high oil prices. He further related
that any ability to manage the decline has to start with the
legacy fields since that's where most of the oil is located and
the infrastructure already exists. The legacy fields are the
only near-term option for new production. If the taxes don't
change, BP's business will have to change, he opined. Mr.
Bilbao then highlighted that other regions, such as Alberta,
have worked cooperatively between the state and the producers to
reduce taxes and increase investment and production.
3:57:48 PM
REPRESENTATIVE HERRON reminded the committee of PFC's
recommendation for the state to negotiate a decline curve with
the majors and then incentivize production. He asked if 2
percent is legitimate or are [the percentages] presented by BP
more reasonable.
MR. BILBAO returned to slide 9 and the opportunity set with the
$5 billion in investment that could achieve the 4 percent
decline. Although BP also sees opportunities beyond that, to
accomplish that the base business has to be healthy. As
illustrated on slide 9, two-thirds of the production in 2020
will come from activity taking place between 2012 and 2020. To
ignore the aforementioned and try to incentivize activity beyond
that would create a foundation on top of which it would be
difficult to support incremental large spending that projects
require. He then explained that when there is a differentiation
above and below a certain line, the concern is that it creates
certain unintended consequences. If, as was the case with SB
192, there is an attempt to apply a different decline target for
each producer, there is the risk of giving different producers
incentive to move projects from one field versus the other. The
producers, he explained, want to hit their target and [will
move] when they can reach their target more effectively in one
field than another. Similarly, the result of establishing a
certain decline rate in a field or the North Slope is different
for each producer because they decline at different rates due to
the blend of their portfolios. Therefore, establishing specific
decline rates may result in a tax break without additional
effort for one producer while another producer may need a
significant amount of investment to reach that rate. More
fundamental than the aforementioned, when BP runs the economics
for the next project, he questioned how BP will know whether
that's the project that achieves the 6 percent or above the 6
percent. He further questioned what assumptions would be used.
He said BP would have to run the economics on a more
conservative higher tax system. Therefore, Mr. Bilbao
encouraged the committee to develop an alternative that
considers the business as a whole. Again, he told the committee
that if the investment climate is attractive, projects will move
forward.
4:01:18 PM
REPRESENTATIVE HERRON, referring to slide 10, asked whether the
benchmarks presented for Alberta remained the same as introduced
or were they whittled down or up.
MR. BILBAO responded that he didn't know specifically. However,
he offered that the conversations he has had with the industry
and Alberta have related that it was a collaborative effort
between the producers and the state, such that they determined
what would deliver additional investment while still allowing
the state to manage certain fiscal requirements. He said that
it only works when there is a conversation.
4:02:48 PM
CO-CHAIR SEATON directed attention to the provision in HB 3001
that changes the maximum tax rate from 75 percent production tax
to 60 percent. He then asked whether BP considers that a
significant/meaningful piece of the legislation.
MR. BILBAO said that it takes everything in the legislation to
make it work. Therefore, when BP considers its economics, it
considers the entirety of the legislation. The legislation, he
opined, will shift BP's projects into a more competitive
conversation. Picking and choosing will result in legislation
that may incentivize some level of activity, but won't approach
the over $5 million worth of opportunity that's available.
4:03:46 PM
REPRESENTATIVE GARDNER highlighted the option under ACES for
royalty relief when a field is deemed worthy of development
except for the tax rate. She asked if there has been discussion
of asking for royalty relief.
MR. BILBAO related that internal conversations within BP suggest
that typically royalty relief wouldn't be offered to the
projects BP is considering. However, he expressed the need to
review the matter further and provide the committee more
information.
4:05:18 PM
REPRESENTATIVE P. WILSON inquired as to with whom BP would deal
if it takes advantage of the royalty relief option.
CO-CHAIR SEATON explained that the legislature authorized
royalty relief that is administered and granted by the
Department of Natural Resources (DNR). The intention of royalty
relief was to provide an opportunity for projects that aren't
economic under conditions to become economic and move forward.
If royalty relief isn't working, then the legislature may need
to consider policy changes.
4:06:47 PM
REPRESENTATIVE PETERSEN informed the committee that more
smaller/midsized oil companies have come to Alaska to work in
the oil fields. One of the reasons for the aforementioned is
the generous tax credits of ACES. In fact, he related his
understanding that [Alaska] under ACES may be the second best
place for tax credits. If other companies view ACES as working
because of the tax credits, why would BP not view it the same.
