Legislature(2011 - 2012)BARNES 124
02/09/2011 01:00 PM House RESOURCES
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| Presentation(s): History of Oil Taxes in Alaska | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
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= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
PRESENTATION(S): The History of Oil Taxes in Alaska
[Contains discussion of HB 17 and HB 110]
1:01:55 PM
CO-CHAIR FEIGE announced that the only order of business is a
presentation on the history of oil taxes in Alaska by Roger
Marks. He pointed out that Mr. Marks is especially qualified to
give this presentation because his career has spanned the entire
history of oil taxation in Alaska.
1:02:48 PM
ROGER MARKS, Economist, Logsdon & Associates, Consultant to the
Legislative Budget and Audit Committee, first noted that prior
to entering private practice two years ago he was a petroleum
economist with the Department of Revenue, Tax Division, for
about 25 years. Much of his time with the department was spent
analyzing the production tax and he had some involvement in many
of the events that he is talking about today. He pointed out
that for some of the events he is discussing there is no written
record of the details, so his descriptions reflect a combination
of his recollections and the many conversations he has had with
lots of people over the years. He cautioned that other people
could have different recollections and interpretations of those
events.
MR. MARKS specified that his talk concentrates on the North
Slope. The two major forces of production and price flavored
the events of the past 34 years. Flow of Alaska North Slope
(ANS) crude oil through the Trans-Alaska Pipeline System (TAPS)
started in 1977 (slide 2). This flow peaked in 1988 at about 2
million barrels a day and has been declining ever since. Cook
Inlet, also an important part of Alaska oil and gas history,
started in 1958 with the Swanson River field. Cook Inlet [oil]
production peaked in 1970 at about 200,000 barrels and is now
down to just 10,000 barrels a day. Gas production in Cook Inlet
peaked at about 2 billion cubic feet a day during the 1990s and
since then has been at about three-fourths of that level.
1:05:17 PM
MR. MARKS pointed out that while the bumps in price between 1977
and 1997 (slide 3) do not look like much on the graph, a
difference of $5 a barrel back then was a huge deal in terms of
state revenues. Notable past events are the 1979 Iraqi
Revolution, the 1986 oil price crash to about $6 per barrel when
the Organization of Petroleum Exporting Countries (OPEC) flooded
the market to enforce some market discipline, and the 1990
[Persian] Gulf War. Since 1998 prices have been climbing due to
a combination of increased world demand and the end of the era
of cheap oil. Every new barrel of oil produced now is more
expensive to produce. Alaska, he noted, has been very fortunate
that the decline in its production has been offset by the
concurrent increase in oil price.
MR. MARKS defined the production, or severance, tax as a tax on
producing or severing a non-renewable resource from the state
(slide 4). Authorized in AS 43.55 and administered by the
Department of Revenue (DOR), the tax applies to all production
in the state, including onshore state land, state land extending
three miles offshore, and federal onshore acreage, such as any
production from the National Petroleum Reserve-Alaska (NPR-A) or
the Arctic National Wildlife Refuge (ANWR). Production tax is
not payable on the public (state and federal) royalty
production. Most state leases have a royalty of about one-
eighth, so the production tax is only payable on the seven-
eighths that is non-royalty.
1:07:33 PM
MR. MARKS discussed the three other elements of state revenue
that Alaska receives from petroleum: royalties, oil and gas
property tax, and state corporate income tax (slide 5).
Royalties are not a tax, but rather the state ownership share.
Administered by the Department of Natural Resources (DNR),
royalties are based on gross production. The gross value of
production is the value before subtracting the operating and
capital costs to produce it. Most royalty rates on the North
Slope are 12.5 percent; however, some leases have a higher rate,
some have a lower rate, some are subject to a sliding-scale
royalty where the royalty rate fluctuates with the price, some
have profit shares on top of the fixed royalty rate, and some
are subject to royalty relief. Royalty relief may be received
by some fields that apply to DNR, and is often received in the
beginning years of the project to make it economic. The royalty
terms are dictated by the lease and are determined at the time
of the lease sale. The lease term is considered a contract; it
is not determined by statute.
