Legislature(2007 - 2008)HOUSE FINANCE 519
10/23/2007 09:00 AM House OIL & GAS
| Audio | Topic |
|---|---|
| Start | |
| HB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB2001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
October 23, 2007
9:02 a.m.
MEMBERS PRESENT
Representative Kurt Olson, Chair
Representative Nancy Dahlstrom
Representative Mark Neuman
Representative Jay Ramras
Representative Ralph Samuels
Representative Mike Doogan
Representative Scott Kawasaki
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Bob Buch
Representative John Coghill
Representative Bryce Edgmon
Representative Anna Fairclough
Representative John Harris
Representative Lindsey Holmes
Representative Craig Johnson
Representative Mike Kelly
Representative Beth Kerttula
Representative Bob Roses
Representative Paul Seaton
Representative Peggy Wilson
COMMITTEE CALENDAR
HOUSE BILL NO. 2001
"An Act relating to the production tax on oil and gas and to
conservation surcharges on oil; relating to the issuance of
advisory bulletins and the disclosure of certain information
relating to the production tax and the sharing between agencies
of certain information relating to the production tax and to oil
and gas or gas only leases; amending the State Personnel Act to
place in the exempt service certain state oil and gas auditors
and their immediate supervisors; establishing an oil and gas tax
credit fund and authorizing payment from that fund; providing
for retroactive application of certain statutory and regulatory
provisions relating to the production tax on oil and gas and
conservation surcharges on oil; making conforming amendments;
and providing for an effective date."
- HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: HB2001
SHORT TITLE: OIL & GAS TAX AMENDMENTS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
10/18/07 (H) READ THE FIRST TIME - REFERRALS
10/18/07 (H) O&G, RES, FIN
10/19/07 (H) O&G AT 1:30 PM HOUSE FINANCE 519
10/19/07 (H) Heard & Held
10/19/07 (H) MINUTE(O&G)
10/20/07 (H) O&G AT 12:00 AM HOUSE FINANCE 519
10/20/07 (H) Heard & Held
10/20/07 (H) MINUTE(O&G)
10/21/07 (H) O&G AT 1:00 PM HOUSE FINANCE 519
10/21/07 (H) Heard & Held
10/21/07 (H) MINUTE(O&G)
10/22/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519
10/22/07 (H) Heard & Held
10/22/07 (H) MINUTE(O&G)
10/23/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519
WITNESS REGISTER
MARILYN CROCKETT, Executive Director
Alaska Oil and Gas Association (AOGA)
Anchorage, Alaska
POSITION STATEMENT: Presented information from AOGA during the
hearing on HB 2001.
CRAIG HAYMES, Production Manager - Alaska
ExxonMobil Corporation
Anchorage, Alaska
POSITION STATEMENT: Presented information from ExxonMobil
Corporation during the hearing on HB 2001.
JOHN P. ZAGER, General Manager, Alaska
Chevron
(No address provided)
POSITION STATEMENT: Presented information from Chevron during
the hearing on HB 2001.
PAT FOLEY, Manager
Lands and External Affairs
Pioneer Natural Resources Alaska, Inc. ("Pioneer")
(No address provided)
POSITION STATEMENT: Offered an outline of the presentation from
Pioneer during the hearing on HB 2001.
KEN SHEFFIELD, President
Pioneer Natural Resources Alaska, Inc. ("Pioneer")
(No address provided)
POSITION STATEMENT: Presented information from Pioneer during
the hearing on HB 2001.
MARK HANLEY, Public Affairs Manager
Anadarko Petroleum Corporation in Alaska (APC)
(No address provided)
POSITION STATEMENT: Presented information from APC during the
hearing on HB 2001.
DAN E. DICKINSON, Certified Public Accountant (CPA)
Anchorage, Alaska
POSITION STATEMENT: Presented information on behalf of the
Legislative Budget and Audit Committee during the hearing on HB
2001.
ACTION NARRATIVE
CHAIR KURT OLSON called the House Special Committee on Oil and
Gas meeting to order at 9:02:48 AM. Representatives Olson,
Neuman, Kawasaki, Samuels, Ramras, and Doogan were present at
the call to order. Representative Dahlstrom arrived as the
meeting was in progress. Also in attendance were
Representatives Buch, Coghill, Edgmon, Fairclough, Harris,
Holmes, Johnson, Kelly, Kerttula, Roses, Seaton, and Wilson.
HB2001-OIL & GAS TAX AMENDMENTS
9:02:58 AM
CHAIR OLSON announced that the first order of business would be
HOUSE BILL NO. 2001, "An Act relating to the production tax on
oil and gas and to conservation surcharges on oil; relating to
the issuance of advisory bulletins and the disclosure of certain
information relating to the production tax and the sharing
between agencies of certain information relating to the
production tax and to oil and gas or gas only leases; amending
the State Personnel Act to place in the exempt service certain
state oil and gas auditors and their immediate supervisors;
establishing an oil and gas tax credit fund and authorizing
payment from that fund; providing for retroactive application of
certain statutory and regulatory provisions relating to the
production tax on oil and gas and conservation surcharges on
oil; making conforming amendments; and providing for an
effective date."
MARILYN CROCKETT, Executive Director, Alaska Oil and Gas
Association (AOGA), paraphrased from the beginning of a 19-page
prepared statement [the corresponding charts and graphs for
which are available in the committee packet], which read as
follows [original punctuation provided, with some formatting
changed:
Mr. Chairman and Members of the Committee. Thank
you for the opportunity to testify before you today on
Senate Bill 2001.
My name is Marilyn Crockett and I am the
Executive Director of the Alaska Oil and Gas
Association ("AOGA"). AOGA is the trade association
for the oil and gas industry in Alaska. Our 17
members account for the majority of oil and gas
exploration, development, production, transportation,
refining and marketing activities in the state. In
addition to Alaska's instate refiners, Agrium and
Alyeska, our membership includes companies new to
Alaska hoping for the opportunity to explore,
companies which are exploring today but do not yet
have production (but hope to in the future) and those
companies which are producing today.
One of the important functions the Association
performs is to provide a forum for member companies to
consider regulatory and legislative proposals, and to
reach agreement on an industry position on those
proposals. To establish an AOGA position, a 5/6 vote
of the members is required. What this means, of
course, is that when AOGA voices that position,
regulators and legislators can be assured that that
position is the position of the overwhelming majority
of Alaska's oil and gas industry.
But on tax issues, AOGA members have taken this
approval process to the highest level. AOGA positions
on tax-related issues require 100% consensus of the
AOGA Members. Let me be clear: my testimony today
reflects the full consensus of the members of the AOGA
Tax Committee, with no dissent.
The focus of our testimony today will be on the
practical impact of declining production levels on
industry operations and the State of Alaska. And
while we are not in a position at this early date in
this Special Session to provide you with a complete
analysis of the many components of SB 2001, we will
describe for you but a few of the troubling aspects of
this legislation. The AOGA Tax Committee is in the
midst of a comprehensive review of the legislation and
will be in a position at a future date to characterize
those concerns.
Here we are in Juneau for the fourth time in the
past two years to deliberate whether one of the
State's taxes on oil and gas should be changed, and if
so, what it should be changed to. Last year the
Legislature passed the Petroleum Production Tax, or
PPT. Now, less than a year later, the Administration
is telling you that the PPT is broken. They say it's
too complicated to forecast, it isn't bringing in the
revenue that was forecast last year, and they don't
have enough capable auditors to enforce it.
In discussing the merits of SB 2001 versus PPT
and the Administration's concerns, we must always keep
in mind the real-world situation that Alaska faces.
The greatest challenge that confronts this generation
of Alaskans and the next is the ongoing decline of oil
production, which has been, is today, and promises to
remain the cornerstone of the finances of state
government.
Production decline is eroding this cornerstone.
It is a historical fact that even with the massive
investments being made, North Slope production
declined an average of 6.2% a year from FY 1997 to FY
2007, and Cook Inlet oil production declined at 8.0% a
year. Without those investments, decline would have
been 15%.
With respect to the future of the North Slope,
there is going to be a major challenge when ANS
production gets down to about 300,000 barrels a day.
According to Alyeska Pipeline Service Company, which
operates the trans-Alaska oil pipeline (TAPS), the
minimum mechanical capacity of the new electronic
pumps that are being installed is about 300,000
barrels a day.
9:07:21 AM
MS. CROCKETT paraphrased from the next portion of the statement,
which read as follows [original punctuation provided]:
Here is a graph showing how long we have before
ANS production reaches this 300,000 barrel-a-day
mechanical threshold, depending on what the rate of
decline is. If decline continues at the historical
rate of 6%, ANS will decline to 300,000 barrels a day
in about 15 years, or FY 2022. On the other hand, if
decline can be held to 3% or less as DOR assumes, then
we would have 30 years or so before we hit the
mechanical threshold.
Let me stress that this graph is not a
prediction. It merely plots the results of the
mathematical calculations of how long it would take to
get to 300,000 barrels a day from the level of 740,000
barrels a day in FY 2007, depending on what decline
rate you choose. What it does show is how important
the rate of production decline is for Alaska's future.
The difference between a 6% decline rate and 3%
doesn't sound like much, but as you can see from the
graph, that difference determines whether the 300,000
barrier is reached around FY 2022 or FY 2037. If you
have a child in junior high school, this represents
the difference between that child being able to grow
up and have a career on the North Slope, and not
having this opportunity.
Investment in new production is the only way to
slow the decline enough to give the children of this
state a future with the North Slope similar to what we
have enjoyed. That's why new investment is such a
crucial question facing the State, both in the context
of the proposed tax proposal and in other areas that
affect the business climate here.
There are three categories of investment that can
slow the rate of decline on the North Slope, or at
least keep it from getting any worse. These are,
first, investment in exploration to discover new
fields; second, investment in existing fields to
prevent their decline from accelerating; and third,
investment in innovation, technology, and new
infrastructure to allow development of the vast but
challenging resource of heavy and viscous oil that has
already been discovered.
A great deal of the testimony to the Legislature,
and a lot of the questions being asked, have focused
on the fiscal terms of the "government take" for
exploring in Alaska and the competitiveness of these
terms relative to the terms in regimes elsewhere in
the world. This kind of "who takes more" analysis is
faulty for two fundamental reasons.
First, it assumes that the geologic prospects for
making a commercial discovery in Alaska are comparable
to those other regimes. This assumption is unsound.
The North Slope has three major areas of significant
oil and gas potential: the state lands in the central
North Slope between the Colville and Canning rivers,
the federal land in the National Petroleum Reserve -
Alaska to the west of the state lands, and the coastal
plain of ANWR to the east of the state lands. The
exploration potential of the state lands is limited
today primarily to the discovery of new satellite
fields, as opposed to fields large enough to stand on
their own economically. Exploration is still active
in NPR-A and by no means over, but the courts have
recently blocked federal leasing of the geologically
promising lands around Teshekpuk Lake. And even if
the Ninth Circuit decides to let that leasing go
forward, the pro-leasing Bush Administration has less
than 14 months left in office in which to hold the
lease sale. Elsewhere in NPR-A, the relinquishment
earlier this fall of some 300,000 acres of lands
reflects disappointing results from leaseholder
exploration efforts there. As for ANWR, despite
Republican majorities in both houses of Congress and a
pro-development president in the White House, the
coastal plain is still closed.
9:10:35 AM
MS. CROCKETT continued reading from page four of the handout:
And this brings me to the second reason why it is
unwise to focus too much on investment in exploration
as the solution to production decline. Exploration is
a risky business, and there is no assurance that
spending money to test a particular prospect will ever
yield a dime of payback. Even when exploration
succeeds in discovering a commercially viable field,
it will take years from the time of its discovery
until the time production from it begins. But the
challenge of declining production confronts Alaska
today - not eight, ten or a dozen years from now. By
its nature, investing in exploration can make a
significant contribution toward solving the challenge
of declining production in the longer term, but not
the shorter term when results are urgently needed.
Investment in heavy and viscous oil development
is also a solution in the mid to long term. The first
well ever drilled to test production from the Ugnu
Formation was only drilled earlier this year in the
Milne Point Unit, and it is still being tested and
evaluated to gain a better understanding of the
physical characteristics of the Ugnu oil. There are
plans to use the results of these tests and
evaluations to plan and develop a pilot project for
producing Ugnu oil. Until then, West Sak will
continue to be the only commercial heavy/viscous
opportunity.
This gets us to investment in currently producing
fields. Fortunately, there are investments that can
be made, and are being made, in these fields to slow
their decline. In the short term, this is in-fill
drilling - that is, drilling new wells into the
portions of a reservoir that are between the wells
that have already been drilled. This accelerates the
drainage of oil from the rock that currently lies in
between existing wells. In-fill drilling last year
contributed some 70,000 barrels a day to production
from the Prudhoe Bay field. To put this into
perspective, a 70,000 barrel per day field would be
th
the 4 largest stand-alone field on the North Slope
today.
There are also major investments being made, and
yet to be made, in "renewal" of the surface facilities
for existing fields. For instance, the gathering
centers and flow stations for the Prudhoe Bay field
have been in service for over 30 years now. For them
the situation is not all that different from what
yours would be if you bought a minivan van years ago
when your children were young, and now that the kids
are all grown up and it's just you and your spouse who
are driving it, it's time to replace that minivan with
a new vehicle that suits your needs better. If
Prudhoe Bay and the other producing fields are to
continue producing in the decades to come, their
original production facilities will need to be
overhauled or replaced. Also, as increasing amounts
of heavy and viscous oil come into production, even
relatively new facilities that were designed for
comparatively light "conventional" oil will probably
need to be modified, refitted or replaced in order to
minimize operating problems in handling that heavy/-
viscous oil. Regardless of the stimulus or purpose
for making them, renewal investments in production
infrastructure present a very similar cash-flow
pattern as there is for investments in the original
infrastructure to develop a field. And consequently,
an incentive that is effective for the initial
development infrastructure is equally effective for
renewal as well.
9:14:02 AM
MS. CROCKETT continued:
So, this is the harsh reality in which we -
government, industry, the present generation of
Alaskans, and the next one - find ourselves. For all
of us, decline is the great challenge that we must
grapple with. It already threatens us now, and if
unaddressed, will only get worse. Massive new
investments for additional oil production are the only
way to deal with this menace, and there are three
areas of investment that can be made to deal with it:
exploration, heavy and viscous oil development, and
slowing decline of existing fields. The first two are
of greatest benefit for the long term, and the other
one is of great benefit for the near term. We need
all three kinds of investment and don't have the
luxury of ignoring one or two of them. I have
explained our collective situation in such detail so
we can each see for ourselves why declining production
is the great issue of the day for Alaska.
Turning now to the relative merits of SB 2001
versus PPT, AOGA submits there are several self-
evident principles of taxation that should be used to
test those merits. First, a tax must be "fit for
purpose" - that is, it must do the things it is
intended to do, and it should do them well. Second,
the administration and enforcement of a tax should be
as efficient as possible, consistent with ensuring
compliance by taxpayers. Third, for a taxpayer who
wants to calculate and pay the correct amount of tax
when it comes due, it must be possible to do so.
Regarding the first test - achieving what the tax
is supposed to achieve - most new taxes have as their
primary or only purpose the new revenues that they
will bring in for the government. In the case of PPT,
however, things were not so simple. In part its
purpose certainly was revenue-related, because most
legislators viewed the prior [economic limit factor
(ELF)]-based production tax as outdated and unduly
generous to producers in terms of the reduction in tax
rate that the ELF caused. But, as Pedro van Meurs
explained repeatedly in his testimony last year and
again at the beginning of this special session, the
PPT was also designed to provide incentives for
investing in production and in that way answering the
threat of declining production.
With respect to the revenue side, no one disputes
that PPT has brought the State more tax revenue since
April last year than ELF would have. According to
DOR, the increase was more than $800 million in the
last nine months of 2006, and at that rate it would
have been over a billion dollars in additional
production tax revenue for a full year. DOR also said
st
at the time that the March 31 payments were about
$137 million less than the $950 million that it had
estimated, and in due course I'll come back to the
questions of forecasting the PPT and higher-than-
forecasted lease expenditures. For now, my point is
that PPT has certainly outperformed the old ELF tax,
which is just what it is supposed to do.
As a consequence of the fact that field costs are
higher than DOR predicted last year, this
Administration criticizes PPT for failing to generate
all the tax revenues that the fiscal note for HB 3001
predicted. It has even been suggested that Alaskans
were somehow promised that PPT would generate $800
million more this year than is now being projected,
and that it is therefore necessary to raise the tax
rate in order to make good on that promise.
That whole line of reasoning is flawed. First of
all, DOR is complaining that they can't forecast PPT
accurately because it has so many variables that
affect the results. However, if they can't forecast
it accurately, then why should so much reliance be
placed on its current forecast that shows the prior
forecast was off by $800 million? If the first
forecast was poor, what has changed to make this
latest one so good?
9:17:30 AM
MS. CROCKETT continued as follows:
As I explained just a while ago, the purpose of
PPT was more than just the tax revenues it would
generate. It was to create incentives for attracting
the massive new investments that will be needed in
order to meet the threat posed by declining
production. The system of tax credits under PPT
provides significant incentives for investing in
capital assets to explore for, develop, and produce
more oil and gas.
ƒCurrent capital expenditures generate a 20% tax credit
in addition to being immediately deductible as lease
expenditures. For the kinds of economic analysis that
reflect the time-value of money, these front-end
benefits have the greatest possible positive effects
on the results of the analysis.
ƒThe incentive to invest sooner rather than later is
materially increased by the fact that the
"transitional investment expenditure" or "TIE" credit
for pre-PPT capital investments can only be taken to
the extent those prior expenditures are matched two
for one by new capital expenditures, and taxpayers
have only until the end of 2013 to use up their "TIE"
credits.
ƒThe 20% tax credit for a carried-forward annual loss
particularly benefits explorers and those who are
bringing new fields into production for the first time
in Alaska and don't have production yet that they can
deduct their costs against.
ƒThe "section 024(c) credit" of up to $12 million a
year for producers with less than 100,000 barrels a
day of production is an incentive for independents and
other smaller players to come to Alaska for oil and
gas.
ƒThe $6 million annual credit under AS 43.55.024(c) is
an incentive for exploration and development in the
areas of Alaska outside the North Slope and Cook Inlet
basin.
Have these incentives under PPT worked? The
rd
preliminary results so far say yes. DOR's August 3
report on PPT states that capital investments for FY
2008 are 80% greater than previously estimated,
despite the fact that operating expenditures are up by
101% over the prior projections. Of course, it will
take time before companies can fully respond to these
incentives, and it will take even more time to tell
whether the new investments to increase oil production
succeed in actually getting more production. But so
far things appear to be moving in the right direction.
There is the question of whether the inability of
explorers and almost-producers to sell their credit
certificates near face value has been a material
problem. As the Executive Director of AOGA, I can
assure you there is no one among AOGA's membership who
thinks any problem in selling the certificates has
been serious enough to justify amending the PPT.
Now, moving on to SB 2001, how well does it stack
up under the standard of being fit for purpose?
Certainly, it would generate even more tax revenue
than the PPT will, at least in the short term. But it
is premised on the totally mistaken notion that
increasing what the government takes from the economic
"pie" will encourage greater investment, or at least
not decrease it from what it would be anyway. No one
has ever taxed economic growth and development into
existence. SB 2001 will not do so, either.
The second standard for evaluating SB 2001versus
PPT is that the administration and enforcement of the
tax must be as efficient as possible, consistent with
ensuring compliance by taxpayers. Here, the two chief
objections to PPT have been, first, that it is all but
impossible to forecast the revenues from it with the
accuracy needed for state budget purposes, and second,
that the audit challenges of PPT leave DOR's auditors
hopelessly outgunned. So the questions that need to
be answered are, how much merit do these criticisms
have, and how would SB 2001 address these concerns?
Regarding forecasts for PPT, DOR cites two major
concerns about the forecasts. One is that, "[w]hile
costs would be expected to increase, the dramatic
difference between what was predicted [in the prior
Administration's fiscal note for HB 3001] and what has
actually been experienced brings into question whether
the legislature made its decisions based upon
appropriate information." The other is that DOR needs
cost information about current and planned spending
from the operators, producers and explorers, and this
allegedly has not been forthcoming from them.
Let us consider this "dramatic difference"
between the projected expenditures behind the fiscal
note last year, and what those expenditures have
actually been. When the DOR staff in the prior
Administration sought information about expenditures,
they chose not to rely on the representations about
2006 costs that individual companies gave the
Legislature in public testimony at that time.