MR. BILBAO answered that fundamentally it's distinguishing
between an exploration period and a production period. During
an exploration period, which can take 7-10 years, the activity
tends to be drilling a well, shooting seismic, analyzing the
seismic, and drilling a well all the way to the point of making
a development decision and prior to the construction of a
facility, roads, or pipeline. It's only at the point of the
decision to make a large infrastructure investment when the
company would begin to consider the impact of ACES on the
economics [of the project]. Mr. Bilbao specified that ACES is
very generous for the period of time prior to producing a barrel
of oil, when the company is trying to find oil. Certainly, ACES
has attracted new players. However, ACES isn't very generous
for the period of the life of a field when the company tries to
get the barrel out of the field and into the market. In fact,
during the aforementioned time period, ACES is quite
prohibitive.
4:09:17 PM
REPRESENTATIVE GARDNER inquired as to an estimation of the
investment it would take to reduce the decline from the legacy
fields by 2 percent across the board.
MR. BILBAO explained that to reduce the decline by 2 percent
would mean that it would decline from 6 percent to 4 percent,
which is equivalent to the $5 billion in investment that BP has
already committed to publicly.
4:10:10 PM
REPRESENTATIVE PRUITT, referring to slide 10, inquired as to
what BP will have to do if taxes don't change.
MR. BILBAO opined that the impact of no tax change and no
investment increase in Alaska will be felt far beyond the direct
oil and gas industry. The three producers generate 90 percent
of the revenue for the state, but more importantly they generate
a large part of the jobs, both directly and indirectly. He
reminded the committee that last year's McDowell report said
that for every direct oil industry job nine indirect jobs are
created in the state. With more investment, there would be more
indirect jobs and it would mean that property owners wouldn't
have to be concerned about a reduction in property value nor
would the legislature have to be concerned about finding a new
way to bring in revenue to the state. If the oil industry
experiences a challenge to investing, the average citizen will
experience it day-to-day in many ways.
4:14:06 PM
The committee took an at-ease from 4:14 p.m. to 4:23 p.m.
Pioneer
4:23:14 PM
CO-CHAIR SEATON invited Pioneer Natural Resources, Alaska to
provide its testimony.
4:24:04 PM
TODD ABBOTT, President, Pioneer Natural Resources, Alaska, began
by drawing attention to slide 2 entitled "Forward Looking
Statements." He then informed the committee that Pioneer
Natural Resources, Alaska ("Pioneer Alaska") is a wholly owned
subsidiary of Pioneer Natural Resources ("Pioneer"). Pioneer
Alaska is headquartered in Anchorage with about 70 full-time
Alaska employees and 120 Alaska contract workers in Anchorage
and the North Slope. Mr. Abbott highlighted that Pioneer Alaska
is the first independent operator on the North Slope, which was
achieved with the Oooguruk project that commenced production in
the fall of 2008. Currently, Oooguruk produces about 6,900
barrels a day and over the life of the project Pioneer Alaska
will invest about $1 billion. Referring to slide 4, he
explained that the slide illustrates what Pioneer looked like
from 1997-2005, which was a time with the Lower 48 fields were
considered mature and oil prices were much lower than they are
today. Therefore, companies were going abroad seeking growth
projects as the projects in the Lower 48 weren't economic.
Pioneer was no different as it explored abroad in West Africa,
drilled in Tunisia and South Africa, it had operations in
Argentina, and worked in Canada. Pioneer also did a lot of work
in the deepwater of the Gulf of Mexico, which was quite
successful, and of course, Alaska as well. He then related that
Pioneer entered Alaska to grow its business because its Lower 48
holdings were mature and Pioneer felt its fields were in
decline. Alaska, with its very large oil resources and prolific
oil and gas basin, fit the bill. Furthermore, the state was
actively courting independents to join the majors in Alaska.
The aforementioned left Pioneer feeling as if it could enter
Alaska with a more independent mindset. Pioneer entered Alaska
with a lower cost structure and more agility in terms of quick
decision making. Moreover, things that are less material to the
major producers are very material to Pioneer Alaska, which leads
Pioneer Alaska to aggressively pursue options that may not be
[economic] for the majors. In fact, Pioneer Alaska does well
when it can come in after the majors and pickup things that
weren't material to the majors. Referring to slide 6 entitled
"North Slope Exploration History", Mr. Abbott told the committee
that from 2003-2007 Pioneer Alaska drilled 11 exploration wells
that resulted in one project, Oooguruk. Exploration is
difficult, even in a basin as prolific as the North Slope.