1:08:59 PM
MR. MARKS explained that the property tax is 20 mills or 2
percent of assessed oil and gas production property located in
the state. For oil and gas property located within a
municipality or borough, the borough or municipality keeps the
amount of property tax generated up to its mill rate, even
though the tax is administered by the state. For properties
outside a municipality or borough, the entire tax goes to the
state at the 20 mill rate.
MR. MARKS explained that Alaska's state corporate income tax is
9.4 percent of apportioned income. Apportioned income to a
state is based on the amount of a company's property, payroll,
and sales in that state relative to the rest of the world.
Alaska has modified apportionment which is based on property,
production, and sales. He noted that in addition to these state
taxes, the producers also pay a federal corporate income tax at
nominal rates of 35 percent of that.
1:12:01 PM
MR. MARKS reviewed the Department of Revenue's forecasted state
petroleum revenues for Fiscal Year 2011 (slide 6). Predicated
on a forecasted ANS price of $78 per barrel, DOR is forecasting
$5.3 billion in general fund revenues. About half of that
total, $2.6 billion, is from the severance tax, $2.2 billion is
from the royalty, $104 million is from the property tax, and
$445 million is from the state corporate income tax. He noted
that for acreages leased prior to 1979, 25 percent of the
royalty goes to the permanent fund; for acreages leased after
1979, 50 percent of the royalty goes to the permanent fund.
MR. MARKS defined "market price" as the price that Alaska North
Slope (ANS) crude oil sells for on the West Coast, which is
currently a little over $90 a barrel (slide 7). "Gross value"
(also called "wellhead value") is market price less marine
shipping cost and TAPS tariff. The current marine shipping cost
is a little over $2 and the TAPS tariff is over $4 for a total
of $6 to be subtracted. The gross value is the basis for
royalties and it was the basis for the severance tax until 2006.
Technically, the gross value is at the point where the oil is
first accurately metered and measured as it leaves the lease.
"Downstream" is anything that happens from the gross value at
the point of production towards the market. "Upstream" is the
operating and capital cost to produce the oil. The "net value"
is the gross value less the production operating and capital
costs and less the exploration costs. In the current production
tax, the term used for net income is "production tax value."
1:14:43 PM
MR. MARKS illustrated how the net value per barrel would be
calculated (slide 8). At a market price of $90 per barrel, less
a marine shipping cost of $2 per barrel and a TAPS tariff of $4
per barrel, the gross value is $84 per barrel. This $84 would
be the basis for the royalty. For Prudhoe Bay this gross value
is at Pump Station 1; other fields have pipelines to get the oil
to Pump Station 1, so these fields pay additional pipeline
tariffs that are subtracted to get to their gross values. To
arrive at the net value the capital production cost and
operating production cost, which DOR estimates respectively at
$12 and $11 per barrel for FY 2011, are subtracted from the
gross value. This results in a net value of $61 per barrel at a
$90 market price.
MR. MARKS highlighted the four tax regimes that have occurred
since 1977 when the North Slope began operating. The Economic
Limit Factor (ELF) was in place from 1977-1989, a modified ELF
was in place from 1989-2006, the Petroleum Production Tax (PPT)
[also known as the Production Profits Tax] was in place from
2006-2007, and the current Alaska's Clear and Equitable Share
(ACES) tax law has been in effect since 2007. However, there
are places in current law where ELF still lives on.
1:16:27 PM
MR. MARKS reviewed how the production tax was calculated prior
to the start of Prudhoe Bay in 1977 and which Cook Inlet was
subject to (slide 10). The production tax was levied on a well-
by-well basis. The first 300 barrels per day was taxed at the
higher of 5 percent of gross value or $.17 per barrel. The next
700 barrels was taxed at the higher of 6 percent of gross value
or $.20 per barrel. Any production over 1,000 barrels per day
was taxed at 8 percent of gross value or $.27 per barrel. The
cents per barrel was indexed for inflation every year.