Instead, they looked at what they believed to be more
reliable information contained in the most recent
partnership tax returns that had been filed with the
IRS for fields on the North Slope.
9:22:55 AM
MS. CROCKETT continued paraphrasing the statement, which read:
Federal partnership returns are not due to be
filed with the IRS until October of the following
year, so even as late as August 2006 when the
Legislature passed HB 3001, the most recent returns
available were those for 2004. Here is a chart
showing the Producer Price Index for oil and gas field
machinery and equipment during the last decade. The
highlighted bar in the graph marks 2004, and you can
see right away why a fiscal note based on the most
recently filed federal tax returns, for 2004, would be
way off the mark in predicting what the field costs
would be in 2006 and '07.
There was nothing sinister about what that
Administration did. The companies said the 2006 costs
were high, but the latest tax returns at that time
indicated the costs were significantly less, with a
fairly lengthy track record of gradual increases. DOR
went with the reported information on the tax returns.
I suspect the DOR staff in the present Administration
would do the same in those circumstances. In any
event, this is not a reason for casting PPT aside.
The other criticism that DOR makes of PPT is that
producers and other taxpayers are not providing DOR
with the information it needs in order to be able to
forecast PPT revenues with sufficient accuracy.
Obviously, AOGA is not privy to what these taxpayers
are reporting to DOR as they make their monthly
installment payments and their annual true-up payment
st
on March 31.
DOR's second chief objection to the
administrability and enforceability of PPT is that the
audit challenges of PPT leave its auditors hopelessly
outgunned. It is not for us to comment about the
proposal to put auditors in the "exempt" service.
But there is a dimension to PPT audits, however,
that we can and should address. This has to do with
what the source or starting point for determining how
much a producer's deductible lease expenditures are.
The PPT statutes currently allow DOR a choice between
starting from the joint-interest billings and invoices
that operators bill to the other participants in an
oil and gas field or venture, or starting from a
comprehensive set of accounting rules and principles
that DOR writes up. Which choice DOR chooses will
determine nothing less than the very success or
failure of PPT as a tax - and for SB 2001 as well, if
it is enacted. It is like having a tax based on your
federal taxable income, and choosing between your
federal tax return (as audited by IRS) as the starting
point, or starting with the Internal Revenue Code and
leaving it up to you and DOR's auditors alike to find
what the right answer is under the Code. It is like
having a tax based on your financial book income, and
choosing between your audited financial statements
filed with the SEC as the starting point, or starting
with Generally Accepted Accounting Principles and
leaving it up to you and DOR's auditors alike to find
what the right answer is under GAAP.
From the taxpayer's perspective, this means a
near certainty of continual assessments year after
year for additional tax, interest, and perhaps
penalties, and depending on how litigious a company
may feel, it may mean a long series of lawsuits and
appeals as well.
From the State's perspective, these same troubles
for the taxpayer will mean that the incentives for
investment under PPT, or SB 2001, will be seriously
eroded. The greater the uncertainty about how much
tax a company owes, the greater the likelihood that
the incentives will turn out be less than their face
value. A taxpayer's only recourse in this situation
will be to discount the face-value of those incentives
significantly, perhaps completely, in running the
economic analysis about making an investment or not.
As a consequence, the effectiveness of those
incentives will be less than it should be, and Alaska
will fail to realize the full amount of new production
that it needs to meet the challenge of decline.
The other choice that DOR could make is to start
with what an operator bills to the other participants
in an oil and gas operation. Note that I said "start"
with those billings - not "end." Anything in those
billings that is nondeductible under AS 43.55.165(e)
would have to be backed out. The central concept of
lease expenditures in AS 43.55.165(a) is that they
must be "direct" and "ordinary and necessary" costs of
exploration, development, or production. It would be
most surprising if there [is] anything in those
billings that goes outside this standard.
How can Alaska be sure of this? Because the
participants in an oil and gas operation do not give
the operator a license to waste their money. I have
heard a great deal of concern expressed during these
hearings about how the companies might somehow try to
"game the system" in order to reduce the tax they will
pay the State. While so many are so worried about
efforts by the companies not to overpay the State, why
would most of these same people think the companies
are somehow more willing to overpay the operator than
the State? Clearly they don't want to overpay either
one. If anything, since the operator usually is a
direct competitor, they probably don't want to overpay
it even more than they don't want to overpay the
State. In other words, if an operator is exploring a
geologic prospect, the non-operating participants
don't want to pay any costs that are not for the
exploration of that prospect. Similarly, if the
operator is operating a producing field, they don't
want to pay any costs that aren't for the operation of
that field. It is reasonable to rely, in the first
instance, on the non-operators' self-interests to
police and limit what the operator can spend their
money on, and they will do that policing by auditing
the operator's invoices to them.
9:31:37 AM
MS. CROCKETT continued:
In the context of PPT, DOR should "audit the
audits" to verify that the non-operators do indeed
audit an operator's invoices on a regular basis, and
that those audits are rigorous and at arm's length.
But once these things have been confirmed by DOR in
its verification of the non-operators' audits, there
is little point for DOR to spend the time and effort
to re-plow the field that the companies' audits have
already plowed.
Daniel Johnston, a consultant hired during last
year's debate on PPT, gave an informal presentation to
members of the Legislature on Friday, Oct. 19, 2007.
During that meeting, he praised the expertise of joint
interest auditors and the ability for the state to
utilize unit accounting. He went onto say that it
would be "extremely insightful for the state to get
unit accounting". Mr. Johnston observed that state
auditors can be "vicious", but that joint interest
auditors are "even more vicious".
Of course, for operations where there is only one
participant or where there are no audits of the
operator's invoices, this approach will be
inapplicable. But there are still things DOR could do
to build off the billing systems where there are such
audits and extend them to these other fields.
However, DOR has not yet adopted the "Phase II"
regulations to implement and apply its existing
statutory authority to authorize or require taxpayers
to follow this approach.
A very dismaying thing about SB 2001 is that
Section 64 would repeal DOR's explicit statutory
authority under AS 43.55.165(c) and (d) to require or
authorize the use of operators' joint-interest
billings as the starting point for computing the
amount of a producer's deductible lease expenditures
for that unit or field, while Section 71(b) would make
that repeal retroactive to April 1, 2006.
We believe that this repeal will mean DOR cannot
authorize or require a producer to start with an
operator's joint-interest billings, even when DOR
wants to allow or require their use. Since these
repeals are in the proposed legislation that has been
introduced, we expect that DOR, in response to us,
will testify that somehow they will still be able to
require or authorize the use operator billings even if
these present statutory provisions are repealed.
However, if you enact a law specifically saying DOR
may do something and later on you repeal that law,
doesn't that repeal mean DOR can't do it anymore? We
think so. But even if you are persuaded by DOR that
we're wrong on this point, why should you repeal those
statutes and take the chance that the courts won't
agree?
The reason I've spent so much time about the use of
joint-interest billings as the starting point for
determining a producer's lease expenditures is this:
Consider the situation that a non-operating
participant faces. All the information it has about
what's being spent for the operation is what it gets
from its billings from the operator, plus whatever it
may learn by auditing those invoices. But if such a
non-operator cannot start from those invoices, how can
it figure out what to report as the lease expenditures
for that operation? All the books and records of the
expenditures are with the operator, and if the non-
operator hasn't yet audited the operator, it will have
no idea what those books and records show. It is
infeasible for a non-operator to be auditing the
operator month by month, yet the non-operator will
somehow have to be reporting and paying installments
month by month throughout the year. Even by the March
31 true-up the following year, it is unlikely that any
audit of the operator's books and records will have
been begun by that date, much less completed. The
penalty for mis-estimating the installment payments is
principally in the difference between the rate of
interest on overpaid installments and underpaid ones.
But the March 31 true-up is very serious business.
Interest at an APR not less than 11% compounded
quarterly begins to accrue, and penalties of up to 30%
for negligence and failure-to-pay can be assessed, on
the amount of any underpayment continuing after that
true-up date. If a non-operator cannot rely on its
billings from the operator as the starting point for
these purposes, what is it supposed to use?
9:32:56 AM
REPRESENTATIVE SAMUELS asked:
I would assume, if you are ... Exxon, and you have to
pick BP for operating at Prudhoe Bay, ... you'd have
nowhere to go if you didn't use those billings that BP
sent you. The way that you're reading the proposed
legislation, where would DOR start?
9:33:48 AM
MS. CROCKETT emphasized that HB 2001 would repeal the
authorization or ability of DOR to use joint interest billings.
By repealing that provision, she said, AOGA questions whether or
not DOR could use "those joint operative billings as a starting
point."
9:34:16 AM
REPRESENTATIVE SAMUELS remarked that the commissioner had a
different take on that language.
9:34:59 AM
REPRESENTATIVE NEUMAN asked for clarification of a paragraph on
page [10] of the statement, which begins: "We believe that this
repeal will mean DOR cannot authorize or require a producer to
start with an operator's joint-interest billings, even when DOR
wants to allow or require their use."
9:35:56 AM
MS. CROCKETT explained that that paragraph communicates AOGA's
belief that the ability currently in statute for the department
to use joint interest billings as a starting point for audit
purposes would be repealed by HB 2001. In response to a
question by Representative Neuman, she said it is not the
understanding of AOGA that the bill reinstates that capability.
She said AOGA concurs with Representative Samuels'
recommendation that clarification be obtained from DOR.
Furthermore, she recommended that there be legislative
discussion to clarify that it is the intent to continue to allow
the department to continue to use those [joint interest
billings].
9:37:47 AM
MS. CROCKETT returned to paraphrasing the next portion of the
statement, which read as follows [original punctuation
provided]:
If, as we fear, the repeals of AS 43.55.165(c)
and (d) under the proposed bill will indeed take away
DOR's discretion to allow or require the use of
operators' joint-interest billings, then SB 2001 will
completely fail the third standard by which a tax is
measured - that it must be possible for a taxpayer to
get the tax right when it is due, when the taxpayer
wants to do so. This will be impossible for non-
operators under the proposed legislation. Even PPT
will fail if the "Phase II" regulations do not
reasonably implement DOR's present authority under AS
43.55.165(c) and (d) regarding the use of operator
billings.
Before I close, there are a few confusing things
in the SB 2001 I would like to address.
The first of these is Section 1, declaring that
subsection (b) in the new production-tax statute of
limitations being enacted is intended to "confirm by
clarification the long-standing interpretation of AS
43.05.260 by the Department of Revenue relating to
limitation of assessments for the production tax on
oil and gas and conservation surcharges on oil." Does
anyone here know why this is in the bill? AS
43.05.260 is the existing statute of limitations for
auditing all state taxes under AS 43, and what is it
about this present limitations statute that is being
"confirm[ed]" by the new AS 43.55.075(b)?
If you read this new section 075(b) - which
begins on page 35 line 30 and runs through line 15 on
page 36 of the bill - you see there are two parts to
the subsection. One part is the first two sentences,
which address the effects for tax purposes of judicial
or administrative decisions that retroactively change
parameters for calculating the tax. The other part is
the last sentence, including paragraphs (1) and (2),
and requires producers to report such decisions to DOR
within 60 days and to file amended returns within 120
days.
The curious thing is that the existing statute of
limitations (AS 43.05.260) - the interpretation of
which is to be "confirmed" - has nothing in it
pertaining to either of these subjects. Here is the
text of AS 43.05.260 and you can see this for
yourselves. Subsection (a) sets three years as the
period for DOR to audit and assess any additional tax
that may be due, and it bars suits to collect any
additional tax if that tax is not assessed within the
three-year period. Subsection (b) says that, if a
taxpayer files its tax return early before it is due,
the three-year period starts running from the due date
instead of the actual filing date. Subsection (c)
creates three exceptions to the rule under subsection
(a), which appear as paragraphs (1) - (3) of
subsection (c): namely, for false or fraudulent
returns to evade tax, for a failure to file any return
at all, and for extensions of the three-year period
that are mutually agreed upon in writing by DOR and
the taxpayer.
Which of these provisions has anything to do with
tax effects of retroactive decisions? Which has
anything to do with having to report such decisions to
DOR and filing amended tax returns? It is not
immediately clear to us what either of these topics in
the new statute of limitations has to do with
interpreting any of the provisions in existing statute
of limitations I've just reviewed with you. So
what's going on with Bill Section 1?
9:41:21 AM
MS. CROCKETT continued:
We believe Section 1 is a stealthy attempt to
legislate an outcome to matters that are already being
litigated in the due course of administrative and
judicial proceedings. In 1999 DOR amended one of its
production tax regulations, 15 AAC 55.200, so that it
reads remarkably like AS 43.55.075(b) being enacted in
this bill. Here you have the regulation and the
proposed new AS 43.55.075(b) side by side, with
identical or parallel language in them being under-
lined. As you can see, the regulation deals with
"decisions of regulatory agencies, courts, or any
other preemptive authority" while the proposed new
statute addresses any "decision of a regulatory
agency, court, or other body with authority to resolve
disputes[.]" The regulation deals with "retroactive
adjustments in costs of transportation, sales price,
prevailing value, or consideration for quality
differentials relating to the commingling of oils or
of oil and NGLs" while the proposed statute addresses
"a retroactive change" to the very same things, plus
any change to "a lease expenditure[.]" Both state
that retroactive changes in the parameters for
calculating the taxable value have "a corresponding
effect, either an increase or decrease, as applicable
on" that taxable value.
Now, the "interpretation" that comes into play
here has to do with the question of when interest
begins accruing on a tax increase or decrease that
results from one of these retroactive decisions - does
it begin to accrue as of the date of that decision? Or
does it begin to accrue all the way back to the
original payment due date?
9:43:10 AM
MS. CROCKETT concluded:
When DOR adopted the amendment to the regulation
in 1999, the director of the Tax Division at that time
told AOGA members that DOR was interpreting that
amendment to mean interest would start to accrue as of
the original payment due date for the tax, not as of
the date of the retroactive decision.
We believe it is this "interpretation" of its own
regulation, which is in the process of being appealed
in due course, that the Administration intends to have
"confirm[ed]" under Section 1 of SB 2001 as the proper
interpretation of the pre-PPT statute of limitations.
The question for you is, do you really want to confirm
this?
Confirming it would set a destabilizing
precedent, because it will mean that the laws can
effectively be rewritten to deal with subjects that
they did not originally deal with, and this can be
done clandestinely by "confirming" some purported
"interpretation" of it. For one thing, it would be an
attempt by the Executive and Legislative branches to
determine the outcome of matters that are already
before or headed to the Judicial Branch in due course.
Can the Legislature intervene in Judicial matters
under the Separation of Powers Doctrine, and even if
it can, should it attempt to do so here? Second, what
does it say to potential investors in this state about
our sense of justice, Due Process, and fair play?
Now, if the Administration appears before you or
any other committee of this Legislature and disavows
any and all intention to do such a thing, I would
encourage you to ask them to clearly explain what they
did intend to achieve with Section 1, so that it will
be part of the legislative history of this bill.
Then, if it becomes law, the legislative history will
be there to establish that the "interpretation" which
we fear is not the Legislature's intent, nor the
Administration's.
A second confusing thing in SB 2001 relates to
the new statute of limitations being proposed for
production tax only. Why does the limitations period
need be six years instead of three, when the three-
year period can be extended and re-extended any number
of times as appropriate? If the state auditors are
anything like me and everyone I know, their work will
expand to fill the time allowed - giving them six
years to get their audits done will mean they'll take
six years to audit even when they could otherwise be
done more quickly. Unfortunately, the longer the
audit runs, the greater the amount of interest there
will be that accrues on any underpayment claimed in
the audit. After three years, interest represents 38¢
for each dollar of additional tax claimed, assuming
interest is not above its 11% APR floor rate. But
after six years the accrued interest is 92¢ for each
dollar of additional tax. By raising the stakes so
substantially for each audit claim that is raised, the
longer limitations period will make it easier to
justify litigating claims.
The purpose of a statute of limitations is to bar
claims when they start to become so old that the
records, documents, and recollections of witnesses may
well be lost or not readily available by the time
those claims are finally raised. The present statute
of limitations has worked for all the other taxes
under Title 43, including the present worldwide
corporate income tax for oil and gas taxpayers, the
domestic or "water's edge" income tax for other
corporations, even the former separate-accounting
income tax. It is worth noting that separate-
accounting involved not only determining net income
from all of a taxpayer's interests in oil and gas
fields and prospects, but also its income from
interests in oil or gas pipelines as well. While PPT
and SB 2001 are not simple taxes, separate-accounting
was probably even more challenging to administer and
audit. If Alaska didn't need a longer statute of
limitations for separate-accounting, we don't see why
one is needed now.
In conclusion, SB 2001 fails two of the three
standards for evaluating a tax, while PPT passes two
of them and would pass the third one as well if DOR
adopts the appropriate regulations. SB 2001 in the
short term will generate more tax revenue for the
State than PPT; however, it will achieve this at the
cost of reducing the incentives for new investments,
and worsening the overall tax climate for making them
here. SB 2001 fails the test of being administrable
as efficiently as possible, consistent with ensuring
taxpayer compliance. This failure will primarily be
due to repealing DOR's existing statutory discretion
to allow, as appropriate, joint-interest partners do
the auditing of the operator's billings to them.
Instead DOR auditors could have to re-invent the wheel
for themselves in each audit. SB 2001 also fails the
test that a taxpayer who wants to pay the correct
amount of tax when it comes due must be able to do so.
This will be impossible for every company that owns an
interest in a lease or property that it does not
operate. This in turn will effectively destroy the
value of the remaining tax incentives under this bill
that potential investors will perceive. If they
cannot tell what they owe, they surely cannot put a
reliable figure to the value of the incentives under
the tax.
All of this brings us back to the fundamental
issue facing Alaska today…the decline of Alaska
production. Today Alaska's production has fallen from
its peak of 2.1 million barrels a day down to the
700,000 range. This means that the trans Alaska
pipeline is 2/3 empty. I would remind you of my chart
earlier that showed the purely mathematical results
about how long we have before hitting the 300,000
barrel-a-day TAPS mechanical threshold, depending on
what rate of decline you assume will turn out to come
true.
And it's important to remember that today's 6%
decline rate would be on the order of 15-16% were it
not for the substantial investments which continue to
be made by operators in existing fields. Further,
Alaska is fortunate to have on the nearby horizon
Pioneer's Oooguruk project, scheduled to go into
production in 2008.
The importance of future investment is further
emphasized when one looks at the Department of
Revenue's forecast of future production levels. In
three short years, DOR projects that production will
come from projects requiring significant new
investment. Draw that timeline out to 2017-ten years
from now-and you discover that half of Alaska's
production will come from new production-production
which will only come from investments yet to be made.
The most important policy question is whether SB 2001
provides a framework for encouraging this additional
new investment. AOGA's 17 member companies
unanimously agree that PPT does accomplish that goal,
and as such, should not be changed at this time.
9:50:23 AM
REPRESENTATIVE NEUMAN observed that [the endnotes on pages 17-
19] include mathematical calculations. Referring to page [13],
he questioned whether the legislature can pass a law that has an
effect on matters already in litigation.
9:51:20 AM
CHAIR OLSON indicated that the legislature has done so in the
past. He added that whether that is right or legal might be a
separate issue.
9:52:11 AM
MS. CROCKETT, in response to questions from Representative
Doogan, confirmed that AOGA would have a more detailed analysis
of the bill available as soon as possible. She reiterated that
when making decisions related to tax, AOGA's policy requires a
unanimous vote of its members. In response to follow-up
questions, she said ConocoPhillips Alaska, Inc., is not a member
of the association, but BP is. She confirmed that BP's position
would match the specifics in AOGA's statement. She stated that
when PPT was introduced, AOGA took some time before taking a
position on it because its member companies held varying views.
She noted that she has been with the association for 37 years.
9:54:34 AM
REPRESENTATIVE DOOGAN asked if there has ever been an oil tax
increase bill that AOGA has supported.
9:54:39 AM
MS. CROCKETT said she does not believe so.
9:54:48 AM
REPRESENTATIVE NEUMAN asked Ms. Crockett if it would be possible
to condense AOGA's previously presented statement down to one or
two pages with bullet points to simplify it.
9:55:27 AM
MS. CROCKETT answered probably not in one or two pages, because
tax issues are complicated and require a lengthy presentation.
However, the key concerns could be consolidated.
9:56:02 AM
REPRESENTATIVE NEUMAN indicated that it would be helpful, for
example, when using statute citations, to include the subject of
that statute.