Although Pioneer Alaska found hydrocarbons in almost all of the
11 exploration wells, to have a commercial project one must find
the right kind of hydrocarbons in the right types of reservoirs
and in large enough accumulations by the right infrastructure.
MR. ABBOTT, moving on to slide 7 entitled "Alaska's Severance
Tax" explained that Pioneer decided to enter Alaska under the
ELF. The Oooguruk project was sanctioned under ELF and
construction began under the petroleum production profits tax
(PPT). Drilling began and the first oil was revealed under
ACES. Therefore, slide 7 illustrates that it's a long lead time
from exploration to first production and that Pioneer Alaska was
always chasing a moving target on the tax structure. He
emphasized that certainty [with regard to the tax structure] is
critical when a company is making decisions to sanction a
project, especially when there is such a long lead time prior to
production. Referring to slide 8, Mr. Abbott addressed what has
changed in the ensuing eight years after [the first oil at
Oooguruk]. The first change is that oil prices have increased
dramatically and gas prices have decreased dramatically. The
higher oil price allows Pioneer Alaska to use the horizontal
drilling and facturing technology that has been available for
some time, although it has been extremely expensive to use until
now. The aforementioned has created the shale boom in the Lower
48 and now the landscape has changed such that the Lower 48 is
no longer considered mature. Companies are no longer going
[abroad] to find an economic project because now it can be done
in the U.S. where there is a stable tax structure. He then
directed attention to slide 9 entitled "Fixed-Royalty
Jurisdictions in US Lower 48 Are A Key Competitor to Alaska for
Investment Dollars", which he borrowed from PFC Energy. The
slide illustrates that from 2003-2005 North America was
exporting cash while from 2008-2010 capital is returning to the
U.S. and being invested in the U.S. because of the higher [oil]
prices, technology, and the tax structures available in the
Lower 48.
4:31:45 PM
MR. ABBOTT, continuing with slide 10 entitled "Current Pioneer
Operations Footprint", informed the committee that Pioneer's
current operations are only in the U.S., which is a much simpler
operation with fewer contractual issues. Pioneer has sold off
its holdings abroad and has, to a large extent, left the high
risk exploration gain [operations] and is focused on resource
potential, shale plays, and even conventional resources. He
then told the committee that his job as president for Pioneer
Alaska is to bring capital and investment to Alaska. Slide 11
highlights Pioneer's plays in Texas and provides some
perspective of what Pioneer Alaska is up against. He informed
the committee that the following three plays in Texas are shale
plays: the Barnett Shale, Eagle Ford Shale, and Horizontal
Wolfcamp Shale. The Spraberry Vertical in Texas can be
considered more of a conventional play as there are vertical
wells that are fractured. Pioneer is probably the largest
acreage holder, by far, in the Spraberry Vertical. Furthermore,
Pioneer has 20,000-plus drilling locations yet to drill. He
related that the Horizontal Wolfcamp Shale is the most similar
well to that of a well Pioneer Alaska would drill in Alaska.
Mr. Abbott highlighted the scale of activity in the Lower 48 and
the economic impact apart from the state revenue. The
aforementioned operations in Texas have a very low geologic risk
similar to what exists in Alaska and have very short project
cycle times as compared to Alaska. He explained that in the
Lower 48 when a company makes an investment, the company can
drill five wells and decide to stop drilling after those five
wells. However, in Alaska the operations are more like
deepwater operations in that the company has to invest hundreds
of millions of dollars before the first few wells are drilled.
Therefore, in Alaska a company will have a lot of money on the
table before getting significant results from development
projects in Alaska. Therefore, the executive committee of
Pioneer has to have tremendous confidence in the economics of
projects in Alaska because they won't take a lot of risk with
such a large stake on the table before getting results. Moving
on to slide 12, he reviewed a graph that illustrates the
competition for capital with the wells in Texas versus all the
North Slope wells and reviewed the economic impact felt in
Texas. Mr. Abbott moved on to slide 13 entitled "2012E Capital
Spending and Cash Flow", and explained that the chart on slide
13 allows Pioneer to predict its cash flow for any given year.