MR. MARKS said it was known prior to 1977 that Prudhoe Bay was
going to be a big deal and therefore it made sense to re-look at
the tax given that Prudhoe Bay would be different than Cook
Inlet. The Department of Revenue commenced a study and made
recommendations for what it believed an appropriate tax, which
became known as the Economic Limit Factor (ELF). As a field
nears the end of its life a point is reached at which the
operating royalty and taxes exceed the revenues (slide 11). The
philosophy behind ELF was that the burden of tax should not
cause a field to shut down when it reaches this economic limit.
Thus, ELF was designed to scale down the production tax as
production declined over the life of the field, with the tax
becoming $0 at the point of economic limit. The proposed
legislation would have required a monthly calculation of the
number of barrels needed at that month's oil price to cover the
operating cost, and those would be tax free to cover the
operating costs at the economic limit. However, the legislature
instead passed a bill that provided for the first 300 barrels
per well per day to be tax free.
1:19:34 PM
MR. MARKS explained that under the original ELF formula, the
percentage of production greater than 300 barrels per well per
day was the percentage that paid the tax; it was computed on a
field-wide basis (slide 12). For example, if a field's average
production was 1,000 barrels, 300 would be divided by 1,000 to
arrive at 0.3. Subtracting 0.3 from 1.0 would arrive at an ELF
of 0.7. The 0.7 was multiplied by the nominal tax rate to
arrive at the effective tax rate. When a field declined to an
average of 300 barrels per well per day, the ELF was 0 and the
tax was 0 (slide 13). Or, put another way, the ELF was a 300
barrel standard deduction. He noted that there was also a gas
ELF under which 3,000 million cubic feet (MCF) per well per day
was tax free.
1:21:18 PM
MR. MARKS pointed out that the Cook Inlet wells had lower
productivity than the North Slope wells and this lower average
productivity resulted in a higher tax rate. Therefore, an
exponent was added to the ELF to provide a tax break to the
older Cook Inlet wells (slide 14).
MR. MARKS outlined how the ELF was applied (slide 15). He
reiterated that the ELF is a fraction between 0 and 1 and is
calculated on the average of all productivity in a given field.
Between 1977 and 1981, the ELF was applied to the nominal tax
rate, which was 12.25 percent of gross. Thus, if the ELF was
0.5 percent, the effective tax rate would be 6.125 percent (0.5
times 12.25). The nominal tax rate for gas was 10 percent.
MR. MARKS recounted that between 1981 and 1989, changes were
made to the ELF in association with changes in the state
corporate income tax. The ELF was kept the same but changes
were made to how it would operate and to the nominal tax rates.
Those changes affected how the corporate income tax works today.
1:23:21 PM
MR. MARKS returned to slide 5 to elaborate, explaining that most
states do not have oil and therefore their corporate income
taxes use the apportionment factors of property, payroll, and
sales. Alaska was using these same apportionment factors when
the North Slope first opened. However, this method created two
problems for Alaska. The first was that when a company is
relatively more profitable in a state per unit of property,
sales, or payroll, that income gets drawn out of the state under
apportionment. If a company is relatively less profitable, more
income gets drawn into the state. With the startup of Prudhoe
Bay, the producers' Alaska operations became very profitable
relative to the rest of the world. The second problem was that
the sales factor was very low because most of the oil was sold
in the Lower 48. These two factors resulted in the corporate
income tax being very low. To fix these problems the state
changed the income tax to separate accounting, which ring fenced
Alaska as itself and measured net income based only on what goes
on in the state, thus causing the corporate income tax to go up
several hundred million dollars.
