Legislature(2005 - 2006)BUTROVICH 205
03/07/2006 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB305 | |
| Department of Revenue - Michael Williams, Chief Petroleum Economist | |
| Administration - Dan Dickinson, Cpa | |
| Department of Revenue – Robynn Wilson, Director, Tax Division – Addressed Legislature’s Questions – with Dan Dickinson | |
| 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 7, 2006
3:39 p.m.
MEMBERS PRESENT
Senator Thomas Wagoner, Chair
Senator Ben Stevens
Senator Fred Dyson
Senator Bert Stedman
Senator Kim Elton
Senator Albert Kookesh
MEMBERS ABSENT
Senator Ralph Seekins, Vice Chair
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
WITNESS REGISTER
MICHAEL D. WILLIAMS, Chief Petroleum Economist
Tax Division
Department of Revenue
550 West 7th Avenue, Suite 500
Anchorage, AK 99501-3566
POSITION STATEMENT: Testified on SB 305 and answered questions.
DAN DICKINSON, CPA
Consultant for the Governor
Office of the Governor
PO Box 110001
Juneau AK 998811-0001
POSITION STATEMENT: Testified on SB 305.
ROBYNN WILSON, Director
Tax Division
Department of Revenue
PO Box 110400
Juneau, AK 99811-0400
POSITION STATEMENT: Presented Questions and Answers relating to
SB 305.
ACTION NARRATIVE
CHAIR THOMAS WAGONER called the Senate Resources Standing
Committee meeting to order at 3:39:25 PM. Present were Senators
Ben Stevens, Bert Stedman, Fred Dyson, Kim Elton and Chair
Thomas Wagoner; Senator Kookesh arrived shortly thereafter.
SB 305-OIL AND GAS PRODUCTION TAX
3:39:25 PM
CHAIR WAGONER announced SB 305 to be up for consideration. He
noted the committee would begin with hearing a presentation from
the Department of Revenue.
^DEPARTMENT OF REVENUE - Michael Williams, Chief Petroleum
Economist
3:41:08 PM
MICHAEL D. WILLIAMS, Chief Petroleum Economist, Tax Division,
Department of Revenue (DOR), gave some personal background and
said he would speak about future crude oil production volumes in
Alaska. First, however, he would address earlier forecasts.
SENATOR KOOKESH arrived at 3:41:08 PM.
MR. WILLIAMS showed a slide labeled "Fall Oil Production
Forecasts," pointing out that with the exception of one data
point on the graph, forecasts have overestimated production in
Alaska. There are two reasons. First, the Prudhoe Bay field,
having produced for close to 30 years, is subject to problems
associated with an aging field such as leaks in pipelines and
second, the North Slope's viscous oil requires new technologies
to develop. Many of these projects have been delayed as a
result. The department's forecast for heavy oil production
reflects this delay.
3:44:53 PM
In the near term, DOR has incorporated revised reservoir-
performance analyses for declining fields, reviewed the
uncertainty associated with the pace and scope of developing
satellite fields and reevaluated unplanned downtime at all
fields, especially Prudhoe Bay. This resulted in an average net
reduction of about 30,000 barrels a day a year over the next
five years. Roughly half this reduction relates to reservoir
performance and facility downtime; the other half relates to the
pace of development of heavy oil, primarily at West Sak. The
forecast for ANS production averages slightly above 800,000
barrels a day for FY 07 through FY 11.
He explained that ANS crude oil production is characterized in
three ways - 1) currently producing, 2) currently under
development and 3) currently under evaluation - each with a
discrete estimated confidence level. Highlighting the
uncertainty of production forecasting, Mr. Williams indicated
DOR continues to forecast production of only reserves that have
already been discovered and that are being evaluated for
development.
MR. WILLIAMS showed a graph labeled "ANS Historical & Forecast
Production: Millions of Barrels per day, FY 1978-2005 & FY
2006-2016" and said the "currently producing" category includes
baseline production and presumes a continued level of
expenditure sufficient to promote safe, environmentally sound
operations.
3:47:50 PM
He noted such expenditures include well diagnostic and remedial
work, in addition to data acquisition and rate-enhancing
expenditures such as perforating and acid stimulation, well
work-overs, fracture treatments, artificial lift optimization
and production-profile optimization. This category presumes
continued gas and water injection for pressure support. Based
on historical forecasting performance, DOR assigns a 98 percent
confidence level for the current fiscal years.
He next addressed the "under development" area on the graph,
which is based on new projects currently funded and in the
design or construction phase, as well as development drilling
and enhanced oil recovery, whether miscible or immiscible,
injection projects currently funded or underway. It doesn't
include those same projects if they are in the "currently
producing" category. It also includes incremental oil expected
from the long-term gas cap water-injection project at Prudhoe
Bay and the low-salinity water flood at Endicott. Examples of
production under development include the Fiord and Nanook
satellite fields at Alpine, the remaining J Pad development at
West Sak, development drilling at Schrader Bluff and certain
satellite developments at Prudhoe Bay.
He reported that the pace of development at all heavy-oil fields
has been slowed to allow proper mitigation of challenging
commercial and technical issues. Because of timing and scope
uncertainty, Mr. Williams said, DOR's subjective confidence for
this category of production is lower, 80-85 percent.
He turned to the "under evaluation" category on the graph,
noting it includes technically viable projects currently in the
"pencil sharpening" stage where engineering costs, risk and
reward are being actively evaluated. Although currently
unfunded by the operators, these projects have a high chance of
being brought to fruition. They include enhanced oil recovery
at certain satellite fields, development drilling outside the
core areas at West Sak and Schrader Bluff expanded development
at Prudhoe Bay satellites including Orion, Polaris and Borealis,
and Alpine West development. Also included are National
Petroleum Reserve-Alaska (NPR-A) development, Point Thomson,
Liberty and development of other onshore and offshore
discoveries.
MR. WILLIAMS said DOR is forecasting production from four small
pools in the vicinity of known discoveries currently named
Lookout, Moose's Tooth, Spark and Rendezvous in the NPR-A.
Since these discoveries were announced, there has been ongoing
exploration outside their boundaries and explorers continue to
push further west in search of new development opportunities.
