Legislature(2005 - 2006)BUTROVICH 205
03/15/2006 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB305 | |
| Department of Revenue - Roger Marks, Dan Dickinson, Cheri Nienhuis, Robert Mintz from the Department of Law – Question and Answer | |
| Department of Revenue - Roger Marks and Cheri Nienhuis | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| = | SB 305 | ||
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
March 15, 2006
3:37 p.m.
MEMBERS PRESENT
Senator Thomas Wagoner, Chair
Senator Ralph Seekins, Vice Chair
Senator Ben Stevens
Senator Fred Dyson
Senator Bert Stedman
Senator Kim Elton
MEMBERS ABSENT
Senator Albert Kookesh
OTHER MEMBERS PRESENT
Senator Gene Therriault
COMMITTEE CALENDAR
SENATE BILL NO. 305
"An Act repealing the oil production tax and gas production tax
and providing for a production tax on the net value of oil and
gas; relating to the relationship of the production tax to other
taxes; relating to the dates tax payments and surcharges are due
under AS 43.55; relating to interest on overpayments under AS
43.55; relating to the treatment of oil and gas production tax
in a producer's settlement with the royalty owner; relating to
flared gas, and to oil and gas used in the operation of a lease
or property, under AS 43.55; relating to the prevailing value of
oil or gas under AS 43.55; providing for tax credits against the
tax due under AS 43.55 for certain expenditures, losses, and
surcharges; relating to statements or other information required
to be filed with or furnished to the Department of Revenue, and
relating to the penalty for failure to file certain reports,
under AS 43.55; relating to the powers of the Department of
Revenue, and to the disclosure of certain information required
to be furnished to the Department of Revenue, under AS 43.55;
relating to criminal penalties for violating conditions
governing access to and use of confidential information relating
to the oil and gas production tax; relating to the deposit of
money collected by the Department of Revenue under AS 43.55;
relating to the calculation of the gross value at the point of
production of oil or gas; relating to the determination of the
net value of taxable oil and gas for purposes of a production
tax on the net value of oil and gas; relating to the definitions
of 'gas,' 'oil,' and certain other terms for purposes of AS
43.55; making conforming amendments; and providing for an
effective date."
HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB 305
SHORT TITLE: OIL AND GAS PRODUCTION TAX
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
02/21/06 (S) READ THE FIRST TIME - REFERRALS
02/21/06 (S) RES, FIN
02/22/06 (S) RES AT 3:30 PM BUTROVICH 205
02/22/06 (S) Heard & Held
02/22/06 (S) MINUTE(RES)
02/23/06 (S) RES AT 3:30 PM BUTROVICH 205
02/23/06 (S) Heard & Held
02/23/06 (S) MINUTE(RES)
02/24/06 (S) RES AT 3:30 PM BUTROVICH 205
02/24/06 (S) Heard & Held
02/24/06 (S) MINUTE(RES)
02/25/06 (S) RES AT 9:00 AM BUTROVICH 205
02/25/06 (S) -- Reconvene from 02/24/06 --
02/25/06 (H) RES AT 10:00 AM SENATE FINANCE 532
02/25/06 (S) Heard & Held
02/25/06 (S) MINUTE(RES)
02/27/06 (S) RES AT 3:30 PM BUTROVICH 205
02/27/06 (S) Heard & Held
02/27/06 (S) MINUTE(RES)
02/28/06 (S) RES AT 3:30 PM BUTROVICH 205
02/28/06 (S) Heard & Held
02/28/06 (S) MINUTE(RES)
03/01/06 (S) RES AT 3:30 PM BUTROVICH 205
03/01/06 (S) Heard & Held
03/01/06 (S) MINUTE(RES)
03/02/06 (S) RES AT 1:30 PM BUTROVICH 205
03/02/06 (S) Heard & Held
03/02/06 (S) MINUTE(RES)
03/02/06 (S) RES AT 3:30 PM BUTROVICH 205
03/02/06 (S) Heard & Held
03/02/06 (S) MINUTE(RES)
03/03/06 (S) RES AT 3:30 PM BUTROVICH 205
03/03/06 (S) -- Meeting Canceled --
03/04/06 (S) RES AT 10:00 AM SENATE FINANCE 532
03/04/06 (S) Presentation by Legislative Consultants
03/06/06 (S) RES AT 3:30 PM SENATE FINANCE 532
03/06/06 (S) Heard & Held
03/06/06 (S) MINUTE(RES)
03/07/06 (S) RES AT 3:30 PM BUTROVICH 205
03/07/06 (S) Heard & Held
03/07/06 (S) MINUTE(RES)
03/08/06 (S) RES AT 3:30 PM BUTROVICH 205
03/08/06 (S) -- Meeting Canceled --
03/09/06 (S) RES AT 3:30 PM BUTROVICH 205
03/09/06 (S) -- Meeting Canceled --
03/10/06 (S) RES AT 3:30 PM BUTROVICH 205
03/10/06 (S) -- Meeting Canceled --
03/11/06 (H) RES AT 10:00 AM CAPITOL 106
03/11/06 (H) -- Meeting Canceled --
03/13/06 (S) RES AT 3:30 PM BUTROVICH 205
03/13/06 (S) Heard & Held
03/13/06 (S) MINUTE(RES)
03/14/06 (S) RES AT 3:30 PM BUTROVICH 205
03/14/06 (S) Heard & Held
03/14/06 (S) MINUTE(RES)
03/15/06 (S) RES AT 3:30 PM BUTROVICH 205
WITNESS REGISTER
SHARON NIENHUIS, Petroleum Economist
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Commented on SB 305.
ROGER MARKS, Economist
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Commented on SB 305.