1:26:35 PM
MR. MARKS related that the producers sued the state claiming
that Alaska's separate accounting resulted in double counting of
income between what would be taxed in Alaska and what would be
taxed in other states. The producers further claimed that
separate accounting was discriminatory because the separate
accounting only applied to the oil industry in the state. While
the state eventually won the case in the U.S. Supreme Court in
the late 1980s, it did not know for sure in the early 1980s that
it would do so and a very large liability was accruing should
the state lose the case. To hedge its bets, the state changed
the corporate income tax to modified apportionment by swapping
the payroll factor for the production factor. Since Prudhoe Bay
was so prolific, using production as an apportionment factor
would draw in a lot more worldwide income. He recalled being
told anecdotally that producers had indicated in discussions
that they would not find modified apportionment legally
objectionable.
MR. MARKS explained that going from separate accounting to
modified apportionment would result in the state taking an
income hit on the corporate income tax (slide 15). To offset
this, the state made changes to the severance tax in 1981. The
changes were expected to be approximately revenue neutral and
were therefore like buying insurance in case of a bad outcome in
the U.S. Supreme Court. One change consisted of applying the
nominal rate of 12.25 percent of gross to only the first five
years of a field and thereafter the nominal rate would be 15
percent. Another change, applicable to the first 10 years of a
field, was the "rounding rule" in which the ELF was rounded up
to 1.0 if it was greater than 0.7. This rounding rule, however,
created a time bomb that went off when Prudhoe Bay had its 10-
year anniversary.
1:29:24 PM
MR. MARKS, in response to Co-Chair Seaton, said that prior to
PPT the taxes were based on gross, so [during the era of ELF]
the state did not have a very good idea of what the upstream
capital and operating costs were and subsequently what the net
value was. At oil prices of $15-$20 per barrel during this era,
he said his educated guess is that upstream costs during that
time were probably in the range of $5-$10 per barrel, so the net
value would probably have been $5-$10 per barrel. He offered to
get back to members with further information.
1:31:12 PM
MR. MARKS returned to his presentation and outlined the problems
with the first ELF (slide 16). One problem was that 300 barrels
was very arbitrary for covering operating costs at the economic
limit, because at an oil price of $5 per barrel a lot more
barrels would be needed to cover operating costs than would be
needed at a price of $20. Additionally, the 300 barrels was
fairly generous in terms of covering operating costs. A second
problem was that every time a well was drilled the average well
productivity went down. A third problem was that oil fields
naturally decline in production, so even if the number of wells
remained the same the well productivity declined. Thus,
drilling more wells and natural field decline resulted in a
constant reduction of the effective tax rate, regardless of what
was going on with price.
MR. MARKS stated that another problem with ELF was that under
some circumstances wells could be drilled for no other purpose
than to drive down a company's tax rate. He said he does not
know whether producers were really doing that, but the ELF
effect had to be part of the equation when producers were
evaluating their after-tax drilling programs. For example,
there were a few years where the ELF for the Kuparuk field was
at 0.69. The rounding rule would have made it very advantageous
to keep the Kuparuk field below 0.7 to provide a big tax
savings.
1:33:54 PM
MR. MARKS reported that a convergence of problems occurred in
the late 1980s (slide 17). First was the oil price crash of
1986 in which the price declined to about $6 per barrel and did
not recover much by 1987 or 1988. Second was declining
production, which coupled with low oil prices affected state
revenues a lot. Third was the declining ELF along with the
declining tax rate. Then, in 1987, the 10-year rounding rule
for Prudhoe Bay kicked in. He elaborated on the Prudhoe Bay
rounding rule problem by turning to slide 22, which depicts the
total average production for all fields on the North Slope under
the economic limit factor from 1978 to just beyond 2003. He
explained that well productivity from the Prudhoe Bay field was
very high - just under 0.95 - at the field's start in 1977.
When the Kuparuk field started in 1981 the ELF average dipped a
little bit. Then, after the rounding rule began, the ELF went
way up. The 10-year rounding rule for Prudhoe Bay expired in
1987, resulting in a huge drop in Prudhoe Bay's ELF and creation
of the time bomb previously mentioned. The weighted average ELF
for the North Slope dropped from about 0.94 to about 0.78, which
was worth about $200 million [per year].