He explained that confidence levels vary by category of
production. Certain heavy-oil drilling for Schrader Bluff,
Orion or West Sak in 2007 may have confidence levels approaching
those in the category "under development." In general, however,
offshore development such as Liberty or potentially high-cost
development such a Point Thomson deserve lower confidence; thus
DOR's subjective assessment is 70-75 percent.
He noted all production from this category is subject to delays
and scope changes that might impact reserves or production
rates. For example, Point Thomson has been delayed in the
forecasts three times since 2000. There are 65,000 barrels of
day of natural gas liquids (NGLs) associated with Point Thomson.
However, a delay at Point Thomson also delays 35,000 additional
barrels associated with the satellite fields.
He informed members that many details surrounding this forecast
are based on petroleum engineering knowledge. His advanced
degree is in economics, but he has lived in Alaska only one year
and isn't intimate with details regarding all these fields.
Thus for the more involved questions relating to geology and
engineering, he'd turn to the petroleum engineer who prepared
these forecasts.
He concluded by saying developing crude oil resources will
require significant investment in time and capital. Under the
governor's proposed tax system, the petroleum production tax
(PPT) creates a fiscal framework that provides strong incentives
for exploration and reduces the risk in capital costs of
development. Most important, it provides a long-term revenue
stream to the state by encouraging new participants and
supporting new developments.
3:53:27 PM
MR. WILLIAMS, in response to Chair Wagoner, indicated he'd just
come from a press conference at which the summary data was
released for DOR's revenue forecast. For FY 06, when all
volumes are put together with the price forecast, it comes out
to about $4 billion; for FY 07 it's about $3.4 billion; and for
FY 08 it's close to $3 billion. He agreed to e-mail his
presentation to the committee aide.
3:54:03 PM
SENATOR BEN STEVENS requested clarification about the first
slide, "Fall Oil Production Forecasts."
MR. WILLIAMS explained that the point estimates are forecasts
for each fiscal year going out to 2010 that consistently
overestimated what actually occurred on the production side.
3:55:57 PM
MR. WILLIAMS, in response to Chair Wagoner, indicated he could
find out percentages relating to the aforementioned from the
petroleum engineer.
CHAIR WAGONER requested that Mr. Williams send that to the
committee along with the presentation.
3:56:30 PM
MR. WILLIAMS responded further about the graph on the first
slide, saying those are just volumes. Affirming that the new
forecast released today shows new production as well, he agreed
the graph doesn't show the projected drop of 30,000 barrels a
year for the next five years. He said the FY 06 forecast for
the North Slope is 854,000 barrels a day; for FY 07 it's 825,000
barrels a day; and for FY 08 it's 803,000 barrels a day.
3:58:43 PM
MR. WILLIAMS reported he and the petroleum engineer, Dudley
Platt, figured out that the aging field at Prudhoe Bay and the
heavy oil caused virtually all the problems with overestimating;
thus Mr. Platt was taking those two factors into account and
trying to be more realistic. Expressing support for the good
job Mr. Platt had done, Mr. Williams said these issues also
highlight the fact that the state needs investment to maintain
and possibly increase production.
4:00:21 PM
SENATOR BEN STEVENS opined that as much as the production has
been overprojected, revenue has been under projected. He added
that the new release says revenues are up, even though
production is down.
MR. WILLIAMS replied that in the last ten years, prices were
underestimated four times and overestimated four times. The
Office of Management and Budget (OMB) compared DOR's price
forecasts with those of three other organizations - U.S.
Department of Energy, NYMEX, and Cambridge Energy Research
Associates - and found DOR's to be the best, though not to a
statistically significant degree. Thus he encouraged positive
thinking about DOR's ability to forecast crude oil prices.
4:01:41 PM
SENATOR BEN STEVENS asked about the accuracy of oil-price
forecasts and its relationship to the Henry Hub price or
"futures prices of gas." He asked whether Mr. Williams was
familiar with a "six to eight times" multiplier and if he had
used it as part of the formula.
MR. WILLIAMS replied he was familiar, but not intimate, with it.
Crude oil is an international commodity traded on exchanges
worldwide; a price for crude oil in London will be the same in
New York and everywhere, accounting for transportation
differentials. For natural gas - different in this country from
liquefied natural gas (LNG) shipped around the world - there are
two large oceans on either side and very little gas comes north
or south. Thus the gas price at Henry Hub has constraints based
on the available supply within this country. There aren't
enough import facilities to import enough gas to balance supply
and demand, part of the reason the relationship between gas and
oil is so difficult to forecast.
He affirmed there is a six-to-one relationship, based on Btu
content and the ability to substitute natural gas for certain
products. For example, gas or petroleum could be used for
feedstock in production of petrochemical products. In the
bigger picture, however, natural-gas prices at Henry Hub are
constrained because there isn't enough supply.
The natural gas industry has been regulated in this country from
1969 to 1998; many industries were established and built
pipelines to bring gas in. In 1996-1998, that changed. Many of
those companies are now having difficulty because gas prices
have gone so high. For instance, the petrochemical industry has
about a third fewer people than ten years ago. He said he
doesn't know what will happen with gas prices or whether that
six-to-one ratio will be there in the future. Forecasting
natural gas for the U.S. is far more challenging than oil
because of the limited time in which it has been available on
the free market. Since December 13, for example, the price at
Henry Hub has dropped 57 percent. Furthermore, Mr. Williams
said he didn't know how the industries would "play out." For
instance, would petrochemical just shift their production
capacity to someplace like Qatar? That would influence demand
for natural gas on the commercial side.
SENATOR BEN STEVENS expressed appreciation for hearing something
he hadn't heard before.
4:06:04 PM
SENATOR STEDMAN asked whether Mr. Williams planned to do a
"trumpet-type" graph depicting a low, medium and high range in
terms of price and volume, to show what might reasonably be
expected.
4:07:13 PM
MR. WILLIAMS replied he was looking at that and believed it had
been done in the past. It's rather challenging to do, however,
because if distribution range is too wide, it provides almost
worthless information. In further response, he said the long-
term crude oil price forecast after FY 09 is $25.50 a barrel.