9:56:21 AM
REPRESENTATIVE RAMRAS used Cook Inlet as a discussion point to
compare the tax structures for that area. He said he is "on
board" with the tax strategy for Cook Inlet. Notwithstanding
that, he said it has become commonplace in the legislature to
talk about "the cliff of available gas" in Cook Inlet. He said
everyone is aware of the tax relaxation that ring fences that
area in order to induce exploration, because "even with the
posture change for Agrium, natural gas is still at risk." He
said the TAPS line could be facing the same cliff as Cook Inlet.
He said, "It doesn't take that many years of 6 percent annual
declines to reach different crises points." He mentioned
available state royalty oil for Flint Hills, batching oil
through the TAPS, the economics of maintaining the TAPS line,
and the cost per barrel of oil that moves through the TAPS line
as production declines. Representative Ramras asked why the
current legislature and administration does not seem to want to
care for the industry and be mindful of not creating the same
scenario for the TAPS line that has happened around the
available gas in the Cook Inlet.
9:59:33 AM
MS. CROCKETT replied that there are programs currently in place
on the books that encourage exploration for oil and gas in the
Cook Inlet region, including the state's areawide leasing
program - a reliable access to resources by companies;
exploration incentive credit programs for Cook Inlet; and the
PPT system, which recognizes the challenges facing oil and gas
development and a declining resource area, such as the Cook
Inlet and Southcentral Region. She said discovery and
development of new sources of gas on the Kenai Peninsula and in
Cook Inlet would clearly benefit everyone, and she urged the
legislature to do everything in its power to support that
happening.
10:00:50 AM
REPRESENTATIVE RAMRAS questioned why, if that is true for Cook
Inlet, and everyone grasps that concept, a different approach is
being taken on the North Slope. He asked what is wrong with the
administration and members of the legislature that they want to
"turn the wrench" until they "wreck the economics of the TAPS
line." He explained that he is interested in TAPS because it
runs through his community.
10:01:41 AM
MS. CROCKETT said decline in production is the single most
important issue facing Alaska; it affects the state's revenue
stream, but will also start affecting TAPS. That decline will
require new ways of transporting the oil through TAPS. She said
she would like people to focus on how the decline can be
addressed in the short term. Long-term plans include
exploration and bringing new fields on line, but the number one,
short-term way to address that decline, she proffered, is by
investing in the existing fields. If the fiscal regime sends
the message that investing in the existing fields will not
generate the rate of return needed, then the outcome, she
warned, will be to watch those production levels continue to
decline.
The committee took an at-ease from 10:03:46 AM to 10:17:14 AM.
10:17:29 AM
CRAIG HAYMES, Production Manager - Alaska, ExxonMobil
Corporation, paraphrased the first portion of his 17-page
written statement [the corresponding charts and graphs for which
are available in the committee packet], which read as follows
[original punctuation provided]:
INTRODUCTION
Mr. Chairman, members of the committee:
Good morning. For the record, my name is Craig
Haymes. I am the Production Manager for ExxonMobil in
Alaska, a position I have held since January 2007. I
have the pleasure of living in Anchorage with my
family. Prior to January this year I was involved
with Arctic oil and gas projects on the East coast of
Canada for almost five years.
I want to thank the committee for the opportunity to
express ExxonMobil's views today regarding the
Administration's proposed tax increase.
Let me state upfront, ExxonMobil believes the current
PPT tax rate and the increase proposed by the
Administration will have a negative impact on resource
investments in Alaska. ExxonMobil does not support
the proposed tax increase by the Administration.
We believe that Alaska needs to focus on a long-term
resource development policy. The policy should
encourage increasing investment that is needed to
maximize the development of Alaska's resources.
Alaska is rich in undiscovered resource potential, yet
oil production continues to decline from mature
basins. Oil production today is one third of the peak
of over 2 million barrels per day in 1988. Alaska
faces a significant challenge. We have a common goal
to maximize economic resource development and need to
work together; Government, industry, and the people of
Alaska, to enhance the development of Alaska's rich
resources and the future.
MR. HAYMES paraphrased the next portion of his written
statement, beginning on page 2, which read as follows [original
punctuation provided]:
EXXONMOBIL IN ALASKA
ExxonMobil invests all over the world to meet the
growing need for energy. Over the last 20 years we
have invested close to $280 billion dollars to search
for new supplies of energy, build new production
facilities, expand refinery capacity and deploy new,
environmentally sound technologies.
ExxonMobil believes technology innovation is the key
to meeting the world and Alaska's energy challenges.
Technology is the lifeblood of our industry.
ExxonMobil currently spends close to $1 billion per
year on research and technology. We have consistently
applied our technology in Alaska to unlock and develop
resources. We have significant arctic experience
around the world.
Some examples of technology applications that we have
contributed to Alaska are
· The installation of the ice resistant Granite Point
platform in Cook Inlet, which is still producing oil.
· Significant research and engineering for the Prudhoe
Bay completion designs for permafrost
· The installation of the first Concrete Island Drilling
System (CIDS) to drill exploration wells in ice
covered waters in the Alaska Beaufort Sea.
· The first full-field 3-D simulation model of Prudhoe
Bay, leading to many enhanced oil recovery and
development drilling programs that are still being
pursued today.
10:21:04 AM
MR. HAYMES' statement continued as follows [original punctuation
provided]:
The application of technology will continue to be a
key to the future of Alaska's resource developments.
ExxonMobil has had a presence in Alaska for over 50
years and has been a key player in Alaska's oil
industry development, spending and investing over $20
billion dollars. We hold the largest working interest
at Prudhoe Bay (36.4%) and our current working
interest share of oil production in the state is
approximately 150,000 barrels per day. We are also
the largest owner of discovered Alaska gas resource.
We are currently active with our co-owners at Prudhoe
Bay, Kuparuk, Duck Island, Granite Point and Point
Thomson. Over the last two years we have
participated in the drilling of over 70% of the wells
on the North Slope - over 130 wells were drilled at
Prudhoe Bay alone - this drilling will add 50,000 B/D
of oil production in 2007, an important contribution
to help mitigate production decline.
We are proud of the role that our company has played
in Alaska, which we believe has benefited both the
State and the industry, and we look forward to working
with Alaska for many years to come.
10:22:31 AM
MR. HAYMES addressed Alaska's resource opportunities,
paraphrasing from the portion of his written statement beginning
on page 4, which read as follows [original punctuation
provided]:
ALASKA RESOURCE POTENTIAL IS SIGNIFICANT
I would like to take a few moments to discuss Alaska's
resource opportunities. Alaska has significant oil
and gas resources. According to the US Geological
Survey and the US Minerals Management Service,
Alaska's undiscovered technically recoverable
resources are 53 billion barrels of oil. This is in
addition to the Department of Natural Resources
estimate for known remaining oil resources of 6
billion barrels. To date Alaska has produced close to
17 billion barrels of oil - this is a world class
result - but is less than one fourth of the potential
total of 76 billion barrels. That is, Alaska still
has the potential to produce another 59 billion
barrels of oil. The gas resource potential almost
doubles this undiscovered potential on an oil
equivalent basis.
Whilst Alaska's resource potential is high, the Oil
and Gas Journal and Energy Information Administration
report that its world ranking of proved reserves has
thth
declined from 14 in 1977 to a position closer to 30
today.
10:24:01 AM
MR. HAYMES addressed the subject of Alaska's future oil
production, paraphrasing from that portion of his statement,
found on page 5, which read as follows [original punctuation
provided]:
ALASKA's FUTURE OIL PRODUCTION
Today Alaska is producing approximately 750,000
barrels of oil per day from the North Slope, one third
of its peak production. The Department of Revenue's
production outlook, from their Spring Revenue Sources
Book, shows that they estimate a 9% annual decline in
Alaska's current base production. As the chart
illustrates, at this decline rate, over the next ten
years Alaska's current base production, shown in
green, will drop to around 360,000 barrels per day.
That is a production level of less than half of
today's.
The Department of Revenue also forecasts that this
base production decline will be partially mitigated
with the development and production of oil in
categories called "Under Development and Under
Evaluation", shown in blue on the chart. These
categories include future investments, such as
development drilling, satellite developments, and
enhanced oil recovery from existing fields. Based on
this forecast, over 50% of the projected oil
production in 10 years will come from new investments.
Let me say that again, 50% of future oil production in
10 years is not even developed or producing today.
Considering that most new projects take at least 5-7
years to bring to production on the North Slope,
investment decisions for these activities,
particularly in the near term, will be critical to
underpin the future of Alaska's oil production.
As I mentioned earlier, the Department of Revenue
forecast is based on a 9% annual decline in Alaska's
current base production. However, this decline
assumes that production enhancement investments at the
core Prudhoe Bay, Kuparuk and Alpine areas continue.
The Department of Revenue forecast, as shown, does not
highlight that this activity requires investment
decisions that are no different from the "Under
Development and Under Evaluation" categories. As such,
a more accurate representation of the future oil
production and investment levels required to achieve
the Department of Revenue forecast is illustrated in
the following chart.
As this chart shows, Alaska's oil production from the
North Slope could be as low as 150,000 barrels per day
within 10 years, (assuming 15% decline, which is
typical for large oil fields such as Prudhoe Bay),
without ongoing and increasing investment. Based on
this forecast, within 10 years, 75% of production will
come from new investments.
Conservatively, we estimate that at least $30-40
billion of investment is required within the next 10
years to achieve the Department of Revenue forecast.
This does not include the billions of dollars of
additional operating expenditures that would be
required to support the developments once they are
producing. This is a significant level of future
investment and spending.
The high tax rate in PPT and the proposed tax increase
put this investment at significant risk. Alaska needs
to encourage the increasing investments required, not
only in exploration activities, but also in the
ongoing development of existing and new fields.
10:28:01 AM
MR. HAYMES talked about Alaska as a high cost region, and he
paraphrased his written statement at page 8, which read as
follows [original punctuation provided]:
ALASKA IS A HIGH COST REGION
Complicating the significant future investments
required to mitigate Alaska's production decline is
its high costs. Alaska has unique challenges
resulting in a high cost environment for exploration
and development and very mature producing fields with
growing unit costs. Many factors contribute to
Alaska's higher costs including:
· Severe arctic conditions, placing limitations on when
drilling and other operations can be undertaken
· A sensitive environment, requiring significant and due
diligence measures to protect it
· Remote location of the resource and distance to market
· Current restrictions for future exploration
opportunities
All combine to create a unique and high cost
environment for Alaska.
10:29:14 AM
REPRESENTATIVE NEUMAN mentioned the Department of Revenue's
charts. He talked about the estimates of a drop to 360 barrels
a day in ten years, and a cost of $30 to $40 billion in new
investment "to increase that by 75 percent to maintain the
levels that we're at," and he said that means $3 to $4 billion a
year in new investment. He asked how much new investment
ExxonMobil Corporation has put into Alaska in the last five
years.
10:30:31 AM
MR. HAYMES replied that the current investment levels in Alaska
are approximately $2 to $2.5 billion, and he said that number
has been increasing. The UAA web site, he noted, provides
statistics showing that the amount has increased from $1
billion. In accordance with the forecast of the Department of
Revenue, achieving the level of production that Representative
Neuman alluded to would require, conservatively, $3 to $4
billion a year in investment.
10:31:16 AM
REPRESENTATIVE NEUMAN asked what assurances Alaska has that the
oil industries combined will invest if PPT stays the same.
10:32:08 AM
MR. HAYMES said he thinks part of the discussion needs to focus
on how to encourage that level of investment to achieve that
desired production level. ExxonMobil Corporation, like any
other company, he said, will look at the attractiveness of the
opportunities and consider many factors. Alaska is a high-cost
environment; the investment level required to pursue oil is very
high, and projects in the state are capital intensive. The
company looks at investments over decades, because they take
years to generate a return. Part of that foundation, he said,
is fiscal policy and environment, two factors which he said he
would cover further into his testimony.
10:33:20 AM
REPRESENTATIVE NEUMAN said he would like to know where
ExxonMobil Corporation's new investment money comes from and
what the company's opinion is as to the effects of PPT on
investment in Alaska.
10:33:54 AM
MR. HAYMES said ExxonMobil Corporation believes that the tax
rate on PPT is too high if Alaska wants to encourage the full
development of its resource potential. The company believes
that the net structure of PPT will encourage investment at the
right tax rate. He said investment levels have increased over
the last few years; however, the question that needs to be asked
is how high it could have been. He said that is a difficult
question to answer, because it is "very hard to know what we
haven't achieved when we don't know." He mentioned the U.S.
estimate of 76 billion barrels of oil of potential technically
recoverable reserves and that not only one quarter of it has
been produced. He stated, "That's the prize that we all need to
work together to pursue." He said ExxonMobil Corporation has a
keen interest to pursue the development of energy across the
world, and if the environment and conditions are right, it will
do so.
10:35:23 AM
MR. HAYMES returned to his presentation. He paraphrased from
the portion of the statement beginning on page 9, which read as
follows [original punctuation provided]:
ALASKA'S SO-CALLED LEGACY FIELDS
The two largest oil fields in Alaska - Prudhoe Bay and
Kuparuk, have been producing since 1977 and 1981,
respectively. Today these two fields account for over
70% of the State's North Slope oil production.
Assuming that exploration and investment activity
continues in these fields, they could remain at this
level of production contribution for the next decade.
These so called legacy fields require continuous
investment to keep the oil flowing and the facilities
operating at capacity. This is the same for any oil
field in the world. During the production phase there
are many changes in operating parameters, such as
reservoir pressure changes, oil, gas and water
production changes, changes in operating conditions,
and ongoing technical challenges. In order to keep
the oil flowing, these changes require additional
investments, such as the addition of water and gas
injection and gas compression facilities, which are
historical significant investments at Prudhoe Bay.
Currently, the owners spend over $2 billion dollars to
optimize and enhance production from Prudhoe Bay and
Kuparuk. These spending levels are in addition to the
capital investments pursuing new wells, projects, and
enhanced oil recovery opportunities. These operating
expenditures are essential to mitigate production
decline at these significant fields, which are
critical to the future of Alaska's North Slope oil
production.
Many of today's exploration and development activities
are occurring in and around Prudhoe Bay and Kuparuk.
As an example, since the year 2000 there have been
multiple Prudhoe Bay satellite fields developed -
Aurora, Borealis, Midnight Sun, Polaris, and Orion -
which are currently contributing over 40,000 B/D of
oil production. These developments would not have been
possible without the infrastructure and facility
sharing of Prudhoe Bay, which reduced the development
and operating costs of these satellites. As satellite
fields are developed it reduces exploration and
development costs for future new projects, as the
infrastructure on the North Slope expands.
If the major Prudhoe Bay and Kuparuk developments did
not exist these satellite fields would not have been
economic to develop.
As another example, for the past seven years over 900
new wells have been drilled in Prudhoe Bay and
Kuparuk. The drilling of these new wells has slowed
the overall production decline from 12-15% to an
estimated 6-9%. Almost 40% of Prudhoe Bay's
production today is from these new wells.
For the past two years, development drilling at
Prudhoe Bay has achieved the equivalent of the
important Oooguruk development. This example
highlights the importance of exploring for and
developing new oil in and around the Prudhoe Bay and
Kuparuk fields - all are important to the economic
benefit and future of Alaska.
Let me re-emphasize that Prudhoe Bay and Kuparuk have
the potential to continue to be critical contributors
to Alaska's oil production. They have the potential
to remain key hubs and enablers for exploration and
development of heavy or viscous oil, light oil and
gas. Encouraging increasing investment at these key
fields is as important as encouraging investment in
exploration and development of new fields. Without
these two hubs, Alaska will be severely challenged to
realize the full potential of its resources.
Progressing a tax policy that singles out and
penalizes these fields will discourage investment not
only at these fields but will also impact future
investment attractiveness to explore and develop other
Alaska oil and gas resources.
MR. HAYMES' statement continued as follows [original punctuation
provided]:
PROPOSED TAX INCREASE MORE COMPLICATED
In analyzing the Administration's tax proposal, we
found that virtually all of the provisions are simply
tax rate increases or further increases in complexity.
As an example, under the Administrations proposed tax
increase the two so-called Legacy Fields, Prudhoe Bay
and Kuparuk, would have a separate 10% gross minimum
tax and be segregated from each other and all other
North Slope fields. This gross tax would be in
addition to the base royalty payments. With this
minimum gross tax the State would be insulated from
price and cost risks, whilst retaining the upside
potential from the progressivity element. The
Administration is simply proposing to increase its
take while shifting the development risks to the
producers. Essentially, at low price, producers are
penalized.
10:41:05 AM
Companies are willing to accept the risks of long-
term, capital intensive investments when there is a
corresponding opportunity for upside potential and a
sharing of risk should prices fall. Under the
Administration's proposed tax increase, investors will
need to assume a higher economic risk when making
funding decisions for future investments and spending.
The Administration has also proposed that all revenues
and expenses for the Legacy Fields will have to be
accounted for separately, with separate taxes paid for
each unit and their satellites. This would include
Alaska's heavy or viscous oil reserves produced from
those Legacy Fields - a resource that already has
significant economic and technical hurdles to
overcome. No other fields, units or regions within
the state would be subjected to these administrative
burdens.
The ring-fencing of the Prudhoe Bay and Kuparuk Units
makes the tax proposal more complex than the existing
PPT.
10:42:28 AM
MR. HAYMES paraphrased the portion of his statement that begins
on page 13, which read as follows [original punctuation
provided]:
EXXONMOBIL POSITION ON THE ENACTED PPT
I believe it is important that I clarify ExxonMobil's
position on the current PPT. ExxonMobil did not
support the PPT that was enacted last year. As we
testified last year, we supported the concept of a net
based tax but stated that the proposed 20% tax rate,
in the original PPT bill, would not encourage the full
development of Alaska's resources. We agreed with the
20% tax rate in order to support the progression of a
gas pipeline project.
The PPT that was ultimately enacted increased the
already high 20% base tax rate to 22.5% with
progressivity - more than doubling industry's
taxation. Alaska's current PPT tax rate is too high.
When combined with the gross royalties and the high
development and operating costs, it makes Alaska one
of the most expensive regions to invest.
There has been a lot of discussion recently on PPT
revenues and forecasts, which has been used in part to
support the Administrations proposal to increase
taxes. PPT has only been in existence for slightly
more than one year. The Department of Revenue has not
completed its PPT regulations or started any PPT
audit. ExxonMobil, like a number of the other
producers, met with the Department of Revenue several
months ago to discuss ways to help the State better
forecast its expected PPT revenues and we are willing
to continue those efforts. We are also willing to
work with DOR auditors to improve their understanding
of joint interest billings.
10:44:20 AM
MR. HAYMES introduced the topic of fiscal predictability and
paraphrased that portion of the statement, beginning on page 14,
which read as follows [original punctuation provided]:
FISCAL PREDICTABILITY IS IMPORTANT
I would now like to address another important element
of the business environment - fiscal predictability.
ExxonMobil, and I believe the industry, values a
predictable fiscal environment in which to make long
term investment decisions. Our investments are
capital intensive and are evaluated over timeframes of
decades. Any change in the fiscal regime has a direct
impact on how we view predictability of the Alaskan
fiscal environment, which in turn directly impacts how
we evaluate on a risk basis future investment
decisions. Let me reemphasize this point. Because
of the nature and magnitude of the risks associated
with any oil or gas investment, coupled with the
amount of time required to recoup that investment,
fiscal terms that are predictable are key to any
investment decision.
The Administrations proposed tax increase would
represent the third significant change to Alaska's
fiscal terms in the past three years. Changing the
fiscal environment for capital intensive projects,
that take many years to generate a return, can only
reduce the attractiveness of future investments.
Each time taxes are raised, the attractiveness of any
prospective well or project diminish and the
likelihood of it not being funded increases. For
every well or project not progressed, additional
production and State revenues are lost. As mentioned
earlier, to mitigate oil production decline Alaska
needs to increase investment. The Administration's
proposed tax increase will reduce investment.
ExxonMobil expects to be involved in Alaska for many years to
come. The policies established today and in the future will
impact the attractiveness of future potential projects and the
future of Alaska.
10:46:31 AM
MR. HAYMES concluded his presentation by addressing the issue of
a long-term resource policy. He paraphrased from this portion
of his statement, which begins on page 15, and which read as
follows [original punctuation provided]:
ALASKA NEEDS A LONG-TERM RESOURCE DEVELOPMENT POLICY
As I mentioned earlier, Alaska has significant
resource potential, but with many unique cost
challenges. It will take significant resources,
technology, investment and teamwork from everyone to
realize the full potential. Alaska and industry
collaboratively need to create a resource development
policy that encourages investment for long-term
production and growth. This is a complex issue and
needs significant time and effort from all parties.