One can select the oil and gas price for next year, which will
be Pioneer's corporate cash flow, including hedging and costs.
For example, at current market prices [Pioneer will have] about
$2.2 billion of cash flow and will spend about $2.4 billion in
capital. Pioneer will spend about $1.8 billion in the Permian
Basin, most of which will be spent in the vertical play of the
Spraberry Basin and a significant portion in the horizontal
wells. He then highlighted that Pioneer is spending about $135
million, which is roughly 6 percent of Pioneer's capital budget,
in Alaska versus $1.8 billion and an additional investment in
the Eagle Ford and Barnett Shale plays. He opined that the
company's decision to make the best return for their
shareholders speaks volumes.
4:38:56 PM
MR. ABBOTT, referring to the map on slide 14, reviewed the
Oooguruk site. Pioneer Alaska continues to drill at Oooguruk as
there is one rig on site. The next step with Oooguruk is the
Torok area. Pioneer Alaska drilled two wells this year, one of
which was an unrelated exploration well and the other was an
appraisal well from the Nuna-1 drill site. With regard to
what's next for Pioneer or the incremental investment for
Pioneer that could be impacted by tax policy, Nuna-1 is the
answer. Nuna-1 has been drilled, test production has been run,
the results are being evaluated now, and the recommendations are
being prepared. He acknowledged that there are a wide range of
outcomes that could result from Nuna-1 with the most likely
outcomes being that tax policy has a tremendous impact. As
noted on slide 15, Nuna-1 is one or two onshore drill sites
depending upon the extent of the development. Nuna-1 is large
and is more like an oil shale project that would be in the Lower
48 as it's highly laminated shale. For Nuna-1 Pioneer Alaska is
drilling long horizontal wells and the largest frack job on the
North Slope is in one of these wells. The [Nuna-1] project
could result in a significant amount of jobs for Pioneer as well
as for the service and construction companies that work in the
area. Still, this project is up against projects in the Lower
48 that have lower operating costs, a better tax structure, and
vast resources of which Alaska once had the monopoly. As
related by slide 16, both Alaska and the Lower 48 have resource
potential while Alaska would be more favorable in terms of
resource competition because it doesn't have the number of
independents as there are in the Lower 48. With regard to oil
bias, he opined that Alaska has a tremendous amount of oil ready
to be produced. However, the ease of the regulatory process is
better in the Lower 48 while in terms of land acquisition Alaska
is in a better position than the Lower 48. Although Alaska
looks fairly good from a resource perspective, Alaska is lacking
from the profitability side, which includes cycle times,
execution risk, operational flexibility, and low operating cost.
Therefore, Alaska needs a better tax structure than what's in
the Lower 48, he opined. The aforementioned, he said, is
illustrated on slide 17 entitled "Average Government Take",
which the committee has already seen in previous presentations.
4:43:50 PM
MR. ABBOTT, referring to slide 18, stated that there are some
aspects to HB 3001 that are a good start, such as that it
incents a wide array of projects, reduces the negative impact of
progressivity, and makes Alaska projects significantly more
competitive. However, an improvement to HB 3001 would be to
include the small producer tax credit extension because it makes
a real difference for small producers such as Pioneer. He noted
that the small producer tax credit is really a reduction of the
small producer's tax liability. Mr. Abbott opined that Pioneer
has some good projects in Alaska that it would like to forward.
He said he wants to bring additional capital to Alaska, and
therefore he will do his absolute best to do so. Tax policy, he
emphasized, would go a long way in terms of supporting the
capital coming to Alaska otherwise it's an uphill battle. With
regard to the Oooguruk expansion, Mr. Abbott clarified that the
Torok expansion is not a done deal and Pioneer Alaska is not
anywhere near sanctioning the development. The hope is that the
expansion is so good that tax policy doesn't matter, although
it's more likely that tax policy will matter. There are a lot
of other projects on the North Slope like the Torok expansion
and for them tax policy matters. He noted that Torok would
bring new barrels into TAPS and create construction and
development jobs. In closing, Mr. Abbott reiterated that
HB 3001 will have a positive and a material impact.