DAN DICKINSON, CPA
Consultant to the Governor
Office of the Governor
PO Box 110001
Juneau, AK 998811-0001
POSITION STATEMENT: Commented on SB 305.
ROBERT MINTZ, Assistant Attorney General
Department of Law
PO Box 110300
Juneau, AK 99811-0300
POSITION STATEMENT: Commented on SB 305.
ROBYNN WILSON, Director
Tax Division
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Commented on SB 305.
ACTION NARRATIVE
CHAIR THOMAS WAGONER called the Senate Resources Standing
Committee meeting to order at 3:37:18 PM. Present were Senators
Elton, Dyson, Stedman, Ben Stevens and Chair Thomas Wagoner. He
announced that they would hear the final presentation on the
questions the legislature asked the administration on SB 305.
SB 305-OIL AND GAS PRODUCTION TAX
3:37:18 PM
CHAIR THOMAS WAGONER announced SB 305 to be up for consideration
and that Dan Dickinson and Cheri Nienhuis would address the
committee's questions to the administration.
^Department of Revenue - Roger Marks, Dan Dickinson, Cheri
Nienhuis, Robert Mintz from the Department of Law - Question and
Answer
DAN DICKINSON, CPA, Consultant to the Governor, said that Robert
Mintz, Assistant Attorney General, Sharon Nienhuis, Petroleum
Economist, Department of Revenue, and Roger Marks, Economist,
Department of Revenue would assist in the presentation. He
recapped that a lot of the answers to the 91 questions had
already been answered. Twenty are remaining to be answered
today. He jumped in at question 22. [The answers to the
questions correspond to the Department of Revenue's letter to
Senator Wagoner, Chairman, Senate Resources Committee, and
Representatives Samuels and Ramras, Co-chairmen, House Resources
Committee, dated March 15, 2006. The answers are indented, but
not necessarily verbatim, for this document.]
3:39:03 PM
22. Please provide an identification of the point of production
at each unit in the state under existing statutes, regulations,
agreements, and court decisions. Provide the same under the
definition as proposed.
He answered the point of production for crude oil
would not change under the proposal and would remain
the point where the oil is first metered or measured
in a condition of pipeline quality. (Note that certain
oil used on the lease will no longer be taxable under
the proposed production tax reforms, but that is not a
point of production issue.) As examples, the points of
production for oil are and will be the LACT (lease
automatic custody transfer) meters at the inlets to
TAPS (for Prudhoe Bay) and the Kuparuk Pipeline (for
Kuparuk), and at the onshore production facilities for
the Cook Inlet platforms.
What will change, in some cases, is the point of
production for some gas. At Prudhoe Bay, while the
current point of production for most gas is the inlet
to the Central Gas Facility (CGF), there are other
potential points of production for other gas uses. For
example, in the separation facilities, gas is taken
right out of the flow stream and burned in that
facility (however this gas is not taxable under the
free use of gas rules).
For taxable gas, the inlet to the CGF is generally the
point of production for all gas that emerges from the
CGF, including the NGLs that are recovered in liquid
form. This compares to other gas plants that are or
have been operating at Kuparuk, Endicott, and
Lisburne. For these facilities, the point of
production for gas under current law is the outlet
where the facility is tied to a sales or other line
that take the gas off the unit. Why? Because in each
of these facilities, the liquid hydrocarbons extracted
from the processed gaseous stream are reblended with
oil and run through gas-oil separators again.
Therefore, the gaseous stream entering the facility
has not yet been completely separated from oil and the
point of production for gas must be downstream of the
facility. Under the bill, all gas processing
operations (as long as they do not also include gas
treatment) are considered upstream of the point of
production. Therefore, the point of production for gas
run through the Prudhoe Bay CGF will be where the gas
is metered after leaving the CGF. In this respect, the
point of production for gas will change at Prudhoe Bay
but remain the same - downstream of the gas processing
facilities - at the other North Slope fields using gas
processing.
3:42:00 PM
SENATOR SEEKINS joined the committee.
3:42:11 PM
23. Please provide an identification of "gas treatment" and "gas
processing" facilities in the state under the existing statutes,
regulations, agreements, and court decisions. Provide the same
under the definition as proposed.
To date in administering the tax, there are no gas
treatment facilities on the North Slope. The only "gas
processing plant" currently in the state is the
Central Gas Facility (CGF), because by definition in
the department's regulations, a facility is a gas
processing plant only if it is located downstream of
the point of production for gas (15 AAC 55.900(b)(7).
Under the definitions in the bill, it will no longer
matter whether a facility is a "gas processing plant."
All four of the North Slope facilities will continue
to be characterized as conducting "gas processing,"
which will be upstream of the point of production for
gas.
Under the proposed definitions, plants removing CO2
and H2S from gas for delivery to a sales line, which
in the sponsor group proposal is assigned to a new Gas
Treatment Plant (GTP), would be a new Gas Treatment
Plant.
3:42:50 PM
SENATOR BEN STEVENS asked to go back to question 22. He asked if
the Pt. Thomson facility would be built the same as other North
Slope facilities using gas processing and Prudhoe Bay so they
would all be functioning the same.
MR. DICKINSON replied yes - at the outlet of those plants. "If
there is gas processing going on in the plants - if that's where
the separation between the stream that become gas and the stream
that become oil." He said the definition has four
characteristics, but he was trying to line them up the same.
3:44:49 PM
SENATOR SEEKINS apologized for arriving late and asked if the
point of production is where a future pipeline would begin and
if the tariff costs start at that point with deductible costs
under the PPT behind that point.
MR. DICKINSON replied yes and added that that's how it works for
oil now. The problem with gas is that it has traditionally been
sold with lots of liquids still in it and the state doesn't have
a clean definition of pipeline quality being transferred to it.