It is beneficial to look at what others have done.
The Canadian province of Alberta has enormous
unconventional crude oil resources. Alberta's oil
sands represent the potential of over 170 billion
barrels of crude, and, like Alaska's resources, are
located in higher cost, remote arctic regions that
require significant investments to develop.
Alberta adopted a resource development policy
approach, designed to increase industry investment and
production. Their approach has proven successful due
to a number of key factors:
· Collaborative pursuit of resource development
objectives
· Development of technologies jointly with industry to
reduce costs, increase oil recovery, and upgrade
viscous oil to marketable products
· Creation of a level playing field for all projects
· Sharing risks with the investors by maintaining a
lower gross revenue based tax, that is, lowering
royalties significantly
· Providing long term fiscal predictability
Alberta's success suggests that Alaska should
seriously consider what other regions are doing to
encourage investment.
A long-term sustainable resource development policy is
required to enable Alaska to maximize its oil and gas
resource. There are many factors that need to be
considered. It is a complex issue. I hope that key
points addressed in my testimony are considered:
· Alaska has significant resource potential, but it is
in a high cost environment
· Oil production is already one third of its peak, yet
we have only produced one fourth of the oil resource
potential
· In 10 years, 75% of Alaska's future oil production
needs over $30-40 billion of new investments -
investments that are needed sooner than 10 years.
· Prudhoe Bay and Kuparuk are the "hub" of the North
Slope, they
¾Represent 70% of North Slope oil production for
the next 10+ years
¾Can be the backbone for future exploration and
economic developments, whether it is existing
production, future light oil, heavy oil, or gas
¾Need increasing investments to achieve their
potential
· Development drilling at Prudhoe Bay and Kuparuk over
the last 2 years has added 50,000 B/D of new oil
production in 2007
We propose a collaborative approach to develop a
sustainable long term resource policy that will
encourage the needed increasing investments and build
the future of Alaska for many generations to come.
ExxonMobil looks forward to working with the
Administration, the legislators, industry and the
people of Alaska in the future pursuit and development
of its oil and gas resources.
To encourage full development of Alaska's resources,
the PPT tax rate needs to be lowered, and should not
include a gross revenue based component. Increasing
investment fuels the economy.
Thank you again Mister Chairman for the opportunity to
testify today.
10:50:54 AM
CHAIR OLSON recollected the discussion two years ago regarding
fiscal certainty rather than fiscal predictability, and how many
legislators at that time "choked" on the concept of a 20- to 30-
year lock-down of the tax structure. He remarked, "Fiscal
predictability looks to me like it might be one step down the
ladder; more of a reasonable position than fiscal certainty."
10:51:59 AM
REPRESENTATIVE SAMUELS asked Mr. Haymes what factors the
ExxonMobil Corporation considers to arrive at investment
decisions.
10:53:13 AM
MR. HAYMES responded that ExxonMobil Corporation looks at
investment on a global level. Considerations include: resource
potential; technical challenges; investment required to pursue a
resource; and costs involved in exploration, appraisal,
construction, production, and final site restoration. The
criteria involve both controllable and uncontrollable aspects.
The latter includes commodity price, tax rates, and fiscal
policy. He said there are internal annual budgeting processes
and working interest owner budget processes that set the tone
for a business plan for future years. Each individual
investment goes through the same scrutiny, he emphasized.
10:56:14 AM
REPRESENTATIVE SAMUELS clarified that he wants to know
specifically what happens when a proposal is handed to Mr.
Haymes.
10:57:51 AM
MR. HAYMES reviewed how an investment portfolio is established
by ExxonMobil Corporation. He explained that a finite amount of
money is allocated proportionally around the world based on
various factors, and it is ExxonMobil Corporation's duty to its
shareholders to maximize return.
11:00:28 AM
MR. HAYMES, in response to a question from Representative
Neuman, stated that ExxonMobil Corporation is keen on working
with the State of Alaska to commercialize its gas resources, and
the corporation is and will continue to be active in looking at
that opportunity. In response to a follow-up question from
Representative Neuman, he confirmed that ExxonMobil Corporation
is not involved in any current discussions with the
administration.
11:00:52 AM
REPRESENTATIVE NEUMAN stated:
When ... people from ExxonMobil Corporation came here,
and you said that you didn't like what we did in PPT,
and you didn't like what the [Alaska's Clear &
Equitable Share (ACES)] does, ... it's kind of a punch
in the guts for me somehow when I go back to 1989 and
the money that's owed to the citizens of the state of
Alaska, you know, billions of dollars. So, any good
faith effort, if you could pass that up, would go a
long ways to this guy, ... [and], I think, for the
state.
11:01:42 AM
REPRESENTATIVE DOOGAN, recalling Mr. Haymes' testimony that
ExxonMobil Corporation did not support the 20 percent rate in
PPT, but "did it because it was sort of part of a gas pipeline
deal," and he asked Mr. Haymes what rate the company did support
before that deal got cut.
11:02:11 AM
MR. HAYMES answered, "Lower than 20 percent." He said he thinks
the key consideration should be that the resource potential in
Alaska is significant. Only 15 billion barrels of oil have been
produced. According to federal analysis, there is 250 tcf of
gas that is technically recoverable. Alaska's future is not
just the gas, but it is the oil as well. He stated, "When you
put the gas on oil-equivalent barrel basis, there is as much oil
and gas together in the future." He reiterated that the focus
needs to be on both. He continued:
We cannot control the price - the commodity price;
that's the market. We cannot control some of the many
fixed costs in Alaska. As we know, it's very unique
in many respects. Technology will help on that front,
as it has for the industry for many years. The key
lever you have to pull is the fiscal policy, and
that's a key enabler to try and help encourage more
investment, which is needed to really develop the full
resource potential.
11:03:32 AM
REPRESENTATIVE DOOGAN directed attention to page 14 of Mr.
Haymes' statement, to the sentence which read: "Any change in
the fiscal regime has a direct impact on how we view
predictability of the Alaskan fiscal environment, which in turn
directly impacts how we evaluate on a risk basis future
investment decisions." He suggested that Mr. Haymes is really
referring to increases, rather than changes in that sentence.
11:04:16 AM
MR. HAYMES responded that the overall policy needs to be
predictable in order to make investments that take decades to
generate a return and are capital intensive.
11:04:31 AM
REPRESENTATIVE DOOGAN asked, "So, a tax cut would bother you as
much as a tax increase?"
MR. HAYMES said he thinks any industry would be against a tax
cut.
11:04:40 AM
REPRESENTATIVE DOOGAN said the other two major North Slope
producers "shared their profits on their Alaska operations with
us last year." He offered his understanding that ConocoPhillips
Alaska, Inc., had reported $2.3 billion, while BP reported $2.15
billion. He asked Mr. Haymes what ExxonMobil Corporation's
profits were.
11:05:09 AM
MR. HAYMES replied that ExxonMobil Corporation does not report
profits on an Alaskan basis; it reports it on a global basis, in
accordance with its quarterly earnings summaries. He said the
annual report does talk about ExxonMobil Corporation's net oil
production for Alaska, and last year there were 150,000 barrels
per day.
11:05:33 AM
REPRESENTATIVE DAHLSTROM asked Mr. Haymes to comment on the
level of predictability ExxonMobil Corporation would like to see
in order to stay and do business. She said she would also like
to know if a representative of ExxonMobil Corporation such as
Mr. Haymes is currently in Alberta, Canada, "fighting this
fight."
11:06:27 AM
MR. HAYMES said Alberta recognizes the significant challenge of
their oil sands. He offered his understanding that Alberta
ranked at about thirtieth in the world on "proved reserves," and
today it ranks second. Alberta changed its fiscal policy about
15 years ago, and that change spurred a huge economy growth. He
noted that recently there has been a recommendation from a panel
for Alberta to increase its royalties. That recommendation has
not been adopted and is under intense scrutiny and debate.
EnCana Corporation has said that if that policy is implemented,
it would reduce its spending in [Alberta] by $1 billion.
Talisman Energy Inc. and ConocoPhillips Alaska, Inc., have also
said they would reduce its expenditure by half a billion
dollars. Those withdrawals could potentially delay $8 billion
future investments on the oil sands. He said that gives a
picture of how tax increases can affect investment. He said the
focus should be on what is the right policy to develop the full
resource potential of Alaska - to consider how, with Alaska's
unique challenges, the state can replicate what is being done in
Alberta. He said there needs to be a collaboration between the
federal and state government and the industry.
11:09:34 AM
REPRESENTATIVE DAHLSTROM noted that one company had told the
legislature that in the event the existing bill is passed, it
would not pull out from Alaska, but would fulfill its
contractual agreements, although it may need to change some of
its business strategies. She asked Mr. Haymes to comment on
what ExxonMobil Corporation may or may not do.
11:10:14 AM
MR. HAYMES replied that ExxonMobil Corporation has been in
Alaska for 50 years and would not pull out of the state. He
said, "I think it really gets down to: how do you attract an
increasing need of investment to mitigate oil production decline
... an hopefully even increase it."
11:11:30 AM
REPRESENTATIVE RAMRAS spoke of his recent disclosure of his
investment in the ExxonMobil Corporation, and the reaction of
his constituents regarding that disclosure. He noted that
anyone who enjoys receiving the PFD is supporting ExxonMobil
Corporation, because that corporation is the largest single
equity holding in the Alaska Permanent Fund Corporation. He
said the legislature has had an open debate with the
Commissioner Pat Galvin and is in agreement that the state can
benefit from short-term horizon gains in tax revenue over the
next three to four years. He asked what would happen if Alaska
dampens investment opportunities and harvests a surplus in tax
revenue for three or four years. He asked how many places in
which ExxonMobil Corporation is involved. Representative Ramras
stated that there is a difference between being passive and
active in terms of resource development. He remarked that the
legislature's intent in 2006 was to reward activity and to be
punitive toward passive activity of harvesting revenue from the
state and allowing it to migrate to other places in the world.
He asked how long it would take to regain to revamp the capital
should that migration occur.
11:15:37 AM
MR. HAYMES said there is no defined time for how long it would
take, but it would be a long time - at least 12 to 17 years. In
the Alberta example, that province changed its fiscal system and
provided predictability back in 1991, but the boom in Alberta
has only occurred in the last 3 or 4 years. Mr. Haymes said it
takes a long time from discovery to production of oil - easily
decades. He reiterated that Alaska is remote and has
challenges. Technology is needed to reduce the cost and lower
tax rates are necessary in order to encourage more investment.
11:17:37 AM
REPRESENTATIVE NEUMAN referred to testimony of 10/22/07 from a
small investment company. That company explained that Norway
charges a higher tax rate, because it starts taxing after
expenses are covered. He asked Mr. Haymes would not be
disturbed by a higher tax rate if Alaska incorporated that type
of structure.
11:19:25 AM
MR. HAYMES reiterated that ExxonMobil Corporation is looking for
fiscal predictability, and he said there are many different ways
to find that. Every country has a different model. He stressed
the need for a collaborative effort with government and industry
to establish an equitable, workable best-case scenario.
11:20:53 AM
REPRESENTATIVE NEUMAN noted that page 4 of Mr. Haymes' statement
shows that Alaska has 53 billion barrels of oil still
recoverable, but the ranking of its reserves have declined from
fourteenth in 1977 to near thirtieth today. He asked Mr. Haymes
what criteria are used in those rankings.
11:21:59 AM
MR. HAYMES said the definitions used by the Oil and Gas Journal
and Energy Information Administration are based almost solely on
economics, without "significant technical challenge" and without
considering total resource potential. He noted that Canada was
ranked seventeenth and now ranks second. Norway has increased
in ranking, as well.
11:23:36 AM
REPRESENTATIVE NEUMAN asked, "Is that directly proportional to
the amount of known reserves?"
11:23:56 AM
MR. HAYMES said some aspects must be looked at: the resource
potential of the basin, the technical challenges, the cost
challenges, and the fiscal policy that encourages investors to
invest. He stated, "We can learn from others ... but we need to
step back and say what's right for Alaska."
11:24:33 AM
REPRESENTATIVE COGHILL said the tax rate that was chosen last
year was the beginning of the discussion to figure out how the
state can improve its partnership with the industry. He opined
that the investment ExxonMobil Corporation and others have made
under the ELF system was terrible. He noted that there has been
a change to both price and cost environment, and Alaska is
trying to make investment decisions and capture the value of its
resource along the way. He said, "I think you did a much better
job of capturing the value than we did." He said he thinks the
governor is questioning what is a fair share. Representative
Coghill said he is listening intently to find out how Alaska can
get the oil industry to invest through incentives, while still
ensuring the state shares in the value "as it goes out the
door." He stated concern about "the progressivity and the
floor." He said he would rather "see a share on the upside and
go ahead and take the risk on the lower side." He asked Mr.
Haymes to explain "the complexity of the recording."
11:27:05 AM
MR. HAYMES reviewed two aspects which he covered in his previous
statement. One is the 10 percent gross floor and the other is
the ring fencing, which is applied to Prudhoe Bay and Kuparuk
River Unit. The 10 percent floor, he said, adds uncertainty
around the assumed tax rate if the crude price is low, and that
10 percent floor needs to be considered when looking at long-
term investments. Investment decision risk assumes the worst-
case scenarios. He continued:
On the legacy field component of ring fencing costs, I
cannot see how that encourages investments for
anybody. First of all, it is focused on Prudhoe Bay
and Kuparuk, which in itself adds complexity. Adding
complexity and administrative burden makes it tougher
for everybody to try and work out what the joint
venture billings are, what is in that ring fence,
what's not - it's going to create a lot of uncertainty
and a lot more auditing requirements from everybody.
MR. HAYMES said ExxonMobil Corporation recognizes that the
administration is proposing not to use the joint-interest
billings as a starting point for audits, which he said the
corporation finds difficult to understand. He continued:
We, as a "nonoperator" of Kuparuk and Prudhoe Bay,
spend a lot of money and time auditing our joint-
venture billings, as I'm sure any of you would do if
you were a partner in any business. We spend almost
half a million dollars a year and a hundred weeks of
work effort every year auditing our joint-venture
billings, and we believe ... an excellent starting
point for any auditor to look at is: What have the
other auditors done? Audit the audit. And then if
you find gaps, start to look at other information.
MR. HAYMES said the current proposal has a lot of other
complexities that need to be seriously considered and thought
through. He said the acid step is to question whether a
proposal will encourage more investment, simplicity, and
transparency in Alaska.
11:30:30 AM
REPRESENTATIVE COGHILL said the legislature needs to figure out
if "that floor" does that. He offered his understanding that
ExxonMobil Corporation was given the ability to transfer credits
within the ring fence, and he said it will be interesting to
hear from ExxonMobil Corporation and the administration
regarding "what value that really is." He offered his
understanding that progressivity is outside that system. He
concluded, "I'm looking for where ... the levers move to make
that valuable to us and less valuable to you. And I haven't ...
been convinced by either argument yet - ... to me it's an open
question."
11:31:46 AM
MR. HAYMES said DOR's "economic 101 on the fields A, B, C, D,
and E" is narrow in its focus, because it looks at one price and
assumes it's constant. Furthermore, it focuses purely on net
present value. Any investor does not look at just net present
value as a criteria for an investment decision; there are many
factors and ranges of outcomes that need to be considered.
There are variables in resources, costs, and commodity price.
11:32:58 AM
REPRESENTATIVE COGHILL said the claim is that "we will hardly
ever again in history see that lower part truly needed." He
added, "But I also was here when we bounced off of $8 oil, so I
... guess anything can happen."
11:33:34 AM
MR. HAYMES responded, "The DOR's price forecast even assumes
that it's nowhere near what it is today."
11:33:41 AM
CHAIR OLSON asked how much oil and gas is coming from Alaska
compared to ExxonMobil Corporation's total U.S. production.
MR. HAYMES answered the ExxonMobil Corporation produces
approximately 2.2 million barrels of oil a day in the U.S.
Worldwide, he said, Alaska's production represents 3 percent of
the corporation's total production on an oil equivalent basis,
including gas.
11:34:14 AM
REPRESENTATIVE SAMUELS asked if 3 percent of the spending also
takes place in Alaska.
MR. HAYMES said over the last five years, ExxonMobil Corporation
has invested over $25 billion on projects throughout the U.S.
In response to a follow-up question from Representative Samuels,
he said the corporation has spent $280 billion. Last year, he
noted, ExxonMobil Corporation invested $20 billion worldwide and
the industry invested approximately $2 to $2.5 million in Alaska
in that year.
REPRESENTATIVE SAMUELS calculated: "For simplicity I'm going to
say it's 2.4 divided by 3, so you invested $800 million, maybe a
little less. Okay, thank you."
11:35:37 AM
CHAIR OLSON recessed the House Special Committee on Oil and Gas
meeting until 1:30 p.m.
CHAIR OLSON reconvened the House Special Committee on Oil and
Gas meeting back to order at 1:41:12 PM.
1:41:23 PM
JOHN P. ZAGER, General Manager, Alaska, Chevron, offered a 12-
slide PowerPoint presentation. He highlighted slide 2, which
read as follows [original punctuation provided]:
Chevron's Alaska Presence
th
‡ 4 largest producer in state
rd
‡ 3 largest operator
‡ ~500 employees or full time contractors
„>300 on the Kenai Peninsula
‡ Chevron is the only producer in the state with a
relative balance of assets in the Cook Inlet and on
the North Slope
„Cook Inlet production - 23M BOPD
zOld oil production, very high lifting cost
„North Slope production - 15M BOPD
„In early stages of increased capital program
zExtend life of Cook Inlet O&G production
zNorth Slope exploration on state lands
zInvestment decisions made under PPT
MR. ZAGER noted that where slide 2 shows 23 million barrels of
Oil per day (BOPD), it should actually read BOEPD, for barrels
of oil equivalent per day, because about two-thirds of that
volume is actually gas. In its heyday, he said, Cook Inlet
produced 200,000 - 220,000 barrels a day gross, and now it is
down to 15,000 - 16,000 barrels a day gross. Now what is being
lifted is more than 90 percent water. Regarding the early stages
of the increased capital program, he said extension of Cook
Inlet oil and gas production would be very economically
challenging without the current high price of oil. He said some
of Chevron's platforms have direct lifting costs - platform-
related costs that do not include overhead or indirect expenses
- in excess of $40 a barrel.
MR. ZAGER said Chevron will have a rig ready to operate to begin
a drilling program in Cook Inlet. On the North Slope, he noted,
Chevron has accumulated a large exploration position in the
White Hills area in which it will begin drilling in December for
two years. Chevron has operated a well on the North Slope since
the early 90s.
1:45:59 PM
MR. ZAGER directed attention to slide 3 of the PowerPoint, which
shows Chevron's Capital Investment - its spending profile - from
2006 projected through 2009. The graph shows an anticipated
increase from $80 to $400 million in spending. He said a second
rig would be added in 2009.
1:46:59 PM
MR. ZAGER moved on to slide 4, which read as follows [original
punctuation provided]:
Chevron is increasing investment under PPT
Introductory Comments
‡ We do have a common enemy - decline
‡ Disappointing to be back so soon after passage of PPT
„Lack of actual PPT results to revise tax policy
„Review scheduled for 2011
„Too soon for a change
‡ Need to strike a balance between tax rate and
investment climate
MR. ZAGER said he doesn't see the evidence to support the theme
that PPT is "broken." He said it is too early to make that
determination. Regarding the review scheduled for 2011, he
said:
Quite frankly, that doesn't give me a lot of comfort.
Sitting here today, you can see the kind of
expenditures we've got going. If White Hills ... is
successful, that would mean probably, on a normal time
line, some time around 2010, we would be ...
commissioning the actual development, which means you
go from spending $200 million to potentially billions
or more dollars. So, knowing that there's a reopener
in 2011 is concerning, because, ... when we run our
risk and our distributions, and all the things that
could happen, one of the things is that state taxes
could go up in 2011. And it's been said, "Well, you
guys have been put on fair notice if that's going to
happen." And that's true, but it ... doesn't help me
right now to make the decision or make a commitment to
that point. It won't help me in 2009; it won't help
me in 2010.
1:49:47 PM
REPRESENTATIVE NEUMAN indicated that the state's oil economists
had discussed the subject of stability and had said they did not
feel the review scheduled for 2011 would cause insecurity in the
industry, because that date allowed warning and time for
preparation, and upon hearing that, he had thought it was a good
policy. He said he would like Mr. Zager to respond to that, and
also to tell the committee what Chevron's "actual" was when
looking at capital investments. He thanked Mr. Zager for
Chevron's investments in the Cook Inlet area.