4:46:24 PM
REPRESENTATIVE GARDNER asked if when ACES went into effect
Pioneer was one of the companies eligible for the claw back
provisions. If so, what was that worth, she asked. She further
asked whether Pioneer was one of the companies that received
royalty relief, and if so, she inquired as to the experience of
it.
MR. ABBOTT said that he didn't know the answer to the question
regarding the claw back, but offered to obtain it and provide it
to the committee. He confirmed that Pioneer did apply and
receive royalty relief for the Oooguruk project. The receipt of
the royalty relief was primarily driven by Pioneer's 30 percent
net profits lease in addition to ACES. As far as quantifying
the value of the royalty relief, he offered to research that and
provide the information to the committee. In further response
to Representative Gardner, Mr. Abbott explained that the 30
percent net profits lease is an additional burden placed on the
Oooguruk lease, basically it's an income tax on Oooguruk.
CO-CHAIR SEATON interjected that the 30 percent net profits
lease was a bid term on the lease at the time, prior to Pioneer
picking up that lease. He explained that there are competitive
lease sales and bonus bids. At the time, the bidder bid the 30
percent net profits as part of the bonus bid to obtain the
lease. He asked if that bid term also applies to the expansion
project.
MR. ABBOTT related his understanding that it would apply to
anything within that lease, which includes Torok. In further
response to Co-Chair Seaton, Mr. Abbott clarified that it was a
royalty reduction not royalty elimination. Therefore, Pioneer
pays royalty and once it pays out it will pay a [30 percent] net
profits lease. He further clarified that the 30 percent net
profits is in addition to the reduced royalty.
CO-CHAIR SEATON asked whether the royalty was reduced through
royalty relief for a period of time until a certain point, such
as when profitability is reached.
MR. ABBOTT said he would have to review the specifics of the
terms.
CO-CHAIR SEATON remarked that he would appreciate the
information because it would help the committee determine
whether the existing royalty relief provisions function well or
not.
MR. ABBOTT, returning to Representative Gardner's earlier
question regarding the difficulty of the process, related his
understanding that the process was extraordinarily difficult and
there was quite a bit of documentation work. Royalty relief
isn't an easy administrative process as it's something that
takes a lot of data, time, and analysis.
4:51:13 PM
CO-CHAIR SEATON asked if the 30 percent net profits portion of
the lease is after the production tax and all other property
taxes. He further asked if the profit is before or after
corporate income tax.
MR. ABBOTT clarified that [the 30 percent net profits lease] is
after and in addition. He offered to prepare information to
provide to the committee.
4:52:04 PM
CO-CHAIR SEATON inquired as to whether the change from the 75
percent maximum tax to the 60 percent maximum tax is a
significant piece in the calculation for being able to draw
capital to a project in Alaska.
MR. ABBOTT responded that it's hard to say without the specifics
for Torok. However, more broadly, the change is a good
provision, but he said he didn't know if it's material enough to
achieve the type of investment being sought.
4:53:07 PM
CO-CHAIR SEATON asked if Pioneer has a process facility sharing
agreement with existing producers or does Pioneer have its own
processing facility.
MR. ABBOTT confirmed that Pioneer has an agreement such that all
of Pioneer Alaska's crude production oil, water, and gas is
processed through ConocoPhillips' production facilities.
Pioneer has a facilities sharing agreement to do so. In further
response to Co-Chair Seaton, he confirmed the facilities sharing
agreement would likely remain for any expansions, although it
depends upon the size. He explained that it would have to be an
extraordinarily large find for Pioneer to justify building its
own processing facilities rather than availing themselves of
those of ConocoPhillips.
CO-CHAIR SEATON surmised that when incentivizing multiple
things, including legacy fields that are water or gas
constrained, there could be issues. He then mentioned that
Brooks Range approached the state about a state loan for funds
to construct mobile processing facilities that could process
about 15,000 barrels per day. If that was available for an
Alaska project, he asked whether that would materially impact
the sanctioning of a project.
MR. ABBOTT mentioned that in his last position with Pioneer he
was vice president of corporate finance. He then informed the
committee that Pioneer measures the profitability of its
projects as a discount return on investment (DRI), which is the
value divided by the discounted capital. For every dollar
invested, one wants to obtain the highest value for that dollar.