4:08:07 PM
SENATOR STEDMAN asked what time period was addressed when
Mr. Williams talked about DOR's accuracy in forecasting when
compared with the other three organizations.
MR. WILLIAMS answered, "The only period we've evaluated is the
one-year out."
SENATOR STEDMAN suggested the $25 estimate could move, then, as
time marches forward.
MR. WILLIAMS concurred that the further into the future DOR
looks, the less accurate the forecasts likely will be.
CHAIR WAGONER thanked Mr. Williams and agreed it was nice to
hear something new.
4:10:32 PM
^ADMINISTRATION - DAN DICKINSON, CPA
DAN DICKINSON, CPA, former director of the DOR Tax Division,
began by reacting to issues raised by testifiers in the last
couple of days. With regard to auditing direct expenditures, he
told members that in auditing "upstream" costs, substantial
weight is given to the industry practice as of December 1, 2005,
before people were entering into arrangements perhaps as a
consequence of this bill. He also mentioned ways of dealing
with costs that were subject to negotiation with working-
interest owners that were not the operator and who had
substantial bargaining power. Out of perhaps 20 ANS units
including exploration units, maybe only three meet that
criterion. He explained:
What we're looking at are places where you have a BP
and an Exxon or a ConocoPhillips. One of those is the
operator; the other two are looking over their
shoulder and they don't want a penny spent more than
has to be spent. My point is if we have those kind of
things going on, if we have that kind of auditing
going on, is there some way we can take advantage of
it?
MR. DICKINSON proposed that, although it would be great if the
state had a field of auditors looking at every invoice, that
isn't realistic and if safeguards can be created to ensure that
the state's interests aren't compromised, then the thorough work
already being done by industry can be used.
He emphasized that the right policy choice is to give
substantial weight to what the producers do when dealing with
each other, but do it in a manner that leaves the state in the
proper position. He highlighted the need to look at what data
can be used effectively and to look at internal controls like
how the auditing is being done and any changes the producers
make in the operating agreements. He disagreed with Jim Eason's
[Legislative consultant] suggestion that giving substantial
weight to how the producers do things might hinder the state's
ability to question what has been going on.
He addressed a second issue: Mr. Eason's concern that if there
is only one agency doing the work, there won't be crosschecking.
Mr. Dickinson agreed that having two people do something is
better than one, but limited resources don't make that
necessarily practical. Currently, two groups of state auditors
apply slightly different rules to the same set of calculations
to come up with royalties and severance taxes. Mr. Dickinson
proposed that one set is probably good enough, especially with
the market's transparency and if the DNR commissioner has the
authority to set the conditions under which a calculation can be
made.
He explained that the DL-1 leases were written before spot
markets became transparent and the royalty value in them was the
higher of four measures: 1) the value of the oil, 2) what the
company sold the oil for, 3) what others sold the oil for or
4) the posted price. However, when it came time to settle the
Amerada Hess royalty issues in the 1980s and to establish a
"going forward" basis, DNR said the following: it believed there
was a transparent market for the value of oil; it didn't believe
transactions were being done which hid that; and it would start
with this publicly reported number of what oil sells for in the
marketplace, using it as the netback, instead of the
aforementioned number based on the higher of the four values.
He indicated, similarly, that AS 43.55.020(f) gives the DOR the
ability to look at the sales price and then impose a tax based
on it or on the prevailing value if the production wasn't sold
at market value. Mr. Dickinson opined that while the concerns
expressed by Mr. Eason were valid, they are met by putting
sufficient safeguards in place.
4:19:44 PM
MR. DICKINSON turned to comments by Daniel Johnston suggesting
the state shouldn't be worse off after the change than before.
One possibility is to leave the economic limit factor (ELF) in
place and do a "higher of" calculation. However, Mr. Dickinson
spoke against leaving the ELF in place saying he believed what
was being done with the bill made sense and that some places
cited by Mr. Johnston had a tax system as their only way of
getting revenues. Nova Scotia, for example, has no additional
royalty, income tax or property tax.
He noted half the state's general revenues come from the royalty
and that isn't affected in this bill, which turns the severance
tax into a different vehicle to be used to incentivize
production; when there is a fair amount of profit from that
production, the state will take its fair share. Mr. Dickinson
opined that having an alternative tax or an alternative ELF tax
isn't as critical as it would be if it were the only source.
4:21:04 PM
MR. DICKINSON began his slide presentation, saying he'd talk
about the point of production and how it affects both royalty
and tax for oil and gas. He said the current tax system has been
pretty simple. The state knew what it wanted and put it into
statute in the 1970s. The definitions are not being changed in
the proposal, but rather being simplified.
He showed the slide "Oil or Gas - Why does it matter?" and
explained that under current rules it matters a great deal. Gas
is taxed at 10 percent of the gross, and a gas ELF looks only at
how productive each well is. In contrast, oil is taxed at 15
percent times an ELF that takes into account both the well's
productivity and the field size.
Another aspect under current rules is that gas used for
production operations on the North Slope is free; this condition
is found in practically all gas-producing states. The condition
says if the ultimate purpose of an operation is oil production,
the gas can be used as fuel and for heating at no charge. Using
oil for those purposes is not free.
He corrected a second slide, relating to proposed rules that
should say "past" rather than "post" production. Mr. Dickinson
reported that each barrel of oil has a conservation surcharge of
3 to 5 cents, depending on various conditions; however, there is
no conservation surcharge for gas.
4:23:39 PM
MR. DICKINSON explained that in part the bill says perhaps some
of those shouldn't matter quite as much and taxes both oil and
gas at 20 percent of the net with free use of both gas and oil
for production purposes. He found in 1996 research that of the
20 oil-producing states, seven have tax-free use of gas and oil
as long as it's for production purposes; the other 14 only give
that to gas, while oil is taxed. He noted the conservation
surcharge would be creditable.
4:24:32 PM
SENATOR DYSON asked what production purposes oil could be used
for.
MR. DICKINSON answered that some products are made at a "crude
oil topping plant" - for example, low diesel that is used in
well work and as fuel for vehicles. Another major use is as
miscible injectant.