1:51:11 PM
MR. ZAGER responded that knowing what is coming in 2011 allows
Chevron to plan for that contingency, model it into its
valuations as best as is possible, and plan its development
accordingly.
1:52:36 PM
REPRESENTATIVE NEUMAN asked Mr. Zager if he foresees Chevron
changing its investment plan should ACES be adopted.
MR. ZAGER offered a two-part answer: First, he said, it would
be unlikely that Chevron would halt its North Slope program
midstream. He said a big part of the cost in Cook Inlet is
getting the infrastructure ready to drill and getting a drill
rig that's capable of drilling. He said the rigs that have been
out in Cook Inlet have been many years out of use and in
disrepair, and bringing them back "is a big front-end loading."
He continued:
To the extent we haven't made commitments going
forward, then certainly we would change our economic
model [to] reflect ACES. And the effect it will have
is it will lower the returns on those projects, and
they will get lower in the queue of projects that we
fund. ... We're part of the mid-continent and Alaska
business unit, which is part of the Chevron North
America, so, that's mostly the world we're competing
in for developing capital .... Exploration capital is
competing more on a heads-up basis across the world.
1:54:21 PM
CHAIR OLSON said virtually all the arguments that he has heard
revolve around not getting a fair share and make comparisons to
other countries, but he said he has heard no comparisons to
other places in the U.S. He asked if Chevron is doing business
in other states and what tax plan do the other states employ.
1:55:07 PM
MR. ZAGER said he has spent most of his time worrying about
Alaska's tax rather than analyzing other states.
Notwithstanding that, he offered his understanding that the tax
in places like Texas is "extremely stable." He added, "There
are things going on in some states, but I don't think anything
in the magnitude that we're talking about here."
CHAIR OLSON asked, "Not the frequency?"
MR. ZAGER answered, "Not that I'm aware of." He emphasized the
importance of finding the balance between the state's needs and
that of the industry.
1:56:19 PM
REPRESENTATIVE DOOGAN said the legislature has heard that
sentiment from everybody who has testified, including the
administration. He asked Mr. Zager how he recommends measuring
the investment climate.
1:57:32 PM
MR. ZAGER replied that Alaska needs to figure out what product
it is leasing and what value it has in the market. He said he
would be providing further details later on in the PowerPoint.
1:58:22 PM
MR. ZAGER directed attention to slide 5 of the PowerPoint, which
read as follows [original punctuation provided]:
Factors that affect investment decisions
„Corporations have a responsibility to operate safely,
seek returns, and increase shareholder value
„Corporate Cash Flow Management
zCorporate uses of cash:
fOperating Costs
fInvestment: upstream, downstream, technology,
acquisitions
fPay down debt, build cash
fPay dividends to shareholders
fBuy back stock
MR. ZAGER said operating costs include salaries to employees and
utilities. Regarding acquisitions, Mr. Zager explained that it
is always an option to buy a company and get the reserves than
to drill for that company. Chevron, he relayed, is one of the
bigger investors amongst its peer group. For the last five
years, Chevron has consistently reinvested 100 percent of its
earnings and has the largest exploration budget worldwide of any
of the producers in Alaska. Its total capital expenditures are
- relative to the company's size - second only to Shell.
2:01:45 PM
MR. ZAGER, in response to a question from Representative Neuman,
said Chevron does not provide segmented earnings and cash flow
in its reporting for Alaska. However, he estimated that Chevron
has been investing between 50-100 percent of its earnings or
cash flow from Alaska. He said the trajectory is up, and at
some point, Chevron would be a net investor in Alaska.
2:02:35 PM
MR. ZAGER returned to the PowerPoint. Because of the present
value of oil, he said, most companies have strong balance sheets
at present - possibly even a net cash position. He said
companies don't want to be too cash positive, because their
shareholders are not paying them to be a bank but to invest
money. He said paying dividends to shareholders is a well-
received use for large companies' cash. Buying back stock, he
said, is another way of "returning a little bit of value to the
shareholders." He explained that buying back stock differs from
increasing dividends in that it is not necessarily a recurring
event.
2:04:00 PM
MR. ZAGER moved on to slide 6 of the PowerPoint, which read as
follows [original punctuation provided]:
Upstream Investment Decisions
‡ Always more opportunities than can be funded or
staffed
‡ Key Factors - How do Alaska state lands stack up?
„Rocks - What is the reserve and production potential?
„Cost - How much will it cost to find, develop, and
produce?
„Time - How long will it take to realize revenue?
„Risk - What is the probability of success?
„Fiscal regime - How much revenue does the investor get
to keep?
‡ Economic models are developed, opportunities ranked,
and investment decisions are made on an After-Tax Net
Present Value (NPV) basis
„Does the investor get enough to justify the
investment?
zGreat rocks can trump poor fiscal terms
MR. ZAGER said Alaska ranks high in its distribution of rocks,
especially at Prudhoe Bay; however, most of the exploration and
new money is not going for Prudhoe Bay light oil, but is going
to viscous oil and new exploration. The new exploration
prospects in Alaska, he indicated, are middle of the road, in
terms of potential.
2:07:23 PM
MR. ZAGER said the cost to find, develop, and produce is high -
probably in the top quartile. Regarding time to realize oil
revenue, he said, "The longer it takes, the less valuable it
is." He estimated time periods of 2-10 years to get production
on line in Alaska. He named the following risks: geological,
price - which would be common around the world, and permitting
or other unanticipated delays that can affect decisions.
Regarding fiscal regime, he offered an analogy to put across the
point that "it's all about what you put in and what you get out
at the end of the day." He said he doesn't know how Alaska
could compare its product to any other country's product,
because it is not the same.
2:10:31 PM
MR. ZAGER said some of the key factors listed on slide 6 are
more controllable than others. Rocks, for example, are not
controllable. He stated, "But the biggest driver that the state
really has just about 100 percent control on is the fiscal
regime, which is the final thing that would be included."
Changing the taxes, he said, will change the relative valuation
and where opportunities will fall in line relative to other
opportunities in North America or worldwide. Mr. Zager talked
about justifying investment to risk. He said getting access to
oil in Alaska is one of the best factors of doing business in
the state. "Everything after that is when you've ... got the
issues," he remarked.
2:13:28 PM
MR. ZAGER directed attention to slide 7 of the PowerPoint, which
shows with a chart how attractive Alaska is as an investment.
The line above the chart read: "Let's look at results of recent
lease sales as a scorecard: This is industry voting with their
dollars." Referring to the chart, he explained:
So, what I've done is ... taken bonus bids on Alaska
state lands and compared them to Gulf of Mexico
areawide lease sales since 2002. These are the same
investors that Alaska should be attracting; they're
mostly ... either the super majors or large
independents that have the wherewithal to play in the
off-shore gulf or the deep water - the same type of
players that would be playing on the North Slope of
Alaska.
MR. ZAGER said the chart shows that the ratio showing lease
sales for the Gulf of Mexico versus Alaska is 72:1.
2:15:10 PM
REPRESENTATIVE DOOGAN asked Mr. Zager to compare both the Gulf
of Mexico and Alaska against the list of factors from slide 6,
beginning with rocks.
2:15:26 PM
MR. ZAGER offered his understanding that the rocks are better in
the Gulf of Mexico, cost in both places is high, time in both
places is similar, and the fiscal regime is better in the Gulf
of Mexico. He said he does not have an answer pertaining to
risk.
2:18:13 PM
MR. ZAGER stated that the point is that there are competitors
around the world that are marketing their resources. He
mentioned Libya as an example of a place that has onerous fiscal
terms but is still attracting bidders. He said, "So, it must
tell you something's different than it is here."
2:19:06 PM
MR. ZAGER highlighted figures on slides 8 and 9, entitled,
"Exploration - How taxing the upside can deter investment
decision." The slides show four-point economic models,
including after-tax (ATAX) net present value (NPV), probability
of success (POS), and probability of failure (POV). He stated,
"This is a simplistic way of actually approximating the actual
distribution which would be ... a law of normal distribution of
possible outcomes." He explained the math behind POS and said,
"To decide whether to drill, you simply add the probabilities
and values together." Mr. Zager showed numbers on the slides
that prove the point: "Taxing and taking away the upside does
affect decisions today."
2:24:52 PM
MR. ZAGER, in response to a question from Representative Doogan,
said he chose the 15 percent POS and 85 percent POF amounts for
the example on slides 8 and 9 because he thought they would be
fair. In response to a follow-up question, he confirmed that
those numbers would be based on more information in a real life
situation, because that's what geologists and geophysicists are
paid to figure out. He added, "If we can convince ourselves
that that POS is actually 20 percent instead of 15, then it's a
better investment decision."
2:25:56 PM
REPRESENTATIVE NEUMAN asked Mr. Zager what the limits are on
exploration days in Alaska and how those limits may affect
Chevron's decisions.
2:27:07 PM
MR. ZAGER said the crew in the North Slope is restricted by a
drilling window from December to April or May. In contrast to
that, drilling in the Gulf of Mexico can occur 365 days a year.
In response to a question from Representative Neuman, he
surmised that Norway, with its off-shore drilling, can also
operate year round.
2:28:33 PM
MR. ZAGER moved on to slide 10 of the PowerPoint, which shows:
"Investment is Needed to Maintain Production at Reasonable
Levels." Slide 10, he said, is a simplistic spread sheet
illustrating an "Alaska Production Forecast Estimate." The blue
line on the spread sheet shows the current production at a 6
percent decline. The red and green lines show the results of an
assumption of $15 a barrel finding & development costs (F&D) and
a $1 billion or $2 billion annual additional investment. The
other assumption made, he said, is that there are enough
projects going on to continue at least until the year 2027.
The committee took an at-ease from 2:30:20 PM to 2:33:55 PM to
address technical difficulty.
2:34:06 PM
MR. ZAGER returned to slide 10 and said it shows that "we need
to attract significantly more investment."
2:34:24 PM
REPRESENTATIVE NEUMAN said if investment stays the same, when a
pipeline is built in 10-12 years there will be half the amount
of oil coming down the pipeline. That's assuming that $15 is
"the same $15 10 years from now as it is today," he said. He
said that really grabs his attention.
2:35:21 PM
MR. ZAGER responded that is correct. He said, "So, whatever the
[$15] is now, it certainly could ... mean we need to attract
more capital in nominal dollars in future years to get the same
amount of work done."
2:35:54 PM
REPRESENTATIVE DOOGAN asked, "You've just taken that $15 a
barrel and divided it into a billion and tracked the result in
production on that line there?"
2:36:07 PM
MR. ZAGER responded:
In a nutshell, yes. It's a little more sophisticated
than that in that I made some assumptions about the
timing of that incremental investment. In other
words, you don't spend a dollar a day and get all
those barrels. And that's why you see this inflection
a little bit here. But once it gets out here where
these are happening constantly, then it's a straight
line again.
2:36:33 PM
REPRESENTATIVE RAMRAS mentioned an editorial in the October 2
Anchorage Daily News. He said, "It seemed that the premise was
if we're ... at ... 22.5 and 20 [percent], what are we even
getting of the 20? Why don't we just keep the 20? ... $600
million was the number they referenced, and they said over 5
years, the $600 million invested, plus the interest income would
be about $4.5 billion. That was the premise of the editorial is
what are we getting for the money; we should just keep it all
and keep the $4.5 billion dollars in our account over the next
five years." That said, Representative Ramras asked, "What do
we get for the green line versus the blue line? He requested a
hypothetical response.
2:40:09 PM
MR. ZAGER said the spread sheet shows that in ten years, in the
year 2017, Alaska would get royalties and taxes on approximately
100,000 barrels a day. He said he has not done the math to
compare a "take it now and bank it" philosophy versus the
financial benefit of the spread sheet from the state's
perspective.
REPRESENTATIVE RAMRAS recommended members read the
aforementioned editorial, because it is a fascinating reframing
of the argument.
2:41:03 PM
MR. ZAGER returned to his PowerPoint, to slide 11, which is
labeled: "Chart 14 - Fiscal Attractiveness Rating versus Fiscal
Stability Rating." He noted that this chart is from the Wood
Mackenzie Government Take Study of 2007 and is somewhat
controversial. He explained that the chart shows fiscal
security on its vertical axis and fiscal attractiveness on the
horizontal access. He said his focus would be on the latter.
Alaska, he pointed out, falls at the middle of the fiscal
attractiveness axis. Those countries listed to the left are
less attractive fiscally. What they have in common is: they
are mostly in the Middle East, they are sitting on "world class
rocks," many are members of OPEC, and many have their own
national oil companies. Developing their reserves is not
necessarily something they need or want, but the rocks are so
good they can either set a price and let people take it, or open
it up and let people bid. He added, "And people will bid it up
to the point where they're in that regime, because the pie is so
big, there's still enough left to justify their investments."
MR. ZAGER drew attention to the countries listed on the right of
the chart. Most of those countries, he noted, are "oil patch
wannabes" - they have less than 1 billion barrels. In order to
attract people to invest, those countries are willing to offer
the best fiscal terms in the world. He reiterated that Alaska
falls in the middle of the chart. He mentioned the data point
from the U.S. He said, "You can argue that industry voluntarily
moved themselves to the left. ... The terms and the rocks
created enough value that we as industry wanted in that play
enough to put $2.9 billion on the table right up front." Using
an analogy, he questioned trying to sell a Chevrolet as if it
were a Cadillac and simultaneously attracting more investment.
He concluded:
You just kind of got to wonder when you ... look at
this from a high level. People who want to attract
more investment are on the right. People who have ...
a lot of companies coming to their door are either on
the right or they're over here and they can, quite
frankly, afford to turn companies away or only have
people that will deal specifically on whatever terms
they offer.
2:45:53 PM
REPRESENTATIVE RAMRAS asked if that is not exactly the
discussion that the legislature is having, that some people
think that a change shifts the "U.S.A. Alaska diamond"
significantly while the administration thinks the change "just
shifts the diamond a sliver."
2:46:27 PM
MR. ZAGER replied that he thinks that is correct. He said this
morning he was asked where Alaska was before PPT came into place
or before ELF. He indicated that it would have shown in an
upper quadrant of the chart that showed it to be much more
stable and more favorable on taxes." He continued:
Interestingly enough, you know, this is a confidential
piece of work, and I want to just be clear that we got
permission from Wood Mackenzie to share this with you
today. But we also asked them, "Could you take a look
at ACES and plot a new diamond would be if ACES
passes?" They declined to do that. ... It would be
an interesting piece of data, and ... I don't expect
it's going to move it over here, for sure. But the
question is, even directionally, is that the way to be
moving if we want to attract more investment? A
little bit, you know. Where's the straw that breaks
the camel's back?
2:47:30 PM
REPRESENTATIVE RAMRAS speculated on what would happen should the
premier of Alberta sign the Alberta fair share agreement.
2:47:54 PM
MR. ZAGER said certainly if Alberta lowers its fiscal stability
while raising its taxes, the diamond showing its place on the
chart would appear somewhere in the lower-left quadrant of the
chart.
2:48:15 PM
REPRESENTATIVE DOOGAN asked, "Don't I look at this chart and
think that my government is selling Cadillacs in the Gulf of
Mexico at sort of Yugo prices here? Isn't that what I take away
from this display? I mean, they're cheaper than Chevies,
because they're over to the right, but they're better cars, too,
'cause..."
2:48:41 PM
MR. ZAGER said a person could reach that conclusion, and he said
he is not here to argue about any aspect of this. He said he
hopes his data is somewhat objective. He stated his view of the
industry as extremely competitive in terms of gaining access to
opportunities. He continued:
You've probably heard people say that internationally
it's becoming more difficult to gain access to many
areas of the world. And so, when an opportunity comes
up, you've got to capture it if you think it's high
quality .... So, industry ... voluntarily moved
themselves to the left, by putting $2.9 billion up
front. And you all know up front costs are going to
hit your [market percentage value (MPV)] more than
anything. [Industry] moved it to the left, because of
the opportunities and because of the fiscal terms.
2:50:01 PM
MR. ZAGER turned to slide 12 of the PowerPoint, which read as
follows [original punctuation provided]:
Summary Comments
‡ You have the power to increase short term state
revenue through raising taxes
‡ Energy companies have the responsibility to invest
where they see the best risk/reward ratio
‡ The common enemy is decline,
‡ Investment is the only way to stem decline
‡ How do you price Alaska's product ?
„Lowest possible taxes and stability will encourage
investment
‡ Chevron intends to invest and grow in Alaska, but
ACES makes investing in Alaska more difficult
MR. ZAGER, regarding taxes, said it is debatable what will
happen ten years out. He stated, "Assuming there aren't more
tax changes, it's not controllable by the state completely, in
terms of what the production level will be." Mr. Zager said he
has heard people say that oil companies are threatening to
withhold investment from Alaska. He emphasized that from the
perspective of Chevron, nothing could be further from the truth.
He explained, "We're simply trying to convey the economic
reality that increasing taxes will make Alaska investments less
attractive." He stated:
My job is still to try to gain as much funding for
Alaska as possible to keep my 500 employees fruitfully
working. It's just that the job would be that much
... more difficult when we're trying to stack Alaska
up against other opportunities either in the U.S. or
worldwide.
The committee took an at-ease from 2:52:21 PM to 3:02:58 PM.
3:03:06 PM
PAT FOLEY, Manager, Lands and External Affairs, Pioneer Natural
Resources Alaska, Inc. ("Pioneer"), introduced Mr. Sheffield and
said his presentation would: serve to reintroduce Pioneer as a
corporate entity; familiarize the committee with Pioneer's
process in making capital investment decisions, what other
projects within the company compete for its capital, and where
Alaska might fall within that list; share a project update on
Oooguruk; and conclude with specific comments on PPT and ACES.
He stated that the bottom line is to ask the legislature to
"resist the temptation to make any negative changes that would
make the fiscal environment less attractive to a new investor."
He deferred to Mr. Sheffield to offer the PowerPoint
presentation.
KEN SHEFFIELD, President, Pioneer Natural Resources Alaska, Inc.
("Pioneer"), showed slide 2 of the PowerPoint and offered some
background on Pioneer, noting that although the company has no
production in Alaska as of yet, it is new and growing. The bulk
of Pioneer's business is in Texas, Colorado, and Kansas. It
also maintains a natural gas business in South Africa, and an
oil business in Tunisia. In 2006, Pioneer employed 1,600 people
worldwide, produced approximately 100,000 barrels of oil
equivalent a day. Other than size, he said, one difference
between the major companies and Pioneer is that over 90 percent
of Pioneer's assets are in North America.
3:06:07 PM
MR. SHEFFIELD related the points from slide 3, regarding Pioneer
capital investment decisions. He stated that investment
opportunities "compete for budget dollars." He said Pioneer and
most independent companies prefer projects in the Lower 48,
because those projects are closer to the company's
infrastructure, are closer to services, and are not
geographically challenged, which results in lower risk, lower
cost, and shorter cycle times. That gives the company a
significant amount of flexibility, he explained. Mr. Sheffield
said Pioneer looks for projects that will give the company 10
percent annual production growth, will guarantee at least 100
percent - if not more - reserve replacement, offer as low a
finding and development cost as possible, and meet certain
economic and financial metrics, such as internal rate of return
and discounted return on investment. Pioneer also considers
project economics over a broad range of potential outcomes, as
well as based upon a variety of "price calls." He said out of
all the projects Pioneer is considering for 2008, about 75
percent of them will be funded; those that don't get funded will
be deferred if possible.
3:09:38 PM
MR. SHEFFIELD referred to slide 4, regarding competition for
Pioneer Capital. He stated that rising commodity prices have
improved the outlook for oil and gas investments worldwide.
Rising costs have taken a bite out of those margins, but those
margins have increased nonetheless. He said one trend is to see
budget dollars flow to low risk resource plays, including tight
sand investments, coal bed methane projects, and shale gas. He
explained the reason for this trend is that with the higher
commodity prices, corporations can meet their objectives without
having to take "the higher risk." Mr. Sheffield listed the low
risk, short cycle projects: oil drilling in West Texas, gas
drilling in South Texas, and gas drilling in Colorado. He noted
that Pioneer is also "competing against" a growing gas business
in South Africa and a growing oil business in Tunisia.
Furthermore, he said, Pioneer has a business development group
looking for new opportunities, primarily in the Lower 48.