The notion is that the last step needed to get ready for
pipeline quality is now being called "gas treatment." So, the
gas treatment plant would be tariffed and PPT type credits would
not apply for it. The point of production would be at the
boundary where you were entering gas treatment, anything
upstream would be upstream of the point of production and would
be gas processing; all the PPT benefits, credits and deductions
would apply.
SENATOR SEEKINS asked if the dehydration plant is all PPT
deductible. He asked if the envelope could carry the liquids and
those get stripped out for some other reason, is that stripping
plant deductible.
MR. DICKINSON replied that gas processing in general would take
out the valuable liquids. People would make economic decisions
about them. Now they are put in TAPS and that will continue to
happen, in general, because transforming them into oil is their
highest value. If a gas line is built and enters into an
integrated system someplace down the road at a "straddle plant"
that pulls out methane or butanes, those decisions will be made
at the time. He said the heavier hydro-carbon liquids will be
stripped out to make it pipeline quality.
SENATOR SEEKINS asked if that straddle plant would be deductible
under the PPT.
MR. DICKINSON replied the building of the plant would not be
eligible for a credit; it would be deductible as a
transportation cost when the gas that was stripped out will be
valued, but it will be on the same basis as a pipeline or
tanker.
SENATOR SEEKINS said he wanted a good idea on where the
deduction on the PPT ended and where the tariff on gas began.
MR. DICKINSON finished answering question 23 saying that gas
treatment is where CO2 and H2S are removed. There may be some
use for those for enhanced oil recovery, but on the other hand,
it could be a big problem and the question is how to deal with
it. "But it's going to have to stripped out before it goes into
the pipeline."
He skipped ahead to question 27.
3:48:46 PM
27. How will AS 43.55.160(j) protect the state from a
proliferation of corporate entities and/or companies claiming
the tax-free allowance? (He explained these are standards that
the commissioner uses to determine whether a company qualifies
for the $73 million allowance.)
AS 43.55.160(j) does not establish a maximum number of
companies entering the market that could utilize the
standard allowance. However, this section requires
that the Department of Revenue evaluate each company
claiming the deduction, on an annual basis, to
determine if the company qualifies for the deduction.
This section goes on to require the company to show
that it has not split operations or property ownership
among multiple entities in order to gain usage of
multiple $73M deductions, when only one deduction
should have been granted.
3:49:35 PM
SENATOR SEEKINS asked if Seekins Oil Company has a standard
deduction and joint ventures with a new company, does he get an
additional deduction through that joint venture.
MR. DICKINSON replied that the difficulty is going to be that
joint ventures are an economic fact of life and the state isn't
trying to warp that situation. If a joint venture were created
without creating a new entity, that wouldn't occur.
SENATOR SEEKINS asked if he would get it if he were under a
corporate structure of a new company as a shareholder.
MR. DICKINSON replied that is the nub of the issue. "Whatever
rules we set up, you'll probably find folks who wanted to avoid
them taking it one step further." So, the standard was set up so
that the commissioner could look at the transaction and
determine whether a company has demonstrated it has intended to
simply split value to take advantage of that allowance, and he
wouldn't allow it.
3:51:02 PM
SENATOR ELTON followed up asking if this would be further
defined in regulations or does the department or commissioner
apply an ad hoc process.
MR. DICKINSON replied that whether it becomes a regulatory issue
or not depends on the activity. If there were a whole lot of
controversial claims, regulations would be written or the
legislature may chose to revisit it.
3:51:55 PM
29. Provide estimates for undiscovered resources in Alaska.
Include the breakdown between technically recoverable and
economically recoverable resources to the extent possible.
Resources estimated are those that would enter the
TAPS north of the Brooks Range. These include
estimates of recoverable oil from the National
Petroleum Reserve - Alaska [NPRA], the Central North
Slope, the Beaufort Sea and the Alaska National
Wildlife Refuge [ANWR]. Estimates are presented in
terms of barrels of technically and economically
recoverable reserves. Technically recoverable
estimates are mean estimates. Economic recovery is
based upon the Department of Revenue [DOR] long term
forecast of Alaska North Slope [ANS] crude oil
delivered on the west coast at $25.50 per barrel in
nominal terms.
For purposes of analysis, all economically recoverable
oil is presumed to be produced by 2046 [within 45
years]. Estimates are obtained from United State
Federal government sources - the United States
Geological Service [USGS], the Minerals Management
Service [MMS] and the Energy Information
Administration [EIA].
Technically Economically Natural Gas:
NPRA 10.6 Bbl 2.95 Bbl 59.7 Tcf
Central North Slope 3.98 Bbl 0.88 Bbl 35 Tcf
Beaufort Sea 6.94 Bbl 1.79 Bbl Remainder plus
existing PBUANWR 10.40 Bbl 4.21 Bbl
Total 32.38 Bbl 9.83 Bbl 200 Tcf +
. NPRA - The entire area is estimated to contain 10.6
billion barrels of technically recoverable oil.
Economically recoverable reserves consist of 2.95
billion barrels of oil.1 (U.S. Geological Survey,
2002, Petroleum Resource Assessment of the National
Petroleum Reserve in Alaska (NPRA), USGS Fact Sheet
045-02, Table 3 and Figure 7).