4:24:57 PM
MR. DICKINSON recalled that this morning Mr. Mintz had suggested
using just one category - "produced hydrocarbons" - and thus no
distinction between oil and gas would be needed.
CHAIR WAGONER asked the reason for making the conservation
surcharge creditable and why the recent North Slope oil spill
could be used as a credit.
MR. DICKINSON replied that right now the actual costs of the
emergency response, including cleaning up and "fixing" that
event, aren't deductible. However, the resulting decreased
production would decrease the amount of tax and royalty the
state gets. Under the proposal, the state would allow both
preparing for such a crisis and then, if it did happen,
responding to it would be deductible.
CHAIR WAGONER pointed out that several state positions are being
funded from that revenue stream that will be reduced.
4:26:42 PM
MR. DICKINSON replied that the proposal wouldn't reduce the
revenue stream to the spill fund; 3 to 5 cents per barrel will
still go to the fund. The money going to the fund would actually
increase a little bit because the definitions are changing to
just look at profits. However, with the credit, the total
amount of general fund revenues would be smaller.
CHAIR WAGONER asked, "Why are we saying that?"
4:27:38 PM
MR. DICKINSON replied that they were trying to do a profits tax
that minimized the small regressive components. The intent of
the tax is to look at profitability and tax that 20 percent. If
you're not profitable, it's nothing. They were trying to get rid
of the philosophically point of view of some smaller additions
to the base tax.
4:28:19 PM
MR. DICKINSON emphasized that concerns about the point of
production relate to the definitions of oil and gas and for oil,
there is no real change. But, for gas the point of production is
driven by the "point of final separation."
He asked, "Why does the point of production matter?"
Historically, the point of production was very important because
costs incurred downstream of it were deductible for calculating
production tax, while costs incurred upstream weren't. You
could deduct tankers, TAPS and the Kuparuk pipeline, for
instance, but as soon as you hit the Kuparuk boundary, costs
were no longer deductible. A billion dollar facility within the
boundary was not deductible.
In a parallel situation with royalty, the point of production
made all the difference. In 1978, the point of production on a
royalty lease form was ambiguous and therefore, was negotiated
between the state and the producers who said that it was at the
wellhead where the oil comes out of the ground and that all
costs were deductible. A field cost settlement was established
at that time to cover upstream costs that included inflation and
it is currently at about $1 a barrel. His point was that as you
move the point of production upstream, then something downstream
of that becomes deductible. That is why, until now, the point of
production has been critically important.
This bill's intent is to incentivize those costs beyond being
just a deduction. The point of production remains important
because, even though costs are deductible from both sides of the
point of production, how they are recaptured is still very
different. Downstream costs remain traditional, but upstream
costs are different. The state is saying you spend a capital $1
and you get to deduct it immediately and, furthermore, you get a
20-cent credit that can be applied against profits for any
obligation. The point of production is still a critical issue.
This is one of the reasons gas processing, which used to be
downstream of the point of production, now moves upstream.
4:32:57 PM
MR. DICKINSON said under the old rules, the state gives gas
processing a reasonable allowance. Now in the proposed bill, the
investment for the gas processing plant would be both a
deduction and a credit. Moving to the next slide, he opined
that the point of production would matter particularly for a
newcomer without heritage facilities who has found gas ten years
down the road and wants access to the production facilities.
Even now, some folks who are discovering oil have alleged that
access is difficult. He stressed that the dynamic would
dramatically change and a new producer would be able to just
build his own plant, knowing he'll get 40 percent credit for it
from the government.
He submitted that if existing heritage facilities are
underutilized, its owner would know how much it would cost to
build and that knowledge could help frame negotiations with a
new entrant. He offered the belief that moving the gas
processing costs upstream of the point of production would
significantly change how people think about costs and facility
sharing. He advised this isn't the only solution members should
think about for that particular problem, but to the degree the
tax code can be used, he thought it would make a significant
difference.
4:35:00 PM
SENATOR ELTON asked what the most important thing for a new
entrant would be for access to a facility or the pipeline.
MR. DICKINSON replied that it's not his job to say that. But
what the department says is that pipelines are publicly
regulated and access to them should be based only on the charge
for that access, which should reflect a cost recovery
methodology - in other words, standard rate-making procedures.
The question with TAPS has been whether those processes were
circumvented in the settlement or aren't representative of true
costs. He wouldn't recommend suddenly moving all the points of
production downstream of the pipeline. Where the line is drawn
between gas (and oil) processing, treatment and pipeline is a
choice that folks have to make.
4:36:57 PM
The next slide deals with what happens when you have production
and post-production facilities in the same building. Under the
current rules, if a central gas facility has both gas processing
(which removes valuable liquid hydrocarbons that will end up in
TAPS) and production activity (which is simply taking the gas
and conditioning it so you can put through compressors and put
it back down in the ground again), together and because one is
deductible and one isn't, costs have to be allocated. Under the
proposed rules, both of those activities would be deductible.
4:39:57 PM
Slide 9 gets into what is the point of production for the gas or
the oil. The statute says that oil must be in the pipeline
quality condition and that has been defined as being in good and
merchantable condition. Gas that is produced in association with
oil is actually metered downstream from the point of final
separation. Both of the definitions remain unchanged, but they
are dealing with the point of final separation.
The question has been raised that the state has this great
standard for oil. So, why can't the same be done for gas? His
observations were that historically, gas is often sold with the
liquids still in it (wet) and so it doesn't have the clear
merchantability standard that crude oil has. Secondly, if you
did that, you would be essentially saying that gas treatment and
the gas treatment plant would now move upstream of the point of
production and would be allowable for these credits and
deductions.
So, we believe that having this condition of pipeline
quality good and merchantable emission is good for
oil. We're going to leave it for oil. We don't think
moving that over to make it the same standard for gas
makes as much sense.
MR. DICKINSON said the definition of gas in the proposal
includes what happens if a big facility is built for gas
treatment and the point of production would be in the middle of
that facility. The point of this slide was that is true and the
state may end up in the same kind of cost allocation issues.