3:12:52 PM
MR. SHEFFIELD mentioned that he has heard Alaska's "take" is in
"the mid-60s range." In response to Chair Olson, he said the
average take in the Lower 48 is in "the mid-40s."
3:13:07 PM
CHAIR OLSON asked, "So, ... the ... bill that's in front of us
would be significantly higher: 20 points?"
3:13:12 PM
MR. SHEFFIELD answered that's correct.
3:13:26 PM
MR. SHEFFIELD directed attention to slide 5, regarding Pioneer's
Alaska entry. He said that five years ago, the company put
together a SWOT analysis, which stands for "strengths,
weaknesses, opportunities, and threats." The strengths listed
for Alaska are its prolific petroleum system, high impact
opportunities, its location in North America, and the ELF policy
and available exploration incentive credits (EICs). The
opportunities that Pioneer noted are that business opportunities
are opening for independent investors, while the weaknesses are
that operations and transport costs would be high, the project
cycle times would be longer, and the regulatory processes would
be complex, although workable. The threats perceived by Pioneer
regarding entry into Alaska include the possibility of the tax
policy changing, and the project delays or cost overruns
resulting from working in a remote Arctic environment.
MR. SHEFFIELD said Pioneer still thinks Alaska has a great
petroleum system, but it has been disappointed in the reservoirs
it has encountered through its drilling. He explained that
those reservoirs have been found to be of lower quality than
expected. Furthermore, he said, the company has found that
conducting business in the state is a little more time consuming
and challenging than expected. The regulatory processes are
complex. Actual costs have been much higher than anticipated,
he noted. He said Pioneer is about half way through its
Oooguruk project - ending the construction phase and about to
embark on the drilling phase - and, to date, is approximately 25
percent over on its capital expenditures, which translates into
about $70 million over budget. He said Pioneer participated in
approximately 11 exploration wells in the last five years, and
almost all of them have run at least a third over predicted
budget. He stated that the tax policy was uncertain five years
ago and still is uncertain today.
3:18:08 PM
MR. SHEFFIELD, in response to Representative Neuman, offered his
understanding that the structure of the EICs five years ago is
similar to what is in the existing PPT law. He deferred to Mr.
Foley for further comment.
3:18:43 PM
MR. FOLEY confirmed that Mr. Sheffield's statement is correct.
He expounded:
Under ACEs, under PPT, all it really does is preserve
the existing EIC program, and that system ... allows
an explorer to take a credit of 20 percent for
drilling an exploration well if it's three miles away
from any other well. And they can take an additional
20 percent, for a total of 40, if the well is much
more remote. And there are also credits available for
a seismic program, which I believe also are 40
percent.
3:19:27 PM
MR. FOLEY, in response to a question from Representative Neuman,
said Pioneer has a single project that it is currently pursuing
in Cook Inlet, which is called the Cosmopolitan Project, and it
is offshore from Anchor Point. In response to a comment from
Chair Olson, he confirmed that it is "a potentially significant
project."
3:19:51 PM
REPRESENTATIVE NEUMAN offered his understanding that the
investment credits there are different from the rest of the
state.
3:20:00 PM
REPRESENTATIVE DOOGAN, regarding investment credits, asked if
Pioneer's work on the slope qualified for the 40 percent
[credit].
3:20:22 PM
MR. FOLEY responded that Pioneer has participated in several
exploration wells on the North Slope, and the credits have
varied from 20 to 40 percent.
3:20:49 PM
REPRESENTATIVE DOOGAN asked if the Alaskan EICs are the only tax
credits that are available, or if the federal government gives
credits, as well.
3:21:02 PM
MR. FOLEY responded that he is not aware of any other credits
that "we" receive from the federal government.
3:21:20 PM
MR. SHEFFIELD returned to the PowerPoint, to slide 6, which
highlights the Pioneer Alaska profile. He said Pioneer entered
Alaska in 2002 and began its Oooguruk project. The company
became the Cosmopolitan unit operator, he noted, and that unit
is drilling just over one mile and deep and three miles under
Cook Inlet. He said Pioneer made its first investment in this
known oil discovery back in 2005 and, in the last two years, has
taken over as operator and increased its interest to 100
percent. He stated, "We upped the ante on this project, based
upon PPT law, and we believe that maintenance of the PPT
structure is critical to the viability of this technically and
economically challenged project."
MR. SHEFFIELD said in addition to Cosmopolitan, Pioneer also
owns interest in about 1.5 million acres - some of it in and
around Prudhoe Bay and Kuparuk River Unit, and some of it out in
NPR-A. He said Pioneer has participated in 11 exploration
wells, and other than identifying the resource at Oooguruk, the
company really doesn't have much to show for those investments.
3:23:48 PM
MR. SHEFFIELD, in response to a question from Representative
Neuman, explained that low quality rock was discovered at
Cosmopolitan in the late 1960s, and Pioneer is investing in
determining the extent and productivity of the resource there,
so that it can make an educated decision on whether or not to
move forward.
3:24:24 PM
MR. SHEFFIELD moved on to slides 7 and 8, which offer a summary
of the Oooguruk project. He continued:
As you can see in the aerial photo, our Oooguruk
project is nearing the end of the construction phase,
and we anticipate spudding the first of approximately
40 development wells next month. Oooguruk is the
largest single capital project in our company's
history; we are the operator with a 70 percent working
interest in a project that will cost over half a
billion dollars. First production is anticipated in
2008, and peak flow rates are expected in the 2010
timeframe at approximately 15-20,000 barrels per day.
We've come a long way and faced many challenges to get
to the point where we can start drilling. From our
first well in early 2003, we evaluated and sanctioned
a major off-shore project in the Arctic in less than
three years. We permitted a complex project with a
diverse group of government agencies and stakeholders.
In 2006, we constructed an armor to Gravel Island,
installed a complex, sub-C flow line bundle, and
fabricated and installed facilities in a remote,
logistically challenged setting. At peak of
construction, we had over 600 workers up on the slope,
and if you look over the last couple years, we
probably averaged over 400 workers on the [North]
Slope. We are now poised to begin a three-year
develop drilling program, and we are looking forward
to first oil in 2008.
3:26:08 PM
MR. SHEFFIELD talked about the benefits that the Oooguruk
project will generate, as shown on slide 9. He said Pioneer is
poised to be the first independent oil producer on the North
Slope, as well as the first independent to gain facility access
into one of the major units. Other investors, he said, are
watching to see if Pioneer is successful. The tangible benefits
of the Oooguruk project to the state of Alaska would be from the
royalty plus 30 percent of the net profits tax, PPT revenues on
Pioneer profits, state income tax, property taxes to the
borough, jobs in construction and operating, and the profits
that will be generated through those expenditures.
3:27:25 PM
MR. SHEFFIELD moved on to slide 10, which lists the Oooguruk
capital expenditure beneficiaries - the major contractors on the
project.
3:27:50 PM
REPRESENTATIVE SAMUELS asked if the lease under which Pioneer is
operating is still owned by ConocoPhillips Alaska, Inc.
3:28:24 PM
MR. FOLEY offered a brief history, noting in conclusion that the
leases have been assigned from ConocoPhillips Alaska, Inc., to
Pioneer.
3:29:02 PM
REPRESENTATIVE SAMUELS asked Mr. Foley if it would be fair to
say, "It was worth your risk; it was not worth their risk."
3:29:24 PM
MR. FOLEY said he can only speak from Pioneer's perspective,
which is that it was worth the risk.
3:29:35 PM
REPRESENTATIVE SAMUELS said if he makes the assumption that
ConocoPhillips Alaska, Inc., chose not to develop that area
because it was not worth a big company's risk, then if Pioneer
had not picked it up, that oil would still be sitting under
ground.
3:30:16 PM
MR. SHEFFIELD responded that Pioneer drilled the three
exploration wells and made "a completion in the Jurassic
formation," and the results of the test gave the company
encouragement that the long-known resource could potentially be
economic. Therefore, the work that Pioneer did actually
improved the knowledge base on that resource. At that point in
time, he said, Pioneer was looking for a sizeable development
project to help in meeting its corporate return, so it made
sense to "kind of take that next step."
3:31:23 PM
MR. SHEFFIELD, in response to a question from Representative
Samuels, estimated that the difference in market cap is in the
range of 20 fold.
REPRESENTATIVE SAMUELS said, "So, they're 20 times as large as
you are."
3:31:36 PM
REPRESENTATIVE DAHLSTROM asked if it would be accurate to say
that it was insinuated that all the companies saw the same
seismic activity.
3:31:52 PM
MR. SHEFFIELD said all companies had similar databases. He
stated:
I don't think that specifically that the seismic data
was the driver. It was a known resource; wells had
penetrated this horizon before. I think that through
the completion that Pioneer did on one of our wells -
and we actually tested the well - it kind of gave us a
little bit of encouragement that this whole ...
resource that had been known for some time - that we
might be able to take it to the next level with new
technology.
3:32:33 PM
MR. SHEFFIELD returned to the PowerPoint, to slide 11, which
addresses Pioneer's view on PPT. He stated that PPT was "rolled
out" without Pioneer's consultation. When the bill was released
in early 2006, he said, Pioneer was already committed to the
Oooguruk project and already had significant exploration
commitments, both in the Central Slope and in NPR-A. After
seeing the tax rates go up from zero to over 20 percent, he
noted, Pioneer took time to work through PPT mechanics and found
it to be a balanced system where investment tax credits help
offset the tax rate. He stated that Pioneer finds PPT to be a
modest incentive for additional investment; it encourages the
development of the abundant lower tier resources in Alaska. Mr.
Sheffield said, "We feel that some of the lower ... quality
reservoirs are a big part of Alaska's resource future, whether
they be challenged by size, or reservoir quality, viscosity, or
just the fact that they're not close to infrastructure." He
said Pioneer also believes that PPT is fair and sustainable over
a broad range of investments. He added, "We think PPT, over
time, should grow the pie and give the state a bigger slice."
3:34:51 PM
MR. SHEFFIELD highlighted slide 12, which addresses Pioneer's
belief that ACES erodes modest PPT incentives. He explained,
"It's really not any one thing, but the cumulative effect of the
changes." Two changes that are negative for the investor, he
said, are the base tax rate increase from 22.5 percent to 25
percent and the tax rate increase through a more aggressive
progressivity formula. Regarding the next negative factor
listed - transitional investment expenditures (TIE credits)
eliminated - Mr. Sheffield said Pioneer's position on that has
possibly changed in the last 24 hours. He explained:
Our interpretation of ACES would be that we wouldn't
be able to recover that $100 million - the credits
related to the $100 million that we spent on the
Oooguruk project. But our ... tax person has been
visiting with some tax folks from the administration,
and we now believe that because Pioneer has been ...
spending so much money, we ... do believe that since
PPT effective date to the end of 2007, that Pioneer
will have spent 2:1 on that sunk $100 million
investment. And we believe - although we still would
like some clarification - that we will be able to
ultimately recover those TIE credits that we've
earned.
3:36:06 PM
REPRESENTATIVE DOOGAN asked Mr. Sheffield to confirm whether or
not Pioneer would return to saying that ACES has a negative
impact if it had a retroactive effective date.
3:36:24 PM
MR. SHEFFIELD replied:
What I'm saying is our interpretation of the way the
ACES bill is written today, with some verification, we
believe that maybe we've already earned those, and
they'll be available to us in the future. Twenty-four
hours ago, our interpretation was that we would lose
all those credits, even though we've been aggressively
spending 2:1 on the capital that we spent prior to the
effective date.
3:37:04 PM
REPRESENTATIVE NEUMAN said some people would argue that TIE
credits give away Alaska's money, and that sentiment concerns
him. He questioned what would have happened regarding Oooguruk
if that $100 million had not been there for Pioneer. He asked
Mr. Sheffield to comment.
3:38:26 PM
MR. SHEFFIELD said the issue for Pioneer is that it sanctioned
the Oooguruk project under ELF and spent quite a bit of money
prior to the implementation of PPT - about $100 million. Now,
instead of being taxed at the ELF rate, any profits made will be
taxed at the PPT rate. The PPT legislation, he said, set up a
framework for Pioneer to earn "that sunk capital," and Pioneer
"stepped up to the plate and earned that back by spending 2:1 on
our sunk capital."
3:39:21 PM
REPRESENTATIVE NEUMAN proffered:
And that's why, in ... Pioneer's view of PPT that you
felt it's sustainable and fair across a broad range of
investments.
MR. SHEFFIELD answered yes.
REPRESENTATIVE NEUMAN added, "And without that, you probably
wouldn't have had that sentence in there?"
3:39:46 PM
MR. SHEFFIELD admitted that the issue is confusing. He said
Pioneer has been following the capital rules created for the
transition from ELF to PPT and wants to make certain that "we're
kept whole when we've lived up to our end of the bargain."
3:40:18 PM
REPRESENTATIVE NEUMAN said every oil company, large or small,
has said it does not like the spread of earned tax credits over
a two-year period. He asked Mr. Sheffield to explain.
MR. SHEFFIELD explained that a credit that can be cashed in
today is worth more than one that can be cashed in next year.
He characterized the issue as significant, but not huge. In
response to a question from Representative Neuman, he said he
can understand why a smaller company than Pioneer may more
strongly object to [the two-year spread of tax credits].
3:42:04 PM
REPRESENTATIVE HOLMES directed attention to slide 9 and the
mention of royalty plus 30 percent net profits to the state of
Alaska, and she asked Mr. Sheffield to explain the 30 percent.
3:42:33 PM
MR. SHEFFIELD stated that the 30 percent net profits are
"embedded in one of the base leases that overlies Oooguruk," so
it is part of Pioneer's lease obligation to the state. He
added, "And then, we would pay PPT on top of that."
3:42:54 PM
MR. FOLEY noted that there are a handful of leases on the North
Slope that have both a royalty and net profit component but are
not a large contributor to the state economy. However, a third
of the money that would flow to the state of Alaska from
Pioneer's Oooguruk project comes from the net profit component,
he said.
The committee took an at-ease from 3:43:41 PM to 3:45 p.m.
3:45:30 PM
MR. SHEFFIELD returned to slide 12, and said Pioneer believes
that increased taxes potentially jeopardize lower tier project
funding. If the lower tier resources go unfunded, it is not
good for the state or the economy. He said the Oooguruk project
has probably the highest take of any project in the state of
Alaska, and Pioneer is concerned that its Oooguruk returns would
be reduced, in which case the company would be less likely to
fund similar projects in the future. Mr. Sheffield listed some
positive elements to come from ACES: it retains the net tax
framework for the non-legacy fields, and it allows credits to be
monetized at face value, with some time delay. He said Pioneer
believes that the only way higher taxes make sense is in a net
regime.
3:47:06 PM
MR. SHEFFIELD directed attention to slide 13, which is from the
Department of Revenue and shows the projected impact of ACES on
four new projects on the North Slope. He continued:
Our observation looking at this analysis is the
[market potential value (MPV)] of those four projects
was eroded by an aggregate of about 50 percent. And
if these projects were in our portfolio, they would be
much less likely to be funded. We believe that ACES
reduces the competitiveness of Alaska investments, and
it will make it more difficult for us to build a
business here in Alaska.
3:47:47 PM
MR. SHEFFIELD moved on to slide 14. He concluded the
presentation by saying that Pioneer's primary competition for
capital is the Lower 48. The company has been an aggressive
investor, but it requires fiscal stability. He said PPT
provides both the balance and the stability for Pioneer to grow
in Alaska, while ACES erodes modest PPT incentives. Finally, he
related, raising taxes on the abundant lower tier projects in
Alaska risks the funding of those projects, which would put at
risk royalty, state income tax, property tax, and jobs.
3:49:03 PM
MR. SHEFFIELD, in response to a question by Representative
Doogan, said that Oooguruk is an isolated field that is not
geologically connected to the Kuparuk field, but it will be tied
in to the infrastructure of Kuparuk by an eight mile flow line.
The committee took an at-ease from 3:50:35 PM to 3:58:21 PM.
3:58:24 PM
MARK HANLEY, Public Affairs Manager, Anadarko Petroleum
Corporation in Alaska (APC), emphasized the importance of
clarity and said he would discuss resource potential and risk.
3:59:57 PM
MR. HANLEY turned to slide 2 of his PowerPoint presentation.
The slide shows a map of all the areas worldwide where APC
explores for and produces oil and gas. He said APC is a large,
independent company that is not integrated and, thus, does not
typically have pipelines, refineries, or gas stations. He
referred to slide 3, which shows on a map the areas where APC
has a position as operator, where it has positions where it is
not the operator. He talked about investing and relinquishing
land; spending money to make discoveries. He indicated that
when people consider rate of return, they don't think about the
fact that the company has to cover risk, lease payments, and
seismic work, for example, even when it does not find anything.
4:04:47 PM
MR. HARVEY projected a slide from an Econ 1 presentation given
during discussion of PPT. He mentioned "prospectivity." He
indicated that the slide shows United States geological survey
(USGS) estimates of the central North Slope's undiscovered,
technically recoverable oil reserves. The mean estimate of
reserves to be discovered is 4 billion barrels, but the amount
of fields smaller than 64 million barrels is 51 percent. Mr.
Harvey reminded the committee that a 50-60 million barrel field,
if not within about 10 miles of existing infrastructure, is not
economic. The best place to find oil is where it's already been
found. Mr. Harvey said APC is one of the companies that think
there "are a few more alpines out there, which are these 500
million barrel fields."
4:07:34 PM
MR. HARVEY said risk and prospectivity needs to be considered
when considering government take. He stated, "If we had 800
[Tcf] sitting on the North Slope, I can guarantee you we'd be
having a little different discussion right now, and government
could probably justify taking a higher take than you can with 35
[Tcf] sitting up there and challenged economics."
4:08:15 PM
MR. HARVEY indicated a slide of the Arctic National Wildlife
Refuge (ANWR). He continued:
Remember before, on the North Slope, we had about 4
billion of technically recovered [oil] in those
smaller field sizes. Here you see a price factor put
on it. So, at $50 a barrel, you can see $2.66 billion
or at 63.2. So, ... for every $10 dollars here you've
got another 600 million barrels of recoverable oil.
Between 40 and 50, it's 700 million.
... And so, what I want to put in perspective, just so
you know, is: what is the impact of this tax thing?
One of the slides that the administration showed, and
I'll show it to you later, showed that the current PPT
raised, under their estimates, at $60 a barrel, about
$1.3 billion, and their ACES is about two, so call it
$700 million. ... 700,000 barrels a day is about, I
think, 240 million or 250 million barrels per year.
Okay, so what's that on a per barrel basis? Give or
take, it's about $3 a barrel, right?
... So, $3 a barrel is the cost on a per barrel basis,
... just [to] give you a rough idea. So, at least
with this chart you can see, at least through USGS,
well I can't tell you exactly, but if you take this
from 60 down to 57, you know there's some linear
thing, it's 150-200 million barrels that is ... not
economic overall. Can I tell which field that is? I
cannot. But ... when you're looking at this overall,
there is an impact - $3 a barrel is an impact. How
big an impact, which field is it going to do, how much
risk is there in a specific field? You know, all
those get affected. But again, just remember this is
not heavy oil, this is not existing fields.
So, if you were to do this ... - I think some other
companies have shown you what they think the economic
impacts are on infield drilling, maybe, at Prudhoe,
and offshore stuff. And again, the other thing to
remember, is this is oil, not gas, that [is] out
there. But again, I just want people to understand:
the oil that's out there tends to be in smaller
fields, and there is - even if you're just using
generic terms - an impact of $3 a barrel that's going
to have some impact. And you could actually [ask]:
"... If over 20 years I lost 200 million barrels, how
much would that cost the state, ... [including] take
and everything else?" So, you can get some idea and
roughly do it, but then you'd have to apply that to,
you know, NPR-A, offshore, anything that's open,
infield stuff, and you'd start getting an idea:
"Okay, we're raising 700 million a year. How much is
it?" And I don't know, I don't know what it comes out
[to be]. But there's an impact, and I guess that's my
main point is that it has to have -- and I will show
you later on.
And so, that's all I had from these slides, but I
thought it was a real good representation. It's their
presentation, but it really shows you this
prospectivity issue, as well as how the price can
affect -- and on this slide, like I said, ... these
are probably a number of years old, and the cost
factors are changed, but the concept's still going to
be the same; there's going to be some impact.