MR. MARKS, in response to Co-Chair Feige, clarified that the 10-
year rounding rule began in 1981. For the first 10 years of a
field, this rule provided that if the ELF was greater than 0.7
it would be rounded up to 1.0. So, instead of multiplying the
nominal rate by 70 percent, it was multiplied by 100 percent.
1:36:04 PM
MR. MARKS related that at the time the rounding rule was put in,
people understood that there was going to be a big problem when
the Prudhoe Bay field hit 10 years. He read the following
statement made by then-Governor Hammond in 1981:
As far as the possible revenue effects in 1988 and
beyond, I have full confidence in the ability of the
legislature to deal at the time with whatever is
required to retain the state's fair share of our oil
wealth.
1:37:01 PM
MR. MARKS stated that in 1987 then-Governor Cowper began trying
to change the ELF system (slide 17). Many of the state's
economists, himself included, encouraged the scrapping of ELF
and the adoption of a net tax. Hugh Malone, DOR commissioner at
the time, understood the ELF problem and why a net tax would be
preferable, but it was Commissioner Malone's judgment that
changing from a gross to a net system would create so much
confusion that it was better to keep with the ELF form as a way
of minimizing chaos. The ELF form was modified to bring in the
new element of field size in addition to well productivity.
Field size would be another proxy for profitability because
bigger fields are generally more profitable. The bigger fields
would pay more, the smaller fields would pay less, and this
would bring in more revenue as well as encourage development of
small fields. Under ELF II [1989-2006], fields with greater
than 150,000 barrels per day would have relatively less than 300
barrels tax free per well per day and fields smaller than
150,000 barrels a day would have relatively more tax free
barrels. A proposal in 1987 did not pass and neither did a
proposal in 1988. The third proposal (slide 18) passed by only
one or two votes on the last day of session in 1989. He offered
his opinion that had the Exxon Valdez oil spill not occurred
this third proposal would not have passed.
1:40:19 PM
MR. MARKS illustrated how the amount of ELF II depended on both
the daily field productivity and the well productivity, with the
ELF rising correspondingly higher with increased field size
(slide 19). Applying ELF II to the 15 percent nominal rate
increased state revenue by about $300 million per year, thus
bringing the ELF back to where it was prior to 1988 when the
rounding rule kicked in. However, he continued, it is important
to look at what happened with small fields under ELF II. A
5,000-barrel-a-day field had no ELF and paid no tax no matter
what its well productivity. A 20,000-barrel-a-day field, which
is a hefty field size for North Slope standards, paid no ELF
when the field average per well per day was below 2,000 barrels.
Under ELF II, only three fields on the North Slope had a
positive ELF - Prudhoe, Kuparuk, and Endicott. The other fields
had no ELF and paid no tax, which caused problems later on.
1:42:16 PM
MR. MARKS explained that while ELF II got things back to where
they were prior to its passage in 1989, the same problem re-
occurred. Field size and well productivity continued to
decline, again resulting in a decline of the tax rate regardless
of what else was happening. Another problem was the
proliferation of field satellites (slide 20). When ELF II was
passed in 1989, five wells were operating on the North Slope -
Prudhoe, Kuparuk, Milne Point, Lisburne, and Endicott. After
passage of ELF II, industry came to the state concerned about
the satellite development that it was going to be starting up.
Satellites are small fields developed in association with the
main field and they share drilling and processing facilities.
1:44:18 PM
MR. MARKS further explained that a provision since the start of
ELF I allowed the [Department of Revenue] to aggregate fields
for determining the ELF if it found that the fields were
economically interdependent. Aggregating fields under ELF I was
not a big deal and did not affect taxes because the fields had
approximately the same well productivity. But under ELF II
aggregating fields was a big deal because of the field size
factor. Industry was concerned that if the department exercised
its authority to aggregate the fields it would make the fields
uneconomic either by the high taxes that would ensue or because
new facilities would have to be built to avoid being aggregated.