4:42:11 PM
He recommended keeping the gas treatment as part of
transportation and the downstream where it is deductible, but
doesn't need the additional credit or upfront help.
4:43:36 PM
The next slides dealt with where the point of production (POP)
is for gas and oil now. This bill proposes moving the POP for
gas, not oil, which would put the central gas facility upstream
from the POP. Everything going through it would be considered a
production operation. When the NGLs are taken out of the gas,
the LACT meter is the point at which they become oil.
4:46:16 PM
He said the question was asked if this was absolutely critical
to the PPT and the answer was no. The goal is to simplify
definitions that will not lead to low value-added conflicts and
to incentivize all production activity including gas processing.
Another question was could the state retain the same definitions
of POP and still get most of the benefits of the PPT? He
answered yes and emphasized that the administration is trying to
create a clear way of dealing with the issues.
4:47:20 PM
SENATOR DYSON asked where gas and oil were taken off for in-
field use in each of the diagrams.
MR. DICKINSON replied under the current plan that oil will be
diverted to a topping plant as it is flowing from the
facilities. The topping plant has another little meter where it
begins to be taxed.
In the separation facilities some gas is used for gas lift and
things like that, but it is simply recycled in the separation
facilities. The major streams of fuel that are used go through
all the processing at the central gas facility and are
essentially identical to what is put down in the ground to
pressurize the reservoir. By that time it is basically methane.
MR. DICKINSON explained:
The new scheme should be the exact same thing. Again,
what would happen is, even though it would be
downstream of the point of production for gas for the
stuff that is used on the lease, it will be as if it
were not produced.... They will, in fact, meter it and
they have to figure out as to who has done what - so
it will go through that meter, but it won't trigger a
point of production or taxability.
He said that oil would be treated the same way.
CHAIR WAGONER thanked him for his presentation. He announced
that they would next go hear the Tax Division's answers to the
Legislature's remaining questions.
4:51:01 PM
^DEPARTMENT OF REVENUE - Robynn Wilson, Director, Tax Division -
Addressed legislature's questions - with Dan Dickinson
ROBYNN WILSON, Director, Tax Division, Department of Revenue
(DOR) explained that she would address the remaining questions
plus a few more.
4:52:13 PM at ease 4:53:30 PM
1. Identify values/amounts for the "look-back" or transitional
deduction per year according to the actual by type (exploration,
development, production).
The Department of Revenue model uses $1 billion per year as
capital costs. So for the transitional period, there would be
about $5 billion. These annual costs are based on compilations
of historical data. [Graph is in bill file.]
4:54:36 PM
SENATOR DYSON asked where she drew the line between exploration
and development.
MS. WILSON replied the bill has no definition for exploration
versus development. The IRS code makes a distinction, because
generally, exploration costs are fully deductible; whereas
development falls under the category of "intangible drilling
costs" and those are capitalized.
SENATOR DYSON asked what the difference in the equipment or
activity in the field was.
MS. WILSON replied that the exploration would include things
like seismic, geologic and geophysical.
4:55:28 PM
MR. DICKINSON added that the information is collected from a
number of sources, but basically for their purposes, exploration
would be pretty close to wildcat drilling of delineation wells.
SENATOR DYSON asked if development water, EOR (enhanced oil
recovery) and all those things were considered development.
MR. DICKINSON replied that was correct.
4:56:11 PM
SENATOR ELTON asked if she had numbers for 2005.
She replied that she didn't have finalized numbers for 2005.
SENATOR ELTON estimated the number to be in the $6 billion range
for 2005.
MR. DICKINSON responded that 2001 would only be one-half the
cost because they are using calendar year costs that run from
July to July. The department's extrapolations indicate that the
downward trend is continuing through 2005 and 2006. He thought
the number would be closer to $5 billion.
8. Which other tax regimes - worldwide - have a progressivity
structure?
Ms. Wilson cautioned that she had heard a lot of references
to progressivity and each person may have a slightly
different definition. For example, in the income tax world,
progressivity generally means as your net taxable income goes
up, the tax rate goes up. But, she has also heard talk about
progressivity with respect to the price of oil per barrel.
That means if the price of oil is $60, you would have a
different tax rate than if it was $40. She suggested that
they might be ignoring the cost. So, the taxpayer that is
doing what the state wants by reinvesting is suddenly being
taxed at a rate that is higher on what is left than the
taxpayer that doesn't reinvest. She cautioned them to be
careful on what they are measuring the progressivity about.
Dr. Van Muers' pointed out that a lot of countries base
progression on production. "So, are we talking about
increasing tax rate based on net profits? Are we talking
about increasing it based on price per barrel or are we
talking about, maybe, production? I don't know that there is
a right answer."
SENATOR STEDMAN interrupted to say that regimes that were
regressive in nature were royalty tax-based systems. The regimes
around the world that are rate-of-return based are production
profit sharing and are progressive in nature. So as the price of
oil goes up, the split between the government and the industry
rises to the advantage of the government.
MS. WILSON continued saying that progressive features are
relatively common around the world. She presented the committee
with a list of the main fiscal regimes with such features.
5:02:50 PM
18. The State of Alaska has relied on the services and expertise
of multiple outside law firms to handle disputes over oil and
gas issues. Have you conferred with such counsel in the drafting
or review of this legislation? If so, have they assessed the
impacts of the legislation on the State's legal position in past
agreements, current disputes, or future disputes?
Yes, such counsel (not all of them) have been consulted and
such assessments have been discussed but have not generally
been generated in formal written form.
Did such advice result in any changes to the legislation?
The bills reflect discussions with counsel that took place
during the drafting process, so in that sense such advice did
affect the legislation.
5:03:27 PM
SENATOR BEN STEVENS asked if royalty is a progressive system in
price and recalled that Dr. Van Muers' said the PPT flattened it
out. He asked if he interpreted that wrong. He asked if they
were benchmarking the progressivity against profit or the price
or the total government take.
MR. DICKINSON replied that using it they way Senator Stedman
did, generally the royalty would be considered regressive,
because no cost is deducted and it's based only on revenue. As
the dollar per barrel increases, the take stays constant. And
because no costs are deductible, as you get close to not
covering costs, the state is still taking dollars.