4:12:17 PM
MR. HANLEY returned to his APC PowerPoint presentation, to slide
4, which is titled, "Alaska Opportunities." He talked about the
world class petroleum basin and said there is a significant
amount of petroleum to be found in "legacy-type prospectivity -
anchor fields. He defined an anchor field as one that can
sustain its own infrastructure, is not tied back through another
facility, and is "kind of an alpine thing" with probably 400-500
million barrels of oil. He mentioned a 2 percent chance, and he
said APC's people think there is a chance to find some of those
fields, which would open up satellite opportunities around the
field. These fields tend to be higher risk, but they also tend
to yield higher reward. Mr. Hanley said APC thinks there are
currently a lot of opportunities to partner with new entrants up
to Alaska. He stated that having more companies drilling wells
is a positive thing. He explained that not all companies can
sustain 10 dry holes, but if there are several companies each
drilling three holes, for example, then there will be a couple
discoveries, and that will "focus people in a direction." This
method allows APC to partner and take more risks.
4:15:30 PM
REPRESENTATIVE NEUMAN noted that the committee had heard from
one of the oil economists who said that Alaska only needs enough
companies to produce the oil that Alaska has, and he said that
contrasts with Mr. Hanley's statement that the more players
there are, the better.
4:16:31 PM
MR. HANLEY acknowledged the state's perspective could be that it
only needs the minimum number of drillers to get the job done.
The problem with that, he said, is there are a lot of unexplored
acres and it would be ideal to have 15 holes a year drilled for
10 years to maximize the potential for discovery, which means
more companies drilling and trying out different concepts. He
offered examples of new exploration rigs in the state. He said
the PPT and net profits approach encourages that.
4:19:33 PM
MR. HANLEY moved on to slide 5, which addresses challenges in
Alaska. The basin is maturing and there is still a lot of oil
left to be found, but it tends to be in smaller
prospects/fields. Those smaller prospects attract different
kinds of companies. Other challenges, he noted, include a lack
of infrastructure and competition, long lead-time exploration,
and seasonal drilling. He offered examples.
4:23:40 PM
MR. HANLEY projected slide 6, which shows APC's view of PPT and
a recap of the 2006 testimony. He said, "You raised a bunch of
money on existing fields, but you created this new system for
new fields that was beneficial, ... effectively reduced our cost
of capital, and helped us with our net present value analysis."
If we're out drilling a lot of wells, doing a lot of
exploration, which is what the state's trying to
encourage, then we are able to offset that ... higher
tax rate at Alpine. And so, you're getting what you
want. As long as you keep investing in the state, you
can keep that tax rate down. And that's a positive
thing from our perspective, particularly from a
company that ... has explorations acres [and] wants to
go out there. So, the whole system set up, in our
view was a positive, even though we had a tax
increase, for instance, at Alpine.
4:25:14 PM
MR. HANLEY, referring to slide 6, said the company has seen an
overall improvement in exploration economics compared to the old
ELF system. He said the old 25/20 was worse in regard to
exploration economics than the old ELF system. He added, "And
that was before you had progressivity, so it would even be a
little ... worse." He stated, "On balance, we were supportive
of the PPT system."
4:26:22 PM
MR. HANLEY moved on to slide 7, entitled, "Support Net Profits
Approach." APC appreciates the administration's work in
evaluating gross versus net and its conclusion to stick with the
net system. He said he thinks a gross system could be designed,
but it would be complicated, and credits would have to be
offered. Once credits are offered, there must be a
differentiation between operating costs and capital costs. He
named the four areas related to the gross system: existing
fields, satellite fields, frontier exploration, and heavy oil.
The economics for each is significantly different.
4:29:10 PM
MR. HANLEY directed attention to slide 8, which shows APC's view
of ACES is that the negatives outweigh the positives. Some part
of ACES is support by APC, for example, the expansion of time to
qualify for the exploration incentive credits; however, that
positive is offset by a lot of new exclusions and restrictions.
Regarding equity, he said, while ACES does not directly affect
APC, it does directly affect the company's partners. He offered
an example. He stated, "In our view, the tax rate and the carry
forward should be the same number." He said APC would prefer
that the administration's proposed tax rate of 25 percent be
lower, but it is matched for the net operating loss, which he
said he thinks is fair. He said, "To the extent this helps
attract people who have worked in industry or understand the
industry, I think that's a positive thing, so we'll do that."
4:32:46 PM
MR. HANLEY, regarding stability, stated concern that PPT and
ACES be revisited again in the next few years to deal with gas.
He said, "I can tell you from our perspective, these rates are
too high for gas." He opined that the state needs to do
something to make gas economic. In the next two years, he said,
the industry will be back before the state government talking
about gas tax rates. He said that discussion is inextricably
linked with oil. Mr. Hanley listed the top three concerns: the
tax rate increase from 22.5 percent, the tax escalator, and the
transition investment expenditure credits elimination.
Regarding the tax escalator, he offered an example in which, at
$40 net, there would be a 2 percent higher tax rate under the
ACES plan. He said, "Where the numbers are exactly the same is
at $80 net." He emphasized the importance of being on the same
page with the administration.
4:37:28 PM
MR. HANLEY, regarding the elimination of the transition
investment expenditure credits, said, "Geez, if we'd have known
that you were going to change this thing, we would have changed
our decision - we would have absolutely waited." He explained
that APC spent money in '05-'06 to get a satellite on line, and
if the company had known it would be hit with a higher tax rate
without transition credits, it would have waited. He offered
further details. The policy call is how far back to go in
letting people collect money and how much a company will get
into the future. Originally, he said, "it was 1 for 1, and they
changed it to a 2 for 1," which meant having to invest at least
twice as much money to bring forward one dollar to get the
credits. He said this is an issue of fairness. He emphasized
the impact that tax decisions have in a company's decisions.
4:40:48 PM
MR. HANLEY directed attention to slide 9, which shows the
administration's field economics estimates. The table is from a
presentation from the administration given on September 4, 2007,
and it shows a project net present value of cash flows, with a
10 percent discount rate, and with field/projects A, B, C, and
D. The table shows that for each project, the economics
decrease anywhere from 33 percent to 54 percent. Mr. Hanley
said he does not know what geological and commercial risks were
assigned in this table, nor where the dry holes are and whether
failed projects were accounted for.
4:44:33 PM
MR. HANLEY turned to the summary on slide 10, which is:
"Significant tax increases outweigh any potential benefits." He
mentioned the time when APC pitched the idea of PPT or a net
profit system. He said the old ELF was a regressive system; at
high prices it was good for companies, but on the low side, it
was not. He said the state actually still has a gross and net
system, because the royalty is really a gross tax, in APC's
point of view. The old system took less at high prices. The
PPT took more of the high side but it actually "gave up some" on
the low side. On balance, he said, that was one of the things
about PPT that helped, because it gave some downside risk
protection for the companies. With a 10 percent floor, Mr.
Haley said, it is like the state is taking the low side and the
high side, and he posited that this is imbalanced and shifts the
risk even more significantly to the industry. That is why the
state will find opposition from companies, he concluded.
4:48:09 PM
REPRESENTATIVE DAHLSTROM expressed her appreciation for Mr.
Haley's ability to comprehend the responsibility the state has
as well as the corporate responsibility to find a balance.
The committee took an at-ease from 4:49:17 PM to 4:55:05 PM.
4:56:16 PM
DAN E. DICKINSON, Certified Public Accountant (CPA), stated that
he works in local practice but is giving this presentation on
behalf of the Legislative Budget & Audit Committee (LB&A). He
noted that all the information is on the LB&A web site and his
presentation would follow the order found on that site.
4:57:28 PM
MR. DICKINSON directed attention to slide 3 of his presentation,
which shows Alaska oil production from 1965 projected to the
year 2020. The majority of the oil produced has come from
Prudhoe Bay, production beginning in 1977 and peaking in 1989 at
1.6 million barrels a day. The peak, including production from
all other fields, totaled 2.1 million barrels a day. Since that
time there has been a decline, and today, Prudhoe Bay is
producing less than 400,000 barrels a day, and all fields
combined are currently producing approximately 700,000 barrels a
day - one third of the production of twelve years ago. He
continued:
During this time, the royalties were a much larger
piece of the state's fiscal system. ... As production
fell, the economic limit factor fell even more
dramatically, and the production taxes ... [went] from
being twice what royalty was, essentially, marching
down towards zero. People were very concerned about
the decline; they were very concerned about
investment. That was the major focus; it was
certainly Governor Murkowski's major focus. And in
that context, tax was really treated as one of the
fiscal tools that the state had, and it really was
viewed as a tax. By that I mean in the sense it was
an act of the sovereign authority to go out and look
at certain activities within the society and say those
should be bearing some portion of the society's total
burden - it really is part of the tradeoff between
those in our society who were the most fortunate, and
those that are less fortunate.
4:59:47 PM
MR. DICKINSON discussed figures pertaining to slide 4, which is
a graph showing the Alaska North Slope West Coast price from
July 1977 to September 2007. Since the low point of less than
$10 a barrel, there has been a dramatic increase in oil prices.
Even counting inflation, prices are higher than they were back
in 1980 when they hit a nominal peak of $35, he said. He
continued:
And in this time the conversations have changed.
We're not really talking about a tax in the
traditional sense anymore. We're basically talking as
if there was a new ... deal out there; there's a new
bid around. We want to talk commercial deals; we
don't want to leave money on the table.
There are lots of other resources that the state
obliges you to manage for the people's benefit, but we
don't talk about making sure that there's no pennies
left in anyone's pocket on that that we haven't over
hit. So, the whole conversation now is really driven,
I think, by the profits that are being made, and
that's changed the conversation. Nonetheless, we
still are a tax system.
5:01:06 PM
MR. DICKINSON projected slide 5, entitled, "Increasing Costs."
He stated, "I think we've all heard the story: Things were down
around $2 billion. We came in and the PPT was passed, and since
then they've gone up to about $4 billion." The first graph
shows the state's general fund budget, he noted. He said if
people had predicted 5 years ago what would happen to the state
budget, nobody would have said it would double. He relayed that
when people consider their tax system, they talk about revenue
sufficiency. Mr. Dickinson said governments put taxes in place
so that they can raise money for their operations. People don't
typically ask, "Well, how much did the other guy get?" The
concern is whether government gets enough to fund what it is
doing. And when the discussion turns to bid rounds or talking
about whether "the other guy" gets more profit, then the talk
has changed into something very different.
5:03:13 PM
MR. DICKINSON turned to slide 8, entitled, "Historical and
Forecasted Budget Surpluses and Deficits FY 2000 to FY 2020."
The chart on slide 8 shows a projected deficit in the year 2010,
which will increase to $1 billion by 2011 and $3 billion by
2015. He said the question is whether each time that deficit
increases will be reason for the state to reevaluate and see
whether or not it "left some money on the table with the
industry."
5:03:50 PM
MR. DICKINSON addressed the subject of information, which is
outlined on slide 9. He said information forms judgment, and
the big mistake "the team" made in presenting PPT was in "not
requiring a lot more information up front." He stated, "I
believe that what the governor's proposed to do makes a lot of
sense; people need to be comfortable with what's going on."
However, he said he would like to challenge some of the things
he has heard and to review what happened in the last fiscal
year, [as shown on slide 10, entitled, "FY 2007 first
snapshot."] He continued:
When most of you left the regular session in the end
of 2006, ... you had passed a budget. ... And that
budget you had based ... on what the Department of
Revenue had said revenues were going to be. And we
had said, "There's going to be $3 billion coming in
oil and gas revenues, there's going to be $400 million
coming in non-oil and gas, for a total budget of $3.4
billion. ... You had authorized ... general fund
spending of $3.2 billion for a surplus of $200 million
dollars.
What happened? ... You passed the PPT. And on the
fiscal note for that it said because of retroactivity
there's going to be FY 06 PPT revenues generated in
April, May, and June. They're going to come in, in
... fiscal year ... and in calendar year 2007, plus
you're going to have FY 07 payments made in calendar
year '06, but in FY 07 - so one's for the actual year
- of $923 million. So, the total increment for FY 07
will be $1.3 billion.
And so, at the end of the special session, you can
take the $959 million that we said was going to be
generated in the production tax under the ELF - under
the old system. Add to that an additional $1.3
billion in PPT to come out with a total of $2.3
billion, so you're total oil and gas is 4.3.
Obviously non-oil and gas and everything else stayed
the same. So, you're now looking at ... a total
coming in at $4.8 billion dollars. As I said, there's
a slight source difference here, so there's a slight
difference I don't understand there, but the general
point is: the surplus was going to be $1.3 billion.
5:06:59 PM
MR. DICKINSON continued:
Okay, let's fast-forward: What actually happened; was
there a shortfall? And the answer is no. ... This is
spring forecast 2007, so it comes out, I believe, in
April, so it's not quite to the end of the fiscal
year, ... but I think this is pretty accurate. What
happened is the total oil and gas was $4.3 billion -
about ... $23 million less than had been projected.
Non-oil and gas went up by about $150 million. So,
the total amount that actually came in was slightly
higher than the amount ... [of] the forecast that your
budget had been based on.
... If you look at the additional supplemental
authorizations that were made, some which were forward
funding, ... that exactly equaled the general fund
appropriations, and so, there was no surplus for the
[Constitutional Budget Reserve Fund (CBRF)] that year.
So, the point is, the total revenue projection was
$3.5 billion; the total amount that came in was $4.3
[billion].
5:08:09 PM
MR. DICKINSON said it is interesting to note that the Department
of Revenue's estimate for oil and gas production tax was the
closest estimate of any that was created. He said that fact
could be called lucky, because prices and costs were
underestimated, production was overestimated, and those factors
cancelled each other out.
5:09:53 PM
REPRESENTATIVE DOOGAN asked if Mr. Dickinson is addressing the
administration's assertion that PPT brought in $800 million less
than predicted.
5:10:31 PM
MR. DICKINSON indicated that he may be. He said he has heard
people talk about an $800 million shortfall many times and he is
not certain what that means. He described factors that may lead
to a discrepancy in the numbers.
5:11:31 PM
REPRESENTATIVE DOOGAN stated:
I'm not sure how useful what you just told me is.
People have been shifting numbers here more than once
since we sat down at this table. I've objected every
time, and now I'm objecting to you. If the discussion
over the ... revenue sufficiency of PPT - if I can use
that phrase - is based on a set of numbers that show
that there's $800 million less than were predicted at
the time the bill was passed - which I want to say is
not particularly important to me, because I didn't
cast any votes, so I wasn't relying on those
projections - then it's not particularly useful for me
for you to come in here and tell me if we look at
these numbers in a completely different way we get a
different result.
If what you're saying is that that statement is wrong,
then I'd like you to prove that to me using the same
method that they used to make it, if you can. ... And
if you can't, then I want you to explain what value
this number has to me in this debate.
5:12:57 PM
MR. DICKINSON said he will try to address Representative
Doogan's request.
5:13:18 PM
REPRESENTATIVE DOOGAN said he does not care if the number
doesn't turn out to be $800 million, as long as "we're talking
about the same thing."
5:13:25 PM
MR. DICKINSON said the question he would ask is: How would a
better forecast have made a difference during this last year?
He said he is attempting to separate regulatory control issues
from fiscal policy issues. He said he believes in offering more
information as opposed to less; however, getting that
information will not necessarily make the situation better.
5:15:21 PM
MR. DICKINSON directed attention to [slide 15], which shows a
simple model of FY 08 production tax revenue. He talked about
the model in conjunction with the governor's proposal.
Regarding the $800 million, he proffered:
... If these rules were in effect for all of ... FY
08, and we use the current modeling assumptions, the
difference between PPT and the governor's proposal
would be roughly $800 million. ... I believe that's
what's being said.
5:25:36 PM
REPRESENTATIVE DOOGAN responded, "That's not what's being said."
He continued:
What's being said is that there was a fiscal note that
indicated or said how much money the bill that passed
was going to raise, and ... in fact, the bill that
passed raised $800 million less than what was listed
on the fiscal note. Now, I'm not saying it's true,
but I'm saying that is what is being said.
5:26:03 PM
MR. DICKINSON stated his belief that if the dollar assumptions
were put in the fiscal note, a person would not have arrived at
that number.
REPRESENTATIVE DOOGAN responded, "So, you just think they're
wrong if that's what they're claiming."
MR. DICKINSON answered yes.
5:26:53 PM
REPRESENTATIVE NEUMAN offered his understanding that the $600-
$800 million was a result of what could be deducted, not the
different prices in the tax rate.
5:27:28 PM
REPRESENTATIVE DOOGAN said, "That statement was actually made in
this committee, as well, in the administration's presentation,
that most of the difference was [due to] substantially higher
costs that had been claimed - I think."
5:27:44 PM
CHAIR OLSON added, "In addition to Prudhoe Bay being shut down
for almost two months."
5:27:51 PM
REPRESENTATIVE SAMUELS said he does not know what number was
used to generate the $800 million figure. He said the last
couple months there was a lower figure of $700 million.
5:28:37 PM
MR. DICKINSON said that clearly, in the fiscal note, the cost
numbers used were far below the cost numbers that have shown
since and are being used for estimations. He said he is not
questioning that line of reasoning. He emphasized his point is
that in looking at the other assumptions, such as price and
volume, it is easy to adjust "some of those and not others" and
then say there is some deficit or lack of revenue that flows
from that. He clarified that he was trying to look at "what was
being said in the fiscal note at the time."
5:29:47 PM
REPRESENTATIVE DOOGAN clarified that he was trying to ensure
that Mr. Dickinson was addressing the same case that the
administration was addressing.
5:30:04 PM
MR. DICKINSON reviewed the work to date, which is shown on slide
16. He then turned to slide 17 - which outlines part II of the
presentation. He said he would comment in the case of tax rules
that are replaced by the discretion of an agency.
5:30:56 PM
CHAIR OLSON acknowledged the presence of Commissioner Patrick
Galvin of the Department of Revenue.
5:31:09 PM
MR. DICKINSON continued. He said he would also talk about when
broad and robust rules are replaced with narrow, specific
approaches, and situations in which production tax, or features
of it, can be made to look more like a windfall profits tax,
versus "the notions of the floor." Finally, he said data,
although good, does not make the decisions and may not even give
all the necessary information needed. In reference to slide 18,
regarding rate, Mr. Dickinson issued a caveat on government take
statistics. He explained that apples to oranges comparisons are
very useful, but he asked everyone to be wary about comparing
numbers from various studies with different assumptions. He
recommended looking at the rest of the fiscal system. He said
some governments encourage high paying jobs with low industry
taxes and pick up the difference by other means, such as
personal income and consumption taxes.
5:33:26 PM
MR. DICKINSON talked about progressivity, which is on slide 19.
Regarding switching factors, he said there is a switch from
monthly to annually, which typically means lower dollars. He
continued:
If you have a spike, under the progressivity, it will
... average out. ... I believe that when people were
here last year, in the summer of '06, and prices were
at $75, people were thinking about that as a spike.
And those of us who talked about it as a spike
probably have a little egg on our face, because it
didn't go back down - or it did, but for a couple
weeks - and then it went charging on up. It is less
progressive, because it's basically making ... more of
a base rate and picking up less at the upside.
Clearly, it is administratively more simple; that's
one of the things the administration has talked about,
and I agree with that absolutely.
5:34:39 PM
REPRESENTATIVE SAMUELS said:
It had been my assumption that it's a true-up at the
end, but you're still going to get -- I mean, the
point of the progressivity was to get the spikes ....
Is it that the language of the bill says that you're
going to average it for the year and then collect it
at the end of the calendar or fiscal year, or
whatever?
5:35:05 PM
MR. DICKINSON answered yes. He offered his understanding that
the piece for applying the progressivity will no longer be
calculated monthly.
5:35:24 PM
MR. DICKINSON moved on to slide 20, which, in terms of
progressivity, compares an annual and monthly analysis of FY 08
with a hypothetical spike. He pointed out that with the $40
starting point that is in current law, for nine months out of
the year, absolutely no progressivity would be generated;
however, in the three months of a spike, the price index goes
up, and quite a bit of progressivity is picked up. He
highlighted the progressivity over the year as shown in the
analysis. He said, "My point here is, a single month at a high
rate, when it gets averaged in, you lose the effect." He
stated:
So, the observation on progressivity is: I believe
the most dramatic change probably is the one that
stems from the monthly versus annual. It's very, very
hard to model, because no one's going to make
predictions, and certainly I'm not going to try to
make predictions about the upcoming monthly crisis,
and whether those spikes are going to occur or not.
5:38:14 PM
MR. DICKINSON addressed slides 22-24. The first two are graphs
showing the effect of a gross floor - low end, while the latter
shows the effect of a gross floor - windfall profits. He
offered details. He said to his way of thinking, a gross
windfall profits tax makes a lot more sense than a floor.