Therefore, having something that's a lower cost of debt through
the state would decrease the amount of capital the company would
have to deploy and decrease the discount rate against which the
project is measured. The aforementioned is positive, but the
question is regarding the ratio of that piece of capital versus
the overall project size. In further response to Co-Chair
Seaton, Mr. Abbott opined that the way it's being described
really isn't a relief of capital but rather it's a financing
mechanism. In that case, the company would still pay the
dollars and the interest rate would make the difference. A
change in the interest rate on a $200 million investment could
help over the life of a project, but it would need to be a
project that's [already] very close to being economic.
4:58:15 PM
REPRESENTATIVE HERRON posed a scenario in which the 40 percent
gross reduction is reduced, and asked when it wouldn't be
meaningful when only changing that.
MR. ABBOTT responded that is very difficult to answer. The
corporation reviews [HB 3001] in terms of its overall value, and
thus [to only consider the percent gross reduction] would be
project dependent.
REPRESENTATIVE HERRON appreciated Pioneer, which is a nimble and
successful company, providing comments today.
5:00:37 PM
CO-CHAIR SEATON recalled that there had been questions regarding
decline curves, and asked whether that would apply to Pioneer's
projects.
MR. ABBOTT said that reviewing a decline curve segregation in
terms of new oil versus old oil is an interesting way to look at
it. Although he said he likes the idea, he said it's difficult
to comment until he has the details. For something like
Oooguruk, Pioneer produces out of several different horizons
each of which has its own decline. Pioneer's production
profile, he related, would historically increase, decrease
slightly, and then start increasing again. As the various
reservoirs deplete at different rates and the water flood
impacts at different times, there will be varying rates.
Therefore, the challenge is how to determine the schedule of
future volumes based on existing production. He opined that
it's a difficult number to ascertain and negotiation of it would
be quite an exercise between the state and the companies.
Again, if implemented correctly, it could work.
5:03:22 PM
REPRESENTATIVE PETERSEN recalled hearing that some of the new
players on the North Slope had found impediments to growth and
potential due to difficulties accessing facilities and excessive
costs for shipping oil down the pipeline. He asked if Pioneer
has experienced such.
MR. ABBOTT acknowledged negotiations to use ConocoPhillips'
facilities were difficult and took a long time. He further
acknowledged that from time-to-time there are disagreements, but
it's a business transaction and is worked out. ConocoPhillips
has worked with Pioneer on its facilities. For example,
ConocoPhillips is doing capital planning for a couple of years
out and has inquired as to Pioneer's needs. Although the
relationship between Pioneer and ConocoPhillips is a business
relationship, it works.
5:05:27 PM
REPRESENTATIVE GARDNER commented that it's interesting that Mr.
Abbott could conceive of a play that would be so wonderful and
economic that tax policy wouldn't matter.
MR. ABBOTT indicated that he's an optimist.
5:05:54 PM
CO-CHAIR SEATON related his understanding that Pioneer would
like the small producer tax credit included in HB 3001. He
asked if an expiration of 2022, a 10-year extension, would
provide enough time to recruit the capital.
MR. ABBOTT replied yes, adding that 2022 would be a reasonable
timeframe for the extension. Having more certainty would help.
CO-CHAIR SEATON recalled comments that the small producer tax
credit wasn't inflation proofed. He asked if Mr. Abbott saw any
need to change that from the $12 million to $15 million or is it
immaterial for most small producers.
MR. ABBOTT opined that $3 million a year of an $800 million
project is unlikely to change Pioneer's decision on a project.
Although [the small producer tax credit] helps with Oooguruk,
tweaking it reaches a point of diminishing returns, he remarked.
AOGA
5:08:25 PM
CO-CHAIR SEATON invited testimony from the Alaska Oil and Gas
Association (AOGA).
5:08:47 PM
KARA MORIARTY, Executive Director, Alaska Oil and Gas
Association (AOGA), began by informing the committee that AOGA
is a business trade association with the mission to foster the
long-term viability of the oil and gas industry for the benefit
of all Alaskans. The association's 16-member companies are a
diverse group and the committee has heard from two of the member
companies today. She informed the committee that AOGA's member
companies have both an onshore and offshore presence and are
located in the Cook Inlet and the North Slope. Furthermore,
AOGA member companies are on federal and state lands. The
member companies include legacy companies, new entrants, three
in-state refineries, and the Alyeska Pipeline Service Company.