. Central North Slope - The technically recoverable
yet-to-be-discovered barrels of oil are estimated at
3.98 billion. Economically recoverable reserves are
set at 0.88 billion barrels (USGS, 2005, Economics of
Undiscovered Oil and Gas in the Central North Slope,
Alaska, Open-File Rpt 2005-1276, Table 5)
. Beaufort Sea - There are 6.94 billion barrels of oil
technically recoverable. Economically recoverable
reserves during the period under consideration are set
at 1.79 billion barrels, the mean estimate at lower
oil prices. (Mineral Management Service, Beaufort Sea
Planning Area Oil and Gas Lease Sales 186, 195, and
202 OCS FEIS, 2003, MMS 2003-001, Appendix B, Table B-
1)
. ANWR - There are 10.4 billion barrels of technically
recoverable oil. Economically recoverable reserves
consist of 4.21 billion barrels. (Energy Information
Administration, Analysis of Oil and Gas Production in
the Arctic National Wildlife Refuge, March 2004, pg 5
and Table 1)
. Natural Gas - Most natural gas that is technically
recoverable is considered economically recoverable
provided there is a means of transmission to market.
Assuming gas flow through a pipeline beginning in
2015, the period through 2046 production totals 49.6
trillion cubic feet. Best estimates of natural gas
reserves on the North Slope far exceed this amount and
include: proven reserves - 35 trillion cubic feet
within Prudhoe Bay Field, Pt. Thomson, and other
fields (EIA, March 2004), NPRA - 59.7 trillion cubic
feet (USGS Fact Sheet 045-02); and, together with ANWR
and offshore undiscovered reserves totals above 200
trillion cubic feet (USGS, Conventional Natural Gas
Resource Potential, Alaska North Slope, 2004, Rpt
20041440).
The studies also set ranges for technically
recoverable oil with a 5 percent and 95 percent
confidence interval. These wide ranges are presented
below. Economically recoverable estimates were based
on 2001 dollars so that $23.50 equates to
approximately $25.50 in 2005 dollars.
Recoverable oil volumes will vary by price of oil.
However, higher valued oil will also be higher cost
oil to produce with each increase in price resulting
in increased volume strictly related to the cost of
production.
Range of Technically Recoverable Oil - 5th Percentile
Mean 95th Percentile:
NPRA 5.90 Bbl 10.6 Bbl 13.20 Bbl
Central North Slope 2.87 Bbl 3.98 Bbl 5.85 Bbl
Beaufort Sea 3.56 Bbl 6.94 Bbl 11.84 Bbl
ANWR 5.70 Bbl 10.40 Bbl 16.00 Bbl
3:54:03 PM
31. How will Net Profit Share Leases (NPSL's) be affected by
this legislation? Will the gross costs of exploration and
development go into the Development Account - or those costs'
net of the credits and deductions?
Production taxes are currently deductible for NPSL
purposes. This legislation is not intended to change
the deductibility of the production tax. However, NPSL
leases are administered by the Department of Natural
Resources, which is better equipped to address these
questions and which we understand is doing so. Also
see Question 58.
3:55:01 PM
33. Of the pre-PPT credit provisions (or claw back), what is the
cost to the state for legacy fields and what is the cost to the
state for frontier regimes?
Also see Question 20. The assumption made for this
request is that the Pre-PPT cost claw-back will be the
last adjustment made to the tax. All other deductions
and credits allowed under the PPT will have been
exercised. There was approximately $4.8 billion of
capitalized investment made by the industry during in
the period 2001 through 2006.
Using the Department of Revenue price forecast, which
has prices falling and remaining below $40 after 2008:
. Legacy Field Owners: $316.6 million
. Frontier Field Owners: None. Due to no production or
the inability to generate revenues sufficient to have
a tax liability after other deductions or credits are
taken.
Assuming a flat price of $45 for 2007-2050:
. Legacy Field Owners: $935 million
. Frontier Field Owners: 15 million
. Total $950 million
Assuming a flat price of $60 for 2007-2050:
. Legacy Field Owners: $936 million
. Frontier Field Owners: 15 million
. Total $951 million
3:56:12 PM
49. What is the estimated economic impact to the state of the
ability to sell tax credits?
He advised them to focus on page 21 that had a summary
of costs he used in modeling what happens. The very
conservative estimate, which is without a gasline and
without any additional fines, no additional oil
outside of the department's forecast, he sees total
capital spending at around $25 billion. On the other
extreme, if the gasline gets built and there is a lot
of additional exploration, the number would be more
than twice that at $55 billion.
The next question people focused, he said, was on
saturation and what would happen with the credits in
the marketplace. Will the credits be used up or will
they "go begging," will the small producer not really
get the effect of the credits, because they can't do
anything with them. His analysis, which used a $40 per
barrel price, showed how much of the production tax,
itself, would be reduced by credits and depending on
which scenario is used, it went from a low of about 25
percent to a high of close to 40 percent, but in no
case did he find that the market would become
saturated. He said the sensitivity analysis was run
with a 95 percent production by the majors and room
was found for them to be used even if the producers
have most of payments and the smaller users have 25
percent of the credits. Saturation might occur if the
price was much lower than $40.
3:59:16 PM
54. Section 21, page 13, line 8 - why is this clause constrained
by Dec. 1, 2005?
This constraint is intended to avoid industry changing
cost allocations in contemplation of this legislation,
in order to avoid taxation.
4:00:20 PM
68. How is it possible that any corporation gets triple the sale
price for a commodity, having invested capital at the expected
lower returns, and then maintains that they need a claw back
provision? Why should we offer it?
a. The first part of this question appears to be
intended to be answered by oil companies.
b. We should offer a transition deduction because we
are converting from a tax on gross to a tax on net
value. When measuring net value, it is necessary to
allow deductions, not only for current expenses, but
also a deduction for the capital investment that is
generating the value. For new assets acquired after
the PPT is in effect, a full deduction for the cost
the capital investment is allowed in the year
acquired. Assets acquired within the last five years
are currently producing taxable oil and gas, and a
deduction should be allowed for, in effect,
depreciation on those assets.