5:44:41 PM
MR. DICKINSON explained that the state's system was regressive
for many years, which made sense when Alaska was a young state.
Every year, the state knew that cash would come in to cover
costs. Today, the state has a savings account with billions of
dollars in it - the earnings reserve - and those dollars are
available for appropriation.
5:46:01 PM
MR. DICKINSON directed attention to slide 25, addressing the
issue of ring fencing. If a legacy field is generating profits,
that money can be reinvested, and that would still be allowed
under the governor's proposal. Mr. Dickinson pointed out a
typographical error at the bottom of the slide. The language
there should read: "Investment credits and losses generated in
Legacy Fields could not be offset by profits generated
elsewhere." He explained that a credit within a legacy field
has to stay there; if it cannot be used, it will never be used
anywhere else.
5:47:32 PM
MR. DICKINSON reviewed the information on slide 26 - ".023
Investment Credits." He talked about a 20 percent loss carried
forward, why it is not the same as the tax rate, and whether it
discriminates against people. He said, "My observation [is
that] it is, and I applaud the notion of making the two the
same." He addressed the issue of spreading out credits over two
year's time and the proposed elimination of TIE credits.
Regarding the latter, he said .025(i) in the bill would
essentially introduce a "mini TIE"; however, the commissioner of
the Department of Natural Resources could authorize credits to
people who had done seismic work prior to 2003. He said people
talk about the conceptual notion of what people expect when
making an investment, and "eliminating the TIE credits would not
eliminate that particular concept." Regarding ".024 Non
Transferable Credits" - as shown on slide 27 - Mr. Dickenson
said the only proposed change in the bill is that those credits
could not be applied against the floor.
5:49:22 PM
REPRESENTATIVE SAMUELS surmised that in an arena where there
were either massively increasing costs or, more likely, a
decreasing price where "you hit the floor," the $12 million
credit is actually "against their income."
5:49:58 PM
MR. DICKINSON confirmed that's correct. He moved on to slides
28 and 29, regarding exploration credits. The new addition to
the bill, in .025(b)(3) would state, "costs arising from gross
negligence or violations of health safety, or environmental
statutes or regulations". The new language in .165(e)(6) would
state, "costs arising from fraud, wilful misconduct, gross
negligence, violation of law, or failure to comply with an
obligation under a lease, permit of license issued by the state
or federal government". He said, "In general, I think it makes
sense to not have the kinds of things that would not be allowed
under, for example, a federal tax."
5:53:28 PM
REPRESENTATIVE NEUMAN referred back to slide 26 and stated his
concern is that a company spends a lot of money to procure
seismic information - to find out about the existing rocks - and
it seems unfair that in two years that information becomes
public and available to others who did put out the cash.
5:53:42 PM
MR. DICKINSON prefaced his response by noting that there is a
difference between well data and seismic data. He said
companies could chose to keep that information to themselves;
they would simply not qualify for the credits.
5:54:12 PM
MR. DICKINSON returned to the presentation, to slide 29, which
addresses exploration credits and "moving from a rule to agency
approval." Currently, he noted, AS 43.55.025(c) requires that a
bottom hole be three miles from previously drilled bottom holes,
except in Cook Inlet if the Department of Revenue determines the
site is a "distinct exploration target." The proposed
legislation changes that by putting in place three requirements:
before applying for credit, the company must get DNR approval;
the company must still meet the three-mile requirement if the
site is not in Cook Inlet; and the company must get DNR approval
"afterwards" to apply for the credit - to confirm that
everything was done as promised.
5:55:37 PM
REPRESENTATIVE SAMUELS asked if, by "rules," Mr. Dickinson is
referring to statutes, as opposed to regulations.
MR. DICKINSON answered yes.
5:55:47 PM
MR. DICKINSON continued with the subject of exploration credits,
shown further on slides 30-32. He said the proposed legislation
would make data on nonstate land - private and federal - more
available to DNR and the public. He mentioned the tax code. He
reviewed that under current law, only additional wells spudded
in a drilling season of 150 days qualify for exploration
credits; however, the proposed legislation would expand that
figure to two drilling seasons, which equal 540 days. The bill
would shift credits to explorers. It would also create "mini-
TIE," allowing DNR to authorize tax credits for seismic work
done prior to 2003.
5:57:29 PM
MR. DICKINSON moved on to the issue of allowable lease
expenditures, which is covered on slides 33-40. He said [AS
43.55.160] would be greatly simplified, because there would no
longer be the need for doing monthly calculations for
progressivity and a monthly gross based on windfall profits tax
would not require division of costs between months. Under the
proposal, allowable lease expenditures must be defined in
regulation, which is a switch from "what is not forbidden is
permitted" to "what is not permitted is forbidden." Mr.
Dickinson said his concern is that the regulatory agency will
have to play "catch up" with innovations in the field. He
stated that although specific language authorizing joint
interest billings would be repealed under HB 2001, the
Department of Revenue would still be able to "go down that road"
through its authority granted under its regulations.
REPRESENTATIVE SAMUELS said everyone agrees upon using the
billings as a base point; however, there has been disagreement
regarding whether to keep or eliminate "the two paragraphs."
6:00:37 PM
MR. DICKINSON said, "I agree that one of the paragraphs was
confusing, but the other one wasn't." He offered examples.
6:02:11 PM
MR. DICKINSON returned to the presentation, to slide 35.
Regarding AS 43.55.165(e)(6), he said the current prohibition is
costs arising from fraud, wilful misconduct, or gross
negligence. The proposed legislation would add: a violation of
law; a failure to comply with an obligation under a lease,
permit, or license issued by the state or federal government.
He said this is different from that which is being proposed for
AS 43.55.025(b)(3). Mr. Dickinson said in general he is fine
with this proposition; however, he questioned what it would mean
to fail to comply with an obligation under a lease, and what
kinds of costs would result.
6:03:13 PM
MR. DICKINSON, regarding slide 36, said [subsection (e)] would
prohibit deductions of the certain costs. He continued:
Under current law, [dismantlement, removal, and
restoration (DR&R)] cash payments, ... for upstream
only, not for pipelines, would be allowed. ... Any
DR&R proportionally that was produced or that the
effect of which came from after the PPT law bill was
passed, would in fact be deductible. The governor's
proposal totally disallows DR&R.
One of the interesting things about DR&R ...: At the
end of the field life, as costs rise, there's going to
be a point at which costs are too high and the field
will shut down; people won't be able to use it
anymore. At some point ... TAPS is going to come to a
place where you say there isn't enough volume, the
costs to run TAPS are too great. At that point,
probably, that's when the legacy fields will ... shut
down.
The point is: Even though there's a fair amount of
DR&R that ... was nominally deductible, a lot of it -
and it always has to be on a cash basis - will be
incurred after there's no longer anything come to
offset. There will be no net ... barrel values that
can be brought down.
So, the general discussion under DR&R and
deductibility really has to do with some of the
smaller fields in which DR&R will occur prior to
shutting down TAPS, as long as the legacy fields are
still producing. ...
6:05:50 PM
MR. DICKINSON, regarding slide 37, said he would compare three
different approaches: that of the bill, that of SB 80, and that
of the governor's proposal. The proposal, he said, would
disallow costs arising in response to a problem which required
an unscheduled reduction in production or resulted in a release
of gas. He suggested that the legislature needs to redefine
what reschedules means, because "unscheduled reduction" is a
term that could be difficult to define. Acts of God, he said,
would still be allowed.
6:08:03 PM
MR. DICKINSON, referred to slide 38, which shows: "Current law
disallows 30 cents a barrel from what would otherwise be
allowable capital costs. This was described as dealing with the
known corrosion issue."
6:09:11 PM
REPRESENTATIVE DOOGAN asked if the 30 cents is subtracted from
the deduction or from what the deduction is based upon.
6:09:28 PM
MR. DICKINSON confirmed the former. He continued:
It is subtracted from your deduction, so you pay tax
on 30 cents more. In other words, if you think about
the net value, it's going to be 30 cents higher as a
consequence of subtracting this from the deduction.
MR. DICKINSON, as shown on slide 39, said the approach of SB 80
was to disallow any costs associated with improper maintenance.
Under current property tax law, he said, is the concept known
as, "replacement cost new less depreciation." He continued:
What is taxed on the North Slope are not the
facilities that are there, but the ... hypothetical
facilities that are there had there been a replacement
of them. And so, what happens is, tax payers come in
and they spend literally millions of dollars, and they
basically build an "as if," and they say, "If we were
producing 400,000 barrels at Prudhoe Bay, we wouldn't
have six production facilities, we'd have three, and
we would have 42-inch pipe, we'd have...
You go through the whole rigmarole and you say,
"Here's the 'as if' facility." And that's what the 2
percent property tax is levied against. ... I believe
that's exactly what would have to happen, because you
... could have improper maintenance here, a little bit
here, something in that facility that had the
implication that this facility was done differently.
And so, essentially, you'd have to build this "as if"
proper maintenance, and every year it gets sort of
further and further disconnected.
6:11:54 PM
CHAIR OLSON interjected:
Without debating the merits of the bill, I think in
this particular case, the fact that the feeder lines
hadn't been pigged for eight years, the corrosive
additive had been cut back to basically water, I
believe, that it was kind of like the definition of
pornography a few years ago: You don't really know
what it is, but you know it when you see it. In this
particular case, we ... had a difficult time finding
industry standards, but we knew it when we saw it.
6:12:23 PM
MR. DICKINSON said that is a fair point. He suggested that one
of the three approaches is appropriate, but he does not think
"having two or three of them in there" would be. He added, "If
one of these other approaches is taken, then I believe the 30
cents should be repealed, because I think that was an express
attempt to meet that concern."
6:13:17 PM
MR. DICKINSON, regarding slide 40, said the question is whether
there will be some new topping plants "up there," and whether
that is an appropriate part of production that should be
allowed. He continued:
Two concerns I have: One is that you're going to have
a fair market value standard in its place where there
isn't a broad market - not a lot of liquidity, and
trying to figure out what that is, again, may ... be
difficult. And I hate to get into situations where
people say, "Gosh, the companies owe us money, ...
they're messing with us." And then it turns out it's
a fight about the fair market value and somebody who's
buying and trading in that market is arguing with
someone who isn't in that market about what fair
market value is. Those standards are very hard to
define if you don't have liquid markets.
One observation I'll make: We all accept the ANS
market value now - the way that's traded and the way
that's reported - but for the first 10 years, when
that was going on, there ... was a lot of skepticism,
a lot of difficulty accepting that, and I would just
be very concerned about having a fair market value
standard for transactions on the North Slope.
And my last concern: ... It's always difficult when
you're trying to take a broad, general principle like
this and you've got plants staring you in the face,
and depending on whether it's in or out, a different
company will be able to make money. And that's ...
just always unfortunate when that's what it comes down
to.
6:15:57 PM
MR. DICKINSON, in response to a question from Representative
Neuman, said he does not believe there would be any question
that fluids purchased for production would be deductible if they
were part of an arm's-length transaction. He continued:
My belief is at the moment, most of this is simply
fuel used for vehicles and compressors and standby
things that aren't running on the natural gas, or what
happens if the methane stream that's used is
interrupted - that that's the main use. And I think
those are clearly production uses. So, I haven't done
the math on that particular issue about how those two
would balance out.
6:16:45 PM
MR. DICKINSON moved on to the issue of the state's purchase of
credits, shown on slide 41 and regarding AS 43.55.028.
Currently, he indicated, that credit purchase is allowed only in
relation to small producers, and when they apply, they have to
reinvest the money in the state, including lease bids, they
cannot have any other delinquent taxes, and there is a limit of
$25 million a year. The proposal, he said, would establish a
fund from tax revenues and the earnings on them, which would be
used to purchase the credits. Furthermore, he said, the
proposal would remove the $25 million limit. He observed that
those are two separate issues. He explained that there could
still be a fund that could be funded through a percentage of tax
revenues and capped at a certain amount, or "you could take off
the cap and not have the funding."
6:17:53 PM
MR. DICKINSON directed attention to slide 42, regarding
information issues and pertaining to AS 43.55.040(5) and (6).
This section of statute, he said, would require taxpayers to
file reports and copies of records that are considered by the
department as necessary to forecast state revenues under AS
43.55, and a $1,000 penalty would be levied for failure to
comply. He explained how this can be ambiguous language. He
suggested a better definition for the word "necessary," a
specification of how far in advance, in terms of the forecast,
how often the reports need to be updated, how far due diligence
would have to go, and whether the state can audit for
information not provided.
6:20:00 PM
MR. DICKINSON turned to slide 43, which covers information
related to the general rule in AS 43.05.230 and the proposed
rule in AS 43.55.890. Currently, he stated, DOR can publish
statistics with individual data combined to prevent the
identification of particular returns or reports. The proposal
requires only the combination of three taxpayers, "regardless of
whether the information prevents the identification of
particular returns or reports." Referring to notes on slides
44-46, he said, "This was described by some folks as being
exactly what happens under the Salmon Pricing Report, which is
something else the Department of Revenue does." Regarding that
report, he noted that lots of values are not reported because of
confidentiality reasons. The report is given in summary. He
continued:
The confidentiality statute does not remove the Salmon
Pricing Report from the general tax law that it has to
prevent the identification of a specific tax payer.
What it does say is: ... If price averages are
calculated by the department, it's public information,
except the information that identifies or could be
used to identify a particular fish processor is
confidential. I guess that's restating the
prohibition that is already in the ... general tax
statute. It may be the reason that, in fact, this
information is not tax information, and therefore the
general tax rule doesn't apply. I don't know why they
have this separate thing. But my point is: You've
got a situation where you're still required under the
Salmon Pricing Report to make sure that a particular
fish processor cannot be identified.
... Here's the language out of the Salmon Pricing
Report ...: "We use the following guidelines when
evaluating confidentiality. If there are three or
more processors for a given area ..., the information
is reported unless one processor accounts for over 80
percent of total value, or two processors account for
over 95 percent of total value." If that is the case,
he said, information is not reported.
MR. DICKINSON asked the committee to review the laws to ensure
that they adequately protect confidentiality.
6:23:14 PM
MR. DICKINSON looked at slide 47, showing information regarding
AS 43.05.230(h). He said the proposal would require DOR to
share information with DNR obtained under AS 43.55. Mr.
Dickinson said he thinks that is a great idea for there to be
more cooperation between the agencies. In response to a
question from Representative Samuels, he indicated that the
department has not had a competitive sale since 1986, but that
does mean it won't have them again. The other issue is that all
the tax information is "backward looking." Up to today, he
said, that is true. He continued:
But the point is, if you read the wording, what this
is going to say is all the forward-looking information
that you have to produce under a $1,000 a day penalty
will also be available to the Department of Natural
Resources. And that's simply where my concern is,
whether that will have (indisc.) implications or not.
6:25:05 PM
MR. DICKINSON noted that slide 48 shows what has to be filed by
the tax payers. He said he agrees with this portion. As shown
on slide 49, the proposal would extend the statute of
limitations from three years to six years. He said he doesn't
think that is that big a deal, because currently there are
mutually agreed upon extensions. He recommended that the
committee look at "this notion that you can assess $1,000 a day
for not reporting information," and consider whether that would
be extended, or whether advance notice or more timely
notification should be required in association with those
penalties.
6:26:19 PM
MR. DICKINSON turned to slide 50, which addresses the issue of
auditors as exempt employees. He said it is a great idea if one
is trying to get people in a competitive market. He noted,
however, that there are income tax auditors within the
Department of Revenue, and income tax is complex. There are
over half a billion dollars a year being generated in income tax
issues. He added, "It's not a trivial issue."
6:27:23 PM
REPRESENTATIVE NEUMAN asked, "What's your opinion if that job
was farmed out?"
6:27:35 PM
MR. DICKINSON stated his belief that in the beginning, the job
should be farmed out. He said there are firms in the Lower 48
that do this all the time. He recommended using those folks as
"part of the seed process to get the Department of Revenue
going." He said people will believe that the department should
have people dedicated within the state. He said he thinks it
will always be useful to have outsiders coming into the system.
6:28:48 PM
MR. DICKINSON moved on to slides 51-52, which address all the
other information systems. He said "this" requires the
information to be filed in a form or manner approved or
prescribed by the department. He said this is something he used
to think was great. He explained, "Tax payers already have this
information, so there's no burden being placed on them, but if
they have to restate it, 'refile' it, and do it all monthly in a
way that meets the state's requirements, there may be a burden
on the tax payer." He said the problem with a form generated by
the Department of Revenue is that it represents their view that
everyone else has to fit the data into those categories.
Sometimes when that happens, he said, "you miss what's going on,
because there's some new division being made we don't know
about, but they have to take those numbers and add them back
together, for example, and stick them into one of our
categories." He expressed a desire to see a balance between
getting information in its raw form and getting information in a
form that can be used immediately.
6:30:47 PM
MR. DICKINSON, referring to slide 53, noted that Pedro van
Meurs, Ph.D., had told the legislature to look at the penalty
provisions, because this bill would weaken them. He indicated
that he had subsequently spoken to Dr. Van Meurs and shown him a
different view point. He continued:
Let me just explained the way the interest provisions
work. Within a year, if ... the taxpayer makes
estimated payments, and they're underestimated, they
owe the time value of money; they have to pay interest
from that through March 31 at a rate set by the IRS,
which is generally viewed pretty close to a market
rate. If they ... overestimate in a month and it
turns out that they owed less, then the state owes
them money.
...And there's actually four rates, because the IRS
has what's called an "over payment" and a "large over
payment" [rate]. And it's not symmetrical, but the
taxpayer owes a higher interest rate to the state, and
vice versa, ... and then the break-off there is, I
believe, $100,000. Then ... if there's a refund, the
interest ... is at a lower rate, and I believe the
level there is $15,000, but I could be wrong on those.
But as soon as you hit March 31, everything that's
happened before gets rolled together, and from that
day forward you are back under Alaska statute, which
at the moment is 11 percent compounded. ... Folks can
make their own judgments about the relation of that to
market rates, but I believe that most people looking
at that believe that ... if your state underpaid for
four or five years and then [had] to pay 11 percent on
that, ... that is a penalty. And what Dr. Van Meurs
didn't understand is that ... the ... lower IRS rates
stopped as soon as you hit March 31.
6:32:56 PM
MR. DICKINSON directed attention to the information on slides
54-56, regarding Cook Inlet "Simplicity." He suggested that the
Cook Inlet ceilings could be implemented more simply.
Currently, calculations have to be done individually for each
lease or property - once for the oil and once for the gas.
Under current statute, all the North Slope is "one segment - one
set of calculations." Everything outside of Cook Inlet and the
North Slope was another calculation. He said, "And then within
Cook Inlet, a taxpayer might have five or six or seven segments,
because this calculation had to be done so often." He
continued:
So, I think there were two rules the legislature
wanted to impose. The first one: there were ceilings
- that Cook Inlet taxes will remain zero for oil, and
for gas it would preserve a level of the ELF and the
prices that were found in 2005-6. And then that would
be preserved until 2020.
The second important principle is that these ceilings
were meant to benefit consumers. Therefore, if a
taxpayer was paying a whole lot less because of the
ceiling -- Maybe I'll just skip ahead to the next
[slide] to give you an example: If I owe $10 in
taxes, and then I have some credits and I apply them
and they drop my tax to $5, and then it turned out
that the ceiling dropped it further down to $3, a
taxpayer couldn't come in, pay their $3 in taxes, take
that $5 credit, and sell it to somebody or use it
elsewhere. The notion was if you were paying lower
taxes because of the ceiling, you had to apply your
credits and your costs and your lost carry forward to
bring you as close to that ceiling as you could. And
that makes sense. And I believe that there's ways
that that can be implemented. It will be a lot less
difficult then the three or four pages that it now
takes to implement those.
6:35:34 PM
MR. DICKINSON concluded his presentation with slide 55, which
addresses the effective date. Generally, he said, the effective
date is January 1, 2008. He said:
I think there are two very good tax policies built
into there. The first one is: the change corresponds
to the calendar year, which is the basis on which all
the taxes are paid, so you don't have to have this one
system through three months and another system through
another several months. So, that's a good idea. And
then the other thing is: generally, as a tax person,
I tend to think that retroactivity - the more limited
use of that is made the better, and so, I applaud the
fact that it's a foreword-looking tax. There is one
provision which is retroactive - the so-called
corrosion provisions - but otherwise it is foreword
looking.
[HB 2001 was held over.]
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at
6:37:04 PM.
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