In total AOGA's members hold more than 1.2 million acres of
land. Therefore, there's little doubt AOGA represents the
majority of oil and gas exploration, development,
transportation, refining, and marketing activities in the state.
She pointed out that one of the key purposes of any trade
organization, especially AOGA, is to provide a forum for the
discussion of matters of general interest for its members. She
highlighted the policy of AOGA to have 100 percent consensus on
tax policy matters, and emphasized that all 16-member companies
concur with the statements she's going to make today.
MS. MORIARTY reminded the committee that AOGA didn't support the
tax changes that were made in 2006 and 2007 because AOGA
believed then and now that the current tax system is
uncompetitive for investment dollars, long-term development, and
production. Furthermore, all of AOGA's member companies believe
that meaningful changes to the tax system are necessary to stem
the decline in production. In fact, today's testimony marks the
sixth time that AOGA has testified before the Twenty-Seventh
Alaska State Legislature regarding the need for oil tax reform.
Throughout AOGA's testimony to the legislature and the public it
has stressed the graph entitled "Production Decline is Real",
which illustrates that declining production is a problem that
cannot be ignored. She acknowledged that [the legislature]
isn't ignoring it. The graph shows the historical production in
the past decade with DOR's forecast for the next decade. Upon
examining the past three years a bit closer, one will find that
production is declining by just under 40,000 barrels per day.
Furthermore, the DOR forecast moving forward is that almost half
of the new production will be from new oil that is oil yet to be
developed. In fact, the recently released DOR spring 2012
forecast forecasts that in 2013 71,000 new barrels per day will
need to be in production.
5:12:22 PM
MS. MORIARTY stated that as a trade association, AOGA's main
question is from where this new oil is going to come, especially
in the short term. She informed the committee that Oooguruk and
Nikaitchuq, new fields, are each expected to peak at around
20,000-28,000 barrels per day. She then reiterated that the
current production decline is about the same as these two new
fields combined each year. In other words, to simply offset the
current decline two new fields like Oooguruk and Nikaitchuq need
to come on each year. Moreover, to reach DOR's forecast for
2013 three fields of this size need to come on line in the next
year. Unfortunately, she knew of no new fields expected to
produce oil in the next three to five years. She recalled that
in 2006 and 2007 many companies testified that ACES wouldn't
attract the investment Alaska needed to stem the production
curve. Not only did that prediction came true, production is
significantly lower today than what was forecast when ACES was
passed in 2007. As the chart entitled "Forecast in 2007 vs.
2011 Actual Production" shows the Department of Revenue
predicted that in 2011 Alaska would produce 754,000 barrels per
day, but production was only at 603,000 barrels per day. Moving
on to the chart entitled "Current Industry Investment", Ms.
Moriarty pointed out that the chart relates the total operating
expenses in Alaska industry wide and the capital investment.
The chart relates that the industry investment totals has
remained stagnate over the last three years. Capital investment
has averaged $1.7 billion, which resulted in a loss of about
40,000 barrels per day over the same three years. Therefore,
current investment levels aren't even stemming the production
decline, never mind increasing production. Without bold and
meaningful reforms Alaska's production will continue to decline
at a rate, according to the Office of Management & Budget, that
would create potential deficits as early as 2015 that would
increase in each succeeding year. From AOGA's perspective,
there's a production problem that's going to soon result in a
serious revenue problem for the state.
MS. MORIARTY pointed out that AOGA's member companies and others
have testified about what's happening with businesses on the
North Slope, the interrelationship between new levels of new
investment each year and the rate of decline in Alaska North
Slope production as well as the impact of taxes on investment
decisions. "These explanations are not threats, but they're not
bluffs either," she stressed. Rather, the testimony has been
candid attempts to describe how those companies evaluate
investment opportunities in Alaska versus elsewhere and how
Alaska's tax regime can influence decisions regarding which
opportunities to take. She further recalled that recently the
legislature's own consultants explained to this committee how
investment decisions are made and provided a similar conclusion
that investment decisions reflect the expectations of the
company's respective shareholders and that companies will choose
the opportunities they perceive to be best, all things
considered, including taxes. Ms. Moriarty stated that the level
of investment in Alaska since enactment of ACES isn't
retaliation rather the investments are nothing more than the
results of the competition of opportunities in Alaska versus
those elsewhere. Therefore, AOGA believes that declining
production is a slope-wide problem that needs a slope-wide
solution. John Norman, the commissioner of the Alaska Oil and
Gas Conservation Commission, recently described Alaska's legacy
fields as an "anchor tenant." Ms. Moriarty said that AOGA
continues to use the analogy that the North Slope is like a tree
with the two great legacy fields being its trunk and the other
fields branching out and rising out of that trunk. Therefore,
if one peels the bark off all the way around the trunk and makes
the tree unhealthy, all the other branches will become unhealthy
as well, no matter how robust they might have been if the trunk
had stayed strong.