4:01:09 PM
69. Please show us an international competitiveness rank and
score for PPT under the following tax/credit scenarios, both
overall and for new producers:
a. 30/15
b. 30/20
c. 25/20
d. 20/20
MR. DICKINSON explained that Dr. Pedro Van Meurs
formulated this question that has as its answer a
bunch of tables. However, he explained that he ran his
competitiveness rankings, basing those on the four
different scenarios (above). His analyses were for the
large producer economics and for the new investors.
The conclusion is that the PPT puts the state in a
better position internationally among the peers that
he ranks than the current system does. This is true
for the larger producer economics and especially true
for the new investor economics.
4:02:48 PM
SENATOR STEDMAN asked if anything in his tables would put Alaska
at a competitive disadvantage.
MR. DICKINSON replied the short answer is no; but the ones with
the more ambitious tax credits place the state in a better
position than the ones that have either the lower credits or the
higher tax rates. He suggested that the overview on page 32 was
the best way of looking at that. No matter which scheme you look
at, things look more attractive to the new small investor and
lot of that has to do with their focus on the credits and the
allowance. The large producers, at 20/20, you can expect more
investment; at 25/20 you can expect the same and as you start
going to 30 percent rates, you can expect either less and a 30
percent tax rate coupled with only a 15 percent credit is much
less. The legacy fields would feel the sting of the marginal tax
rate more; the new companies would feel the benefit from the
incentives.
4:05:48 PM
SENATOR ELTON asked if there has been some controversy about
investment in the UK North Sea being treated differently.
MR. DICKINSON replied that he would tiptoe around that one. He
said that UK had made some dramatic changes recently to its
methodology and just weeks ago essentially doubled the rate.
There is debate about its effects.
^Department of Revenue - Roger Marks and Cheri Nienhuis
CHERI NIENHUIS, Petroleum Economist, Department of Revenue
(DOR), said that Roger Marks, Petroleum Economist, DOR, was also
online.
4:09:02 PM
She recapped that she had answered only question 70 that asked
for the annual oil severance tax amounts at various prices and
for various scenarios. When she answered it she didn't have the
numbers presented beside the chart. She had also run additional
scenarios with 15/20, 25/20, 15/25, and 22.5/22.5. The packet
contained all the runs.
CHAIR WAGONER said they have the information and can review it
later.
4:14:31 PM
MS. NIENHUIS summarized information at $40 a barrel for a frame
of reference. She compared severance tax revenues that would be
collected from 2007 - 2030 with the status quo and found for
15/25 that it was 21 percent greater; for 15/20 it was 36
percent greater; for 20/20 it was 100 percent greater; 22.5/22.5
was 126 percent greater; 25/25 was 151 percent greater; 25/20
was 165 percent greater; 30/20 was 230 percent greater; and
30/15 was 245 percent greater than the status quo.
SENATOR STEDMAN asked if she was more comfortable with the
analysis between the first 10 years versus the last 10 years for
professional estimating values.
MS. NIENHUIS replied that the reason 2030 is the time frame used
is because that is the period in which it is believed the TAPS
would either shut down or the North Slope will shut down.
She said the House Resources committee also wanted to know what
the difference would be in annual severance tax with just an
incremental 1 percent change in both the tax rate and the credit
rate. That relevant chart was 70(i) and it compares the status
quo with a 19/20, 20/19, 20/20, 20/21, and 21/20. She also ran
another graph to illustrate the difference between a 1 percent
tax rate increase or decrease and what a 1 percent credit rate
increase or decrease would amount to. She found a 1 percent tax
rate increase impacts the severance rate at a $40 level quite
significantly by a 5 to 1 ratio. So every 1 percent tax increase
was equivalent to about a 5 percent credit decrease. "So, the
tax rate is significantly more important based on this analysis
than is the credit rate." She added that the ratio decreases
closer to 2030 because of the projected decrease in production.
MR. DICKINSON said that the tax was very price sensitive because
the credit is going to be $1 of spending whereas the tax rate
would be on a $1 of profit. So if there were $1 billion of
spending a year, at $20 oil with $5 profit, if you double the
price, the size of the credit will still be precisely the same.
MS. NIENHUIS said that Daniel Johnston also said that it would
be a 5 to 1 ratio.
4:18:33 PM
SENATOR BEN STEVENS remarked that Mr. Johnston said the tax rate
was inelastic and the elasticity was in the credit rate.
SENATOR STEDMAN responded that wasn't right; he said the tax
rate is the sledge hammer and the credit is the tack hammer.
SENATOR BEN STEVENS agreed with that, but he thought he heard
Mr. Johnston say that the tax rate was inelastic in relation to
investment. He said he would check on it.
4:19:59 PM
MS. NIENHUIS continued saying that 70(j) was a summary table
showing the effective tax rate for all scenarios. They were all
price sensitive except the status quo. For this example, she
explained, the way the average effective tax rate was calculated
by taking the severance tax liability and dividing it by the
gross well-head value less the royalty. This makes an apples to
apples comparison with the status quo tax, which is a tax on
gross revenues, less royalties.
4:21:04 PM
SENATOR BEN STEVENS found Mr. Johnston's statement that was
contrary to what MR. DICKINSON said. On page 13 of his testimony
on March 6, "I believe there is a strong evidence that producing
activities are relatively unaffected by changes in the tax rates
unless they are dramatic."
MR. DICKINSON replied that he said something different, but he
had no opinion on the elasticity issue, which is what happens if
you change one thing. He was focused on a the mathematical point
that the amount of the credit, 1 percent change in the credit,
would not have any relationship to price, whereas a 1 percent
change in the tax rate would be dependent on price.
SENATOR BEN STEVENS said he understood now.
SENATOR STEDMAN recalled that the point Mr. Johnston was trying
to make was that at a 20 or 25 percent tax rate, he didn't
expect a significant change in what the majors produce on the
North Slope.