SENATOR BEN STEVENS said he thinks of progressivity in terms of
total dollar value. The state's share either stays the same or
increases (significantly in some instances) - compared to the
status quo. He asked if that was accurate.
MR. DICKINSON replied:
I think that as prices go up under our current system,
the state makes a lot more money. The forecast just
released said $1.6 billion. But our percentage of the
gross has fallen.
SENATOR BEN STEVENS said, "Right, so that's regressive."
MR. DICKINSON agreed.
SENATOR BEN STEVENS said he was comparing the old system to the
new system.
MR. DICKINSON responded that the proposed system would be less
progressive than the old system. Technically speaking it is not
progressive at 20/20.
5:09:08 PM
SENATOR STEDMAN supposed that even under a regressive system,
the state's total dollars might increase, but the percent of
government take would decrease. At the London seminar he
attended, he learned from industry to think of progressivity or
regressivity in terms of percentages rather than dollars as the
dollar prices moved. "From their viewpoint, no matter where the
money was spent, it didn't matter. If it didn't go to them they
didn't care - call it a tax, call it a royalty, call it anything
you want to."
He said Dr. Van Muers combined the proposed bill using 25/20
with the current royalty and tax structure and it resulted in a
virtual flat government take. He said the discussion was should
the government take have been upward of that, flat or
regressive. At a minimum he thought it should be flat and that's
what he presented. They need to remember that as the price goes
up, more revenue would come to the state even under a regressive
system.
5:12:43 PM
SENATOR ELTON picked $40 at 20/20 and said for every $1 increase
in a barrel of oil a quarter point was added. He asked if that
would have more progressivity.
MR. DICKINSON replied yes.
5:13:50 PM
SENATOR BEN STEVENS said he was fascinated that the Legislature
was mesmerized on the percent of government take. Government
depends on a flow of money, not a percent of a declining
resource. He kept coming back to what the government should
frame its policy on when it tries to secure a reliable revenue
stream. He thought in a true progressive system the government
gives up more as the price goes down - all the way down to zero
tax at zero profit.
5:17:05 PM
SENATOR STEDMAN steered thinking back toward Senator Elton's
discussion on progressivity. If the state takes a higher
percentage when prices go up, it takes away the upside from the
industry and it is only fair to go back to the other end of the
curve and adjust for it. "You can't have an extremely
progressive system and then go back to the low price side and
start putting in floors. There's no balance there."
5:18:38 PM
MS. WILSON jumped in with an example to hopefully add clarity.
If oil is at $100 a barrel and the producer produces one barrel
and has expenses of $90 and, therefore, a net profit of $10.
Next year the price of oil falls to $10 a barrel; he produces
one barrel and doesn't invest anything and his net profit is
still $10. So, if the state is talking about basing an
increasing tax rate simply on the price of oil, those two $10-
profits are going to both enjoy - for instance, a 15 percent
rate when oil is $10, and a 25 percent rate when oil goes to
$100 - both scenarios have a $10 profit, but in the first
instance when oil is $100 a barrel, the producer has $2.50 in
tax and for the second example, $1.50 in tax. She emphasized
that both taxes are on the same profit. She cautioned people to
keep intent in mind.
5:21:01 PM
SENATOR BEN STEVENS said he wanted to get attention off the
government take, because that's not what the change does.
5:23:27 PM
SENATOR DYSON reminded the committee that under the Constitution
and the Statehood Compact the gas belongs to the people and they
should be rewarded on the upside.
5:26:11 PM
SENATOR STEDMAN said keeping an eye on the cash flow - at the
end of the day - was important.
5:26:59 PM
MR. DICKINSON reminded them that they were discussing the long-
term cash flow and how to make sure it's robust under all
conditions.
5:27:43 PM
MS. WILSON continued with the questions and answers.
24. What standard will be used to determine whether oil or gas
is of 'pipeline quality' under the definition of 'gross value at
the point of production'?
MS. WILSON said that Mr. Dickinson covered this question in his
presentation and this is a written description of it. She wanted
to skip that one. The Chair indicated that way okay. [The
following answer was provided in her letter.]
The current production tax statute taxes the "gross value at
the point of production" of oil and gas. The quoted phrase
was enacted in 1977 and replaced the previous statutory
phrase "gross value at the well." This change was aimed at
ensuring that costs of production operations downstream of
the well would not be deductible in calculating the taxable
value of oil or gas; rather, taxable value would be
calculated at the point that production is complete.
In the case of oil, "gross value at the point of production"
was defined as the value of oil where it is metered "in a
condition of pipeline quality," and "pipeline quality" was
defined as "good and merchantable condition." This definition
essentially adopts commercial standards of marketability for
oil. HB 488 and SB 305 would simplify and shorten the
definition of gross value at the point of production for oil
but do not materially change it. In addition, the definition
of "oil" is broadened to include liquid hydrocarbons
recovered by gas processing in the case of leases or
properties whose production is subject to gas processing. The
bottom line is that the point of production under these bills
would still be the point where oil is metered in a condition
of pipeline quality, and "pipeline quality" would mean the
same thing it has always meant under the production tax
statute.
In the case of gas, neither the existing statute nor the new
bills use the phrase "pipeline quality" or "good and
merchantable condition" with respect to gross value at the
point of production. Rather, the statutory definitions of
"gross value at the point of production" for gas, as
interpreted and clarified by the Department's regulations, 15
AAC 55.900(a)(6)(B) and (C), focus on where gas is accurately
metered after separation from oil. The new bills retain this
concept but, in effect, expand "separation" to include gas
processing, so that in the case of leases or properties whose
production is subject to gas processing, the point of
production for gas recovered by gas processing is the point
where it is metered downstream of the processing.
5:28:42 PM
25. Provide an historical analysis of the results of valuation
methodologies adopted by the Department of Revenue, Department
of Natural Resources (under all agreements), and the Department
of the Interior. She asked Mr. Dickinson if that had been
covered. He suggested going to the last paragraph [But the whole
answer has been included for clarity].