Governor Cowper said the intent of ELF II was to encourage small
fields, so the department drafted regulations that would allow
it to give advance rulings to the producers that would not
aggregate fields under certain conditions.
1:45:30 PM
MR. MARKS outlined the four basic conditions in these
regulations under which the department could give an advanced
ruling not to aggregate (slide 21): 1) if the shared facilities
reduced costs, 2) if the advanced ruling enhanced the likelihood
of development, 3) if oil from each field could be accurately
measured, and 4) if the shared facilities was the only factor
making the fields interdependent. The department carefully
studied the requests it received and granted several for
satellite development configurations. A little before the year
2000, the department received a request for an advanced ruling
for Prudhoe Bay to not aggregate six new satellites that were
under development. By this time, however, the department's
understanding of satellite development was evolving. One
particular aspect disturbing the department was the practice of
"back out" and how it created a new dimension regarding the
meaning of interdependence under Condition 4. Mr. Marks
elaborated that all oil fields have gas that comes up with the
oil. The unit's processing facility separates the gas and the
gas is then injected back into the well; so, as a field matures,
more and more gas comes up with the oil. However, a processing
facility can handle only so much gas depending upon its size.
Therefore, to handle the high gas to oil situation of an older
field, oil from the high-gas field was throttled back and oil
that had less gas was brought in from another field.
1:49:05 PM
MR. MARKS noted that while the statute gave the department the
authority to aggregate fields if those fields were economically
interdependent, the statute did not define interdependent.
After mulling over this problem for several years, the
Department of Revenue and the Department of Law came up with an
interpretation of interdependent that meant the Prudhoe Bay
satellites and main Prudhoe Bay field should be aggregated for
ELF purposes. In 2005, then-Governor Frank Murkowski concurred
with the departments and aggregated the six satellites and the
main field. However, fields that had already been given the
advanced rulings were not touched because the thought was that
those fields had been developed under a good-faith agreement.
The 2005 aggregation decision raised the Prudhoe Bay field size,
causing the main field's ELF to go up from 0.8 to 0.9, and the
ELF for the satellite fields went from 0 to 0.9, which was worth
about $150 million. He said he believes that decision is still
being challenged in court.
1:50:54 PM
CO-CHAIR SEATON understood the definition of satellite fields to
be reservoirs that are at different vertical depths under the
same drilling platform.
MR. MARKS expounded on what is meant by field. Units are an
administrative concept for how leases are managed by the
Department of Natural Resources. A unit generally consists of
several accumulations that are under some sort of common
management system. For example, the big Kuparuk field was
started in 1981 and then some other fields - Tarn, Tabasco, and
Meltwater - were found near it. Technically, these fields are
called participating areas; they are a distinct oil accumulation
not in any pressure communication with any other accumulation.
A unit consists of several of these participating areas. The
main field is a participating area with these other fields
sharing the same drill pad and same processing facilities, so
there is some integration to how they are operated and managed.
1:53:17 PM
MR. MARKS pointed out that while the ELF for the North Slope had
an uptick in 2005 when Prudhoe Bay was aggregated, the ELF had
been steadily declining over the previous decade (slide 22).
Many people were concerned about this decline and deemed the ELF
broken. The Kuparuk field was seen as the poster child for "the
ELF is broken" because by 2005 its well productivity was very
close to 300 barrels per day. Thus, Kuparuk's ELF was about to
become zero even though its production of about 130,000 barrels
per day made it one of North America's largest fields.
1:54:25 PM
MR. MARKS related that the ELF was done away with through the
1998 Stranded Gas Development Act (SGDA) (slide 23). The SGDA
set out to get a gas line by way of giving the administration
the authority to negotiate with the producers a tax system for
gas. Once that system was negotiated it was to be put in
contract rather than statute so that there would be fiscal
stability. Negotiations started in 2004 but stalled about two
years later because producers wanted fiscal stability for oil.