4:24:00 PM
SENATOR ELTON said Econ One added, what they called, a historic
line of 12 percent for the historic tax rate. He asked if she
agreed with that number.
MS. NIENHUIS replied that she hadn't looked at it, but believed
it to probably be accurate and she referenced page 43 that had
the effective tax rates for the North Slope by field since
FY'86.
MR. DICKINSON added that she was referencing page 43, question
30, Table (a). He walked them through an example. In 1988,
Prudhoe Bay was 1.6 million of the 2 million barrels of
production. In that year, the Prudhoe ELF was 12.66 percent. The
only other field of any major size was Kuparuk at close to
200,000 barrels a day for 8.33 percent. If you average them all
together, you get something in the 11 to 12 percent effective
tax rate range. Before the aggregation decision and with 1
million barrels of production in 2004, Prudhoe Bay represented
400,000 of that although 50,000 of that would be gas (and,
therefore, not part of the ELF). Alpine and North Star,
combined only produce as much as Kuparuk that had an effective
tax rate of 2 or 3 percent.
He advised if they are asking for the average tax rate on the
North Slope, because of the ELF, you need to get the dates.
4:27:57 PM
SENATOR BEN STEVENS thanked him for that explanation. He said
the reason it stayed so high was because it included the years
of massive production. The chart that was presented yesterday
went back to 1977 at the beginning of production, but they can
only accurately use charts 10 years out. If you go 10 years
forward, you should just go only 10 years back. Mr. Dickinson
just said that the historical effective rate would be
dramatically different depending on the number of years it went
back. So, he asked to see the numbers for average historical
rate in 10-year increments.
MR. DICKINSON responded that made sense and he could produce
that.
SENATOR STEDMAN pointed out that Econ One's figures were based
on a forward projection of ELF on status quo.
MR. DICKINSON agreed with that and so did Senator Ben Stevens.
4:31:29 PM
SENATOR BEN STEVENS said he was trying to clarify that included
in the historical numbers were years when the state was at full
capacity and production.
And I think if we ever got to that again, those would
be the numbers we should use, but we're not talking
about full capacity and full production; we're talking
are talking about maintaining existing production,
which is one half or less than 40 percent of what it
was at one point. So, I think that we have to use
historical figures in context of where we're going to
go into the future.
MR. DICKINSON observed that Econ One pointed out that these
rates are not historically unprecedented.
What is historically unprecedented is the level of
support that the Governor suggested we make to the
industry in the future work going on on the North
Slope. And I think if you look at when these rates
were at this rate, it was Prudhoe Bay. Prudhoe Bay was
the entire story with Kuparuk...
4:32:58 PM
MS. NIENHUIS moved on to question 71. Please show the corporate
take chart on page 24 of Mr. Marks' presentation given the
following tax/credit scenarios:
a. 25/20
b. 30/20
c. 30/15
d. 15/20
e. 25/25
f. 15/25
g. 22.5/22.5
She said this chart was slightly different and has the status
quo presented next to the PPT under each of the scenarios. Mr.
Marks used the EIA forecast, which is an average of $57 a barrel
through 2040.
MR. MARKS corrected her saying, "I think it's 20/50."
MS. NIENHUIS said the charts were high volume and most of the
costs remained the same. They showed primarily the difference in
the state take (royalties, corporate income tax, severance tax
and property tax (which stays fairly steady throughout)), but
also the difference in the federal tax and the difference in the
corporate take.
4:35:03 PM
MR. DICKINSON explained that the royalty and production tax
stays the same, but the modeling shows increase in the severance
tax and with the diminution in both federal take and corporate
take.
MS. NIENHUIS said that was correct. For 25/20 with the
cumulative revenues were $580 billion (gross revenues), the PPT
produces about 28 or 29 percent for the corporate take. There is
a fairly large difference between the severance tax collections
in the two scenarios between status quo and the PPT.
4:36:10 PM
The next slide considered 30/20 and has the corporate take
significantly down to $155 billion from the previous one of $164
billion, a higher state take overall and a commensurate decrease
in federal tax. This is due to the fact that severance taxes are
deductible for federal tax purposes. Since the severance tax is
higher in the PPT than under the status quo, that has an effect
on the federal tax, as well.
The next chart showed the same information for the 30/15
scenario. It has slightly less in the way of corporate take and
slightly more in the way of severance tax.
The next one, 15/20, was a little different. Even at that rate,
the severance tax is significantly higher than the status quo
and a fairly high corporate take, as well.
The next was 25/25 had significantly more severance tax, about
four times more than the status quo.
The next one was 15/25 showed the corporate take to go up quite
a bit, but the federal tax was not that much different than
under the status quo. The severance tax was up over the status
quo.
Lastly, 22.5/22.5 was close to the 20/20 in terms of total
revenues to each entity. Close to 30 percent of gross revenues
to the corporations and about $55 billion to severance tax.
4:39:30 PM
72. Please show the price point where DOR estimates corporate
profit margins hit:
a. 15 percent
b. 20 percent.
MS. NIENHUIS said the question was made in the context
of the presentation of these charts and she understood
the question to be show where on the chart the
corporate take is 15 and 20 percent. That would not
necessarily represent a profit; that would be the 15
percent of the gross revenues. So, actually the profit
would be minus the Opex and the Capex costs,
transportation and et cetera. It's true that $20 a
barrel is a problem for the state no matter what tax
system you go with. In Chart 72(a)(1)she showed that
$20.15 per barrel was the price at which the corporate
take is 15 percent; it shows the state take to be
quite low at that amount. For clarification she said
the total cumulative revenues of this chart is $100
billion including costs.