While there is much that is parallel in the calculation of
gross value at the wellhead between royalty and tax, many
differences have developed. Both start with destination value
in the market and then subtract the tankering, pipeline and
other costs to arrive at a wellhead value. The Department of
Revenue's valuation for tax comes from statute and
regulation. The Department of Natural Resources' valuation
for royalty comes from lease contracts supplemented by
Royalty Settlement Agreements (RSAs), which set forth
different methods for each large North Slope producer. (Cook
Inlet valuation is not covered in this answer.)
Destination value, for the Department of Revenue, is what the
oil was sold for or when the oil is not sold or is sold for a
below market price - the so-called prevailing value or spot
price. Destination value for the Department of Natural
Resources is a formula driven by the ANS or a basket of
similar crudes.
From the destination value, each method subtracts marine
transportation costs, TAPS costs (including tariffs, losses
and quality bank changes from mid-point refineries), feeder
line costs (including tariffs, losses and quality bank
differences), and other miscellaneous costs. DOR deducts the
costs specific to each taxpayer, while for royalty, some of
the RSAs have formulaic deductions and others use the royalty
payers' actual cost. In addition, DNR subtracts field costs
for most DL-1 lease form leases on the North Slope whereas
DOR does not.
The differences between wellhead values narrow across time.
The average difference for the period FY00 through December
2005 is 3.9 percent. However, the average difference for the
last 12 months is 6.1 percent while the average difference
for FY00 through FY03 is 3.0 percent.
The critical point is that DOR uses actual proceeds, and only
resorts the Prevailing Value (PV) when the conditions of 020
(f) are met, thereby taxing on the higher of proceeds or PV.
For each of the three producers, DNR uses a single
destination formula based on spot prices, not actual
proceeds.
5:29:56 PM
34. Of the pre-PPT credit provisions (the claw back), how many
investment credits were sold under SB 185 and how do we ensure
the person who holds the credit, not the original recipient,
gets the credit?
a. Only two credits that have been issued have been sold to
another party.
b. The Division will first obtain a waiver of confidentiality
from the seller allowing the Division to confirm the credit
amount to the prospective purchaser. Once sold, the Division
makes the transfer and issues a new credit certificate to the
purchaser upon receipt of documentation and confirmation of
the transaction from the seller of the credit. The credit
exists as an electronic entry in a Division database,
therefore only the Division can make the actual transfer of
the credit in that database. A new certificate is entered in
the database to the purchaser and the old certificate is
marked as transferred and its balance is zeroed out. The
Division then notifies both the purchaser and the seller, in
writing, of the completed transfer of the credit, at which
time the purchaser may then apply the credit to its own
production tax liability. When a credit is applied to a tax
liability by a producer, the Division then verifies the
holder and amount of the claimed credit against the credit
certificates in the database.
5:31:30 PM
40. Do other nations with a net profit system have the 90
percent payment of taxes with the sure-up provision the
following year? What is the economic impact of this change?
a. Net profits systems in the world typically work on the
basis of three different concepts:
(a) Monthly payments based on actual production, revenues and
expenditures, without an annual true-up, as is the case in
most production sharing agreements
(b) Yearly payments based on a yearly return, filed within a
few months after the year, without a need for monthly
payments on account, as is the case for the Thai SRB, for
instance. This means there is only a single annual payment.
(c) Yearly payments based on a yearly return, filed within a
few months after a calendar year or a lease/contract year,
with monthly payments on account. In this last case, the
monthly payments could be based on:
a. Estimates for each month, as for instance with the Nova
Scotia profit sharing royalty. These estimates can be
challenged by government and different estimates may be
required.
b. Payments based on a mixture of actual information from the
previous month and estimates, such as in Algeria
c. Corporate income tax style procedures, whereby payments
are based on taxes paid in the prior year (Norway for the
Hydrocarbon Tax).
The 90 percent rule proposed for Alaska is unique. The
overall economic impact would depend on the taxpayers' cost
estimates for each month. We expect that taxpayers will
experience underpayments in some months, but will experience
overpayments (because of estimates used) in other months. In
addition, falling production amounts, or unforeseen costs
will serve to likely create overpayments in later months.
Overall, we do not expect any material net economic impact.
5:33:10 PM
66. The discussion of oil field needs, i.e. not to deplete the
gas pressure, did not recognize the COre-injection. How will
2
that lengthen the field life(s) and at what volumes, i.e. how
will it affect taxes?
At Prudhoe Bay, about 8.5 billion cubic feet of gas a day is
reinjected into the field for pressure maintenance. After
stripping out certain hydrocarbon liquids, CO2 is reinjected
along with the other hydrocarbons (and non-hydrocarbons).
When an export line is built on the North Slope, the CO2 will
be stripped (in "gas treatment"), and there is some question
about what will happen with that CO2.
5:33:52 PM
CHAIR WAGONER asked why is there a question about what will
happen to Co2.
MR. DICKINSON replied that the question is that the co2 is
either a valuable product or a waste product and are modeled
differently for the different applications. For this question,
CO2 is just with the gas and is not part of the tax picture.
When a gas line occurs, that would be one of the issues to focus
on.
5:34:47 PM
67. What happens if the "Big Three" sell off their assets to 20
smaller companies? Will the significant tax benefits ever be
realized?
Assume 20 new companies suddenly showed up on the North Slope
and each qualified for the $73 million dollar allowance. A
total of $1.4 billion in profits would be sheltered from
taxes. If these companies had simply purchased their way in,
then taxes would be lower by $280 million (20 percent of $1.4
billion) than they would be otherwise. At current prices, or
say even at $40 oil, this could be a material portion (though
not all) of the tax.
If that is the future of the North Slope and the sell off was
for business purposes, the Legislature may choose to act and
make it less attractive to new firms coming in. If these were
tax-motivated sales, we hope the powers of the commissioner
that are built into the bill would prevent the new entrants
from using the $73 million allowance. The commissioner gets
to approve qualification for the $73 million allowance.
5:36:21 PM
73. Will the new confidentiality provisions extend to or have an
effect on any other taxes besides the production tax?