Wanting fiscal stability for oil was not frivolous, he said,
because producers feared that if the state later became unhappy
with the gas contract, the state would be able to take it out of
the producers' hide on oil, given that the companies producing
gas were the same companies producing oil. Since the SGDA did
not authorize fiscal stability for oil, Governor Murkowski said
the state would give that stability but the ELF would be
replaced with a new oil tax system. Governor Murkowski asked a
consultant, Dr. Pedro van Meurs, to design an oil tax system
that would protect Alaska's interests and be internationally
competitive. Dr. van Meurs designed an oil tax proposal called
the petroleum production tax (PPT), which was based on net
income rather than gross income. This proposal, a public
document published on 2/14/06, recommended a 25 percent tax rate
and a 20 percent credit rate on capital cost. It did not
include any progressivity because Dr. van Meurs was looking to
make the system internationally competitive and the other
jurisdictions that Alaska was competing with did not have
progressivity. Additionally, Dr. van Meurs proposed a system of
credits associated with production tax that the state largely
still has.
1:57:53 PM
MR. MARKS said the Murkowski Administration's position when it
began negotiations with producers was a 25 percent tax rate and
a 20 percent credit rate. What came out of the negotiations was
a 20 percent tax rate and a 20 percent tax credit, which was a
sizeable tax increase over the ELF. Arm-in-arm with the
producers, the administration then went to the legislature with
this proposed oil tax system and proposal to amend the SGDA to
allow fiscal stability for oil. The legislature was not
supportive of the gas deal that the administration had struck
with the producers, so the legislature took that proposal and
used it as a starting point for amending the severance tax
statute and getting rid of the ELF. The [Production] Profits
Tax (PPT) [also known as Petroleum Production Tax], a net tax,
was adopted in 2006. Most every economist believes that a net
system is a much more efficient way to tax than gross. One
reason why relates to production costs. A barrel of light oil
on the North Slope might cost $10 per barrel to produce and a
barrel of heavy oil might cost $30. Under a gross system, they
would pay the same amount of tax, but a net system would
recognize that difference. Another reason why is that under a
net system costs can be deducted, but under a gross system they
cannot. In 2006 the administration recognized that the pipeline
was running in excess of 60 percent empty. A net system would
be in the state's best interest because a company could reduce
its taxes by investing in Alaska and deducting the cost, whereas
under a gross system the profits would be taken and invested
elsewhere where they can be deducted.
2:01:00 PM
MR. MARKS explained that the legislature made two main changes
to the administration's "20/20 proposal" when it came up with
the PPT. First, the tax rate was raised to 22.5 percent of
production tax value, also called net value. Second, a
progressivity element was added. Progressivity was triggered
when the net value exceeded $40 a barrel, at which point the net
value was multiplied by .25 percent. The term for how fast the
tax rate increases as value goes up is called the slope. The
net value is determined by subtracting the transportation and
operating costs, which average $29 per barrel in Alaska, from
the price received per barrel. For example, at a price of $90 a
barrel the net value per barrel is $61.
2:03:32 PM
[A brief at-ease was taken to correct an error discovered on
slide 24 - the progressivity rate was incorrectly shown as 7.75
percent, the correct rate was determined to be 5.25 percent.]
2:03:41 PM
MR. MARKS continued with his aforementioned example, noting that
the progressivity is calculated by subtracting $40 from $61,
multiplying that by .0025, arriving at a progressivity of 5.25
percent. That 5.25 percent is added to the 22.5 percent base
rate to arrive at a total tax rate of 27.75 percent. The $61
net value is multiplied by 27.75 percent to arrive at a tax of
$16.93 per barrel.