4:41:36 PM
At a high volume scenario the same corporate take has
some additional costs associated with it because the
high volume scenario has the heavy oil that would come
on line as well as the gasline. The price at which the
corporate take is 15 percent under this scenario would
be $27 per barrel ANS. It showed a cumulative revenue
of $283 billion.
The next question was price does the corporate take go
to 20 percent under the low volume scenario without a
gasline and she showed that it would be $24.50 a
barrel ANS. The state takes less revenue at this
amount than under the status quo.
She used another high volume scenario to answer what
price would the ANS per barrel have to be for the
corporate take to be 20 percent. She got an average of
$32 per barrel ANS.
4:43:45 PM
90. Please show the cumulative production tax from 2007-2030
under the PPT given the following tax/credit scenarios:
a. 25/20
b. 30/20
c. 30/15
d. 15/20
e. 25/25
f. 15/25
g. 22.5/22.5
h. A summary chart showing all above scenarios
i. A summary table showing all above scenarios
Her first slide started with 25/20 and a low volume
scenario; the crossover point was $24. The crossover
point for 20/20 was $26.50 per barrel.
4:44:38 PM
The low volume scenario for 30/20 had a crossover
point at $22 a barrel ANS. It rises fairly steeply
past $25 a barrel.
The low volume scenario for 30/25 had a crossover
point of $21 a barrel. For 15/20, it was at $34 a
barrel. She said that several of the scenarios don't
generate much revenue at prices below $25 - $35. The
scenario for 25/25 had a crossover at $25. At 15/25,
the crossover point was at $36 per barrel. The 20/20
stays high above the 15/25. The crossover on 22.5/22.5
was $26 a barrel and it behave very like the 20/20.
The last slide addressed question 90(i), which shows
what the cumulative tax revenues would be at the
different prices in the graphs she just presented.
4:47:40 PM
ROGER MARKS, Petroleum Economist, DOR, commented on the status
quo $20-dollar column in question 90(i) indicates the state
would get only $123 million per year in revenues with which to
cover its budget and at that point it would have bigger problems
then having chosen the wrong combination of taxes and credits.
He advised that worrying about how much money you lose at the
low end under $20 is probably not a real fruitful exercise and
it was pathetic. That doesn't mean prices couldn't be $20; but
it does underscore the need for broad-based taxes. At $20, the
state would need more than the oil industry to keep it afloat
and the CBR (Constitutional Budget Reserve) would be just a
pleasant memory especially if the prices were low for as long as
a couple of years.
4:50:14 PM
MR. DICKINSON jumped back to page 34, questions 73, 74, 76. They
all related to the Cook Inlet analysis. The first question
analyzes it under the proposal. The second question is how much
does the $73 million allowance play in that and the third
question is what happens to a new player. His answer was:
If we look under the current analysis and the
assumption - and this is the big one in the Cook Inlet
- What happens to gas prices if you assume that they
move towards world prices, then, in fact, you will see
the folks that have gas paying a PPT. If you don't
move towards world prices and you stay in the $2 - $3
range, then you will find the folks that have the gas
are not paying the PPT. So, fundamentally, the
question here is not so much a PPT question as right
now there's one contract between Enstar and Unocal
that uses world pricing, if you will, or US pricing.
Most other contracts are at much lower rates. Cook
Inlet has been isolated for markets. Essentially you
have ConocoPhillips selling on a world market, but
aside from that it's been internal use and the prices
reflect that.
MR. DICKINSON contended that if they go to world prices in
around the $7 range, the ELF would not be appropriate at
that point and the PPT would have to be there.
Moving on the second question: What happens when the $73 million
allowance comes in. He analyzed this specifically going
backwards, which brings with it the assumption of low prices.
Without the allowance there would be a small increase; with the
allowance they would see about the same or a diminishing of the
take. His finally conclusion was with just the $73 million
allowance and isolating Cook Inlet, at low prices they would see
a significant production tax being paid under the PPT.
4:53:23 PM
76. Model a newcomer to the Cook Inlet that explores for, finds,
develops and sells gas. What will their taxes look like under
the status quo and the PPT?
It is impossible to answer this question with any
accuracy because of the numerous assumptions one would
have to make. Generally, a newcomer to Cook Inlet
would spend at least a couple of years exploring for
gas, and during this time, would presumably not
produce any gas and in fact may not realize any income
from these operations. So for the years of exploring,
the newcomer would not pay any tax under either the
status quo or the PPT system. Under the PPT system,
the newcomer would have earned capital credits in the
first couple of years that they could either hold or
sell, as well as any loss carry-forwards they may have
accrued. The question is if they are selling at world
market prices, they will use those capital credits up
very quickly. If they are selling in the $3 range,
those credits will give them a shield for a number of
years. After the credits have been used and monetized,
they still have the $73 million. So if a player was
generating less than that, as they do in the Cook
Inlet, they are covered and not paying additional tax.
4:54:24 PM
78. Could we look at (1) a standing offer to purchase tax
credits for 10 percent of their face value - with the
implication that the department could treat that as a receipts
funded program so that the legislature would not have to
authorize the purchase amount and (2) "Alaska bucks" - i.e.
allow credit certificates to be used in lease sales or other
lease acquisition activities as cash.
He answered that basically rather than having a
buyback, the state would make the credit refundable.
The state could set a limit on the refund. The total
credits are going to represent between 25 - 30 percent
of the revenues, so if some of those are purchased
rather than taken, the net effect on the state is the
same. The notion here was why let a market player
intervene and get 10 or 15 cents on the dollar.