The new confidentiality language added by secs. 4 and 16 of
the bill applies only to information relating to the oil and
gas production tax, not other taxes. This is because:
(1) AS 43.55.040(1) addresses information "necessary
to compute the amount of the tax," and the phrase "the
tax" is used throughout AS 43.55 as referring only to
the production tax; and
(2) AS 43.55.040(1) deals only with information
obtained from persons "engaged in production," or
their agents, and with purchasers "of oil or gas," and
with owners of a "royalty interest in oil or gas."
77. How much gas was flared so as to trigger taxes and/or
penalties in recent years?
During FY 2005, 351,000 Mcf of gas was flared that was
considered gross taxable production. Of that, only 120,000
Mcf was from fields with a positive ELF and subject to tax.
During the same period 31,000 Mcf was flared and considered
waste and subject to both tax and penalty.
80. When the 1989 ELF change was enacted, was it retroactive and
were there transition provisions?
The 1989 ELF changes were made retroactive to January 1,
1989, and applied to oil produced after December 31, 1988.
There was a transition provision to the effect that tax
payable as a result of the retroactive changes would be due
on the 20th day of the calendar month following the effective
date of the Act. (The effective date of the Act was August 6,
1989.)
82. Under the new gas and oil definitions, what will the net
change to the spill fee be? In other words, looking at FY 2005,
how much, if any (a) oil did we tax for its use in production
operations and (b) how many NGLS were put in TAPS?
During FY 2005, tax was collected on 1,222,400 barrels of
crude oil used in production operations. During FY 2005,
16,445,000 barrels of NGLs were put in TAPS.
83. For sales of credits by the smaller interests, estimate the
price at which those credits will no longer have a market among
the big three?
Credits may be used in the year of expenditure, carried
forward to following years, or transferred (they are
fungible). If transferred, the credit cannot lower a
severance tax rate below 80 percent of what it would
otherwise be [AS 43.55.024(e)]. These credits will have
market value that would not exceed 20 percent of their face
value ($1,000 in capital expenditures would save $200 in
State severance taxes). A company generating them but unable
to use them would face a choice - sell them or use them the
following year (if they have taxable income).
Use the next year reduces the value of the credits due to
discount rate. Oil companies typically try to use a 15
percent discount rate but will often settle for less, say 10
percent. This means, all other things equal, they would be
willing to sell a $1,000 credit ($5,000 capital expenditures)
for $900 (10 percent discount rate) or more. Conversely,
another company would be willing to pay up to $999 for the
credit to save $1,000 in State severance tax.
If we assume a billion in spending, assume that 10 percent of
that was for little companies that would want to sell their
credits, so $200 million in credits are for sale. With our 20
percent limit, that implies that if the big three had a
billion dollar in tax obligations, that market could absorb
all the credits. As our fiscal note shows, if the price of
oil is $40 or above, all of the credits would be usable in
the immediate year. If oil falls below $40, then we expect
that the credits would be fully utilized within two or three
years. While the time-value of money means that those
certificates would be discounted, we believe that the
certificates would still be marketable.
84. If aggregation at Prudhoe Bay had been implemented on July
1, 2001 [the start of the claw back period], how much more would
the State have received between then and the actual aggregation
date?
The State would have received $430.4M additional revenue. She
provided a graph of estimates.
85. Why are the status quo lines in the three graphs presented
by Ms. Wilson flat once the forecast price effect is adjusted
for? Wouldn't falling production and ELF move those down?
The status quo drops from $378 mm in 2009 to $291 mm in 2012.
It looks flat because of the scale on the graph.
86. What will the actual cost to the investor be for these
upstream investments and what is the total government
underwriting, state and federal, all tax types included. Is it
different for large companies and small companies?
After state and federal tax, the investor would bear about 38
percent of the marginal capital. There is no reason to think
it would differ appreciably between large and small
investors.
87. Lord Browne famously said two years ago that any profits
over $20 a barrel were being returned to shareholders as they
weren't needed in BP's business. What tax rate, credit rate
would be needed to have a cross over [unspecified period] at $20
[presumably Brent].
With a 20 percent credit, it would take a tax rate of about
51 percent to affect a crossover at $20 Brent.
88. Please explain how the conservation surcharge is affected by
oil price and what affect this bill has on the surcharge.
a. The conservation surcharge is a 3 cent per barrel charge
on all oil produced less royalty barrels, so therefore it is
not sensitive to price.
b. There will be changes in the quantity of oil subject to
both production tax and conservation surcharges under the
bill. One change will be positive, one negative. The positive
change is that natural gas liquids extracted by gas
processing and blended in the TAPS stream that are now taxed
as gas, will be treated as oil under the bill.
The negative change is that oil that is used in lease
operations will not be taxed or subject to surcharge under
the bill. Oil may be used to make fuel for lease operations
and perhaps used for other production purposes. The overall
result is an expected increase of the total surcharge amount
of $444,000 per year, based on FY 2005 amounts. (See Question
82.)
The bill should not affect the assessment or collection of
the surcharge, other than the quantity-of-oil effects
described above. Any surcharge paid will be allowed to be
credited against production taxes, but that would only reduce
the amount of tax collected, not the amount of surcharges
collected.
89. Why are we including gas in the PPT calculation?
The bill includes gas in the PPT calculations because it is a
stand-alone bill. The bill does not require implicitly or
explicitly that a Stranded Gas Contract be subsequently
concluded. Therefore, a PPT law would be entirely functional
in case a Stranded Gas Contract is not presented to the
Legislature or in case the Legislature rejects such a
Contract.
The ELF system for gas is "broken" just as the ELF is
"broken" for oil. The gas ELF does not encourage reinvestment
and it is not sensitive to price.
It should be noted that under high gas prices, the Alaska
State take for gas would increase significantly relative to
the status quo. This would be beneficial in case significant
gas reserves would be developed outside the scope of the
Stranded Gas Development Act.
The inclusion of gas in the PPT is therefore a strong
incentive for producers to conclude a Stranded Gas Contract
that is in the interest of the State of Alaska. Including gas
in the PPT enhances the bargaining position of the State for
a good Stranded Gas Contract.
CHAIR WAGONER thanked everyone for their comments and adjourned
the meeting at 5:46:13 PM.
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