5:18:07 PM
MS. MORIARTY, referring to the slide entitled "Rich In
Resources", said that if one considers the resources remaining
on the North Slope, one should be encouraged. In fact, the
legacy fields, the conventional line of 5 billion barrels of oil
remaining, hold the most promise in the short term.
Additionally, during this time of record high oil prices Alaska
should see a flurry of activity and increased investment levels
to get these resources to market. The producers of the existing
non-legacy fields on the North Slope and the developers of any
new fields that may be discovered need as much production as
possible flowing from the legacy fields through TAPS in order to
maintain affordable costs to ship oil from the North Slope to
refinery destinations. She confirmed Representative Petersen's
concern for high transportation costs and characterized it as a
real concern that could cripple the economics of any new fields
as well as the economics of any non-legacy fields currently in
production. Ms. Moriarty emphasized, "So, we believe that
Alaska and Alaskans need to appreciate the North Slope
production with a great level of concern and react with bold and
meaningful reforms." Without comprehensive reform for the
legacy fields as well as other production and future production,
the entire North Slope will be harmed. As Mr. Abbott told the
committee, tax policy does impact business decisions and the
competition for investment dollars is real. Therefore, AOGA
encourages the committee to put Alaska in a better and more
competitive position for near-term and long-term development.
The legislation, HB 3001, before the committee does recognize
the overall government take in Alaska is too high and does
provide meaningful reform. Ms. Moriarty acknowledged that a
solution that benefits all fields may not be achieved this
special session because it appears the legislature is fragmented
on this issue. However, AOGA will continue to work with the
legislature until meaningful tax reform is reached for all
fields on the North Slope.
5:20:37 PM
REPRESENTATIVE FOSTER inquired as to how many barrels have gone
through TAPS.
MS. MORIARTY answered that over 16 billion barrels of oil has
gone through TAPS. If one were to include production for Cook
Inlet, just over 17 billion barrels of oil has been produced
since statehood.
5:21:13 PM
REPRESENTATIVE HERRON inquired as to when a decrease in the
percentage alone is not meaningful to AOGA.
MS. MORIARTY said that's difficult for her to answer because she
has to have 100 percent consensus. In all of the discussions,
reducing the base rate and changing progressivity would provide
the most meaningful reform.
5:23:03 PM
CO-CHAIR SEATON directed attention to the committee packet that
includes testimony from the ExxonMobil Corporation whose
representative couldn't be present today. He told the committee
members could submit questions for ExxonMobil Corporation. He
reviewed the committee's upcoming schedule.
5:25:18 PM
MR. BILBAO, in response to Representative Gardner's question
regarding a discrepancy in the decline curve BP presented versus
that of DOR, noted that he has sent a text to his office to
confirm whether the data submitted by all the producers included
the projects associated with the incremental $5 billion and
whether that accounts for the difference in production.
Therefore, Mr. Bilbao said he would like to double check that.
[HB 3001 was held over.]
5:27:00 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 5:27 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| House Resources HB3001 2012-04-25 ConocoPhillips.pdf |
HRES 4/25/2012 1:00:00 PM |
HB3001 |
| BP Presentation April 25th, 2012 to House Resources and House Energy Committees.pdf |
HRES 4/25/2012 1:00:00 PM |
HB3001 |
| Pioneer Testimony to Joint House Resource _ Energy Committee 042512.pdf |
HRES 4/25/2012 1:00:00 PM |
HB3001 |
| EM - Letter to House Resources re HB 3001 - 4-25-12.pdf |
HRES 4/25/2012 1:00:00 PM |
HB3001 |
| 04 25 12 HRES Slides.pdf |
HRES 4/25/2012 1:00:00 PM |
HB3001 |