If value is added to them by allowing them to be
reinvested or used for a lease sale or make them 110
percent, that is a policy call by the legislature. How
equal it wants the people who are bidding to be is
another issue. Perhaps they would want to incent
someone who has worked here before versus someone who
is coming up for the first time. He advised to steer
clear of having any incentives built in to the process
of acquiring the leases and they have focused on
getting them on the process of developing those.
4:56:58 PM
79. Could we draft up alternative standards for the anti-hiving
provision so the legislature can choose.
ROBERT MINTZ, Assistant Attorney General, Department
of Law, answered if multiple entities take advantage
of the allowance, that means that one entity would
have to be producing and it would have to get some
kind of benefit in return for that. That was the
trigger for the approach that the department will
disallow an allowance deduction if it finds that a
benefit attributable to a producer's allowance is
shared with or enjoyed by another producer. This
concept might be more effective if it were adopted as
a supplement to, rather than a substitute for, the
current language in proposed AS 43.55.160((j).
4:59:46 PM
MR. DICKINSON said question 81 was a request to share the model
and he declined to do that, but fundamentally, his experience is
that this model is not user-friendly and only a handful of folks
know how to use it. He vowed to help people get answers to their
questions.
5:00:34 PM
Skipping ahead, he went to a sequence of questions on what is
the meaning of progressive tax. What is proportional and what is
marginal?
Black Law Dictionary said that a progressive tax is a
tax structured so that the effective tax rate
increases more than proportionally as the tax base
increases. Clearly how the tax base is measured has
caused some confusion. The tax base could be the net
or the gross. The confusion has arisen in trying to
restate the PPT, which is a tax on the net, in terms
of gross to make it comparable to the ELF. On one of
them, estimates for capital costs would have to be
made, and the department has actuals on the gross
going backwards.
SENATOR STEDMAN asked what his conclusion was.
MR. DICKINSON replied, "A progressive tax is one in which
wherever you measure your base, and as your base changes, does
the rate change more quickly than the base - not nearly in
proportion to it."
5:02:36 PM
SENATOR STEDMAN asked if they were looking at percentage changes
of the total pie as the dollar value went up.
MR. DICKINSON replied that he believed it could be measured as a
change in the percentage or as a change in the total dollars.
"The main thing is you need to be consistent about which one you
are measuring as the total of one goes up, the total of the
other goes up more quickly."
SENATOR STEDMAN said he didn't necessarily agree with that.
CHAIR WAGONER said he would let the two of them get together
later on that issue.
MR. DICKINSON responded that he has seen folks do it both ways.
5:04:03 PM
93. What is the meaning of the term "marginal tax rate," which
is the rate of tax applied to the last dollar of the tax base?
He explained that according to WG&L Tax Dictionary
(2004), a marginal tax rate is, "The rate of tax
applied to the last dollar of the tax base."
Therefore, if a tax is based on net income, a marginal
tax rate is measured based on the last dollar of net
income. This is most often found in income tax law
such as AS 43.20.011 where the top marginal rate is
9.4 percent and this tax rate is applied to amounts of
Alaska corporate taxable income over $90,000.
5:04:33 PM
94. What is the meaning of the term "effective tax rate?"
In general, whenever there are several factors at play
this measure cuts through all their effects and
typically divides the tax paid by some measure. For
example, an income tax, the effective tax rate is
normally expressed as the actual income tax paid
divided by taxable income, expressed as a percentage.
For example:
Gross income: $100
Less deductions: ($90)
Net income: $ 10
Tax at 20 percent: $ 2
Less credits: (1)
Tax due: $1
He explained that in this example, the effective tax
rate is 10 percent, which compares the $1 tax due with
the taxable income of $10. In Question 30, earlier,
the effective production tax rate was the percentage
of gross revenue without taking exploration credits
into account.
5:06:24 PM
95. Please differentiate the definition of "exploration,"
"development," and "production."
He noted that, in general, the bill provides the same
tax treatment to oil and gas exploration, development,
and production. In other words, it generally makes no
difference whether an expenditure is for exploration,
or for development, or for production, and it was
therefore not felt necessary to define the terms in
the bill. The terms exploration, development, and
production are addressed in FASB (Financial Accounting
Standards Board) Current Text Standards say:
Exploration involves identifying areas that may
warrant examination and examining specific areas that
are considered to have prospects of containing oil and
gas reserves. Exploration costs include drilling
exploratory wells and exploratory-type stratography
test wells. The principal types of exploration costs
include costs are topographical, geological, and
geophysical.
5:07:22 PM
SENATOR ELTON asked he would have thought lease costs would be
an exploration cost.
MR. DICKINSON responded that he didn't believe lease costs were
considered exploration costs. Lease acquisition costs are
usually separate and distinct from exploration costs.
5:07:59 PM
ROBYNN WILSON, Director, Tax Division, DOR, said that Mr.
Dickinson was correct.
MR. DICKINSON added that development costs are what is necessary
to get the reserves, delineate them, figure out what is there,
provide the facilities for getting them up, treating extracting,
gathering, storing. The kinds of costs for typical
infrastructure costs would be road building, power lines,
drilling, platforms, the casing, the tubing, the equipments.
Once that development has occurred and the investment has been
made, the last category is production and that involves the
actual lifting to the surface, gathering it, storing it, and
getting to market. Production costs, operating costs,
maintenance costs, replacement like labor to operate the wells,
repairs, maintenance, material, supplies and the fuel consumed
to operate the wells.
5:08:32 PM
SENATOR ELTON said he mentioned something that was not included
in the written answer - getting it to market is not listed as a
production cost.
MR. DICKINSON replied that he meant getting it ready for market,
typically an E&P that would turn it over to a midstream company
that would have transportation. Senator Elton was correct, a
pipeline would not be considered production.
There being no further questions to come before the committee,
CHAIR WAGONER adjourned the meeting at 5:10:10 PM.
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