MR. MARKS noted that the progressivity under PPT peaked at 25
percent. Along with this was another provision for capital
costs. The PPT was being debated in the legislature at the same
time that there was a big corrosion spill on the North Slope,
which caused concern that deductions should not be allowed for
maintenance that should have been done. As a result, $.30 a
barrel was subtracted from capital costs for what could be
deducted as a sort of maintenance provision. The PPT also
established credits, but those were not changed much by ACES.
Additionally, a floor was put in, with the floor being the
higher of 4 percent of gross or the PPT.
2:05:59 PM
MR. MARKS illustrated the .25 percent slope of the severance tax
rate under PPT at various net values per barrel (slide 25) and
the PPT severance tax per barrel at various net values per
barrel (slide 26). He said it was decided that Cook Inlet
should stay at the ELF that was in place in April 2006 when the
PPT went into effect, which is also the case under current law.
So, Cook Inlet oil pays zero ELF, zero tax, and Cook Inlet gas
pays $.17 per million cubic feet (MCF) in production tax. Under
current law those provisions stay in place until 2022.
2:07:48 PM
MR. MARKS discussed the three main problems with PPT (slide 27).
First, because the state had previously been under a gross tax,
the Department of Revenue did not have a clear idea of what the
deductible costs would be. So, while PPT was under debate, the
department had to estimate those costs in the absence of perfect
information. Second, even if the department had had perfect
information, incredible cost inflation took place in the
petroleum sector in 2007, the first year that the PPT was in
effect, resulting in much less revenue than had been expected.
Based on oil prices at the time, the estimate had been for about
$1.1 billion more in production tax but only about $0.3 billion
more came in, a difference of about $800,000 million. The third
problem was what he calls "VECO taint". Evidence arose after
the 2006 session that some votes for PPT may have been
influenced by inappropriate relationships with VECO Corporation,
which caused a lack of confidence in what had happened during
the 2006 legislative session.
2:09:18 PM
MR. MARKS related that after her 2006 election, Governor Palin
decided to look at oil taxes free of the taint. She introduced
a new production tax, Alaska's Clear and Equitable Share (ACES),
which proposed to increase the tax rate to 25 percent, drop the
progressivity trigger to $30, and drop the progressivity slope
from .25 percent to .2 percent.
CO-CHAIR SEATON understood that some of the new wells drilled by
BP under PPT were paid off in 90 days. He asked whether Mr.
Marks recalls this as being another part of the impetus for
changing PPT.
MR. MARKS replied he does not, but that different people may
have different recollections that may be absolutely valid.
2:11:10 PM
MR. MARKS pointed out that in its 2007 session the legislature
made one major change to the Palin Administration's proposal.
The base rate was increased to 25 percent [as proposed], the
trigger was dropped to $30 [as proposed], but instead of
reducing the slope from .25 to .2 [as proposed], the slope was
increased to .4 percent. Noting that ACES operated exactly like
PPT, he used his previous example of a $90 price and $61 net
value per barrel to calculate the tax under ACES: progressivity
is calculated by subtracting $30 from $61, multiplying that by
.004, arriving at a progressivity of 12.4 percent; that 12.4
percent is added to the 25 percent base rate to arrive at a
total tax rate of 37.4 percent; [the $61 net value is multiplied
by 37.4 percent to arrive at a tax of $22.81 per barrel.] Under
current ACES law, the progressivity slope drops to .1 percent
when the progressivity reaches 50 percent, which is at $92.50
net. He noted that some changes were also made to the credits.
2:12:59 PM
MR. MARKS compared the ACES and PPT severance tax rates (slide
29). Under ACES, progressivity is triggered at $30 compared to
$40 under PPT; ACES has a steeper slope [.4 percent] than PPT
[.25 percent]; under ACES, when the net value per barrel hits
$92.50, the slope drops from .4 to .1 percent, but under PPT the
severance tax rate peaked at 50 percent and then remained flat.
Comparing the ACES and PPT severance taxes per barrel (slide
30), he reported that when oil prices averaged about $100 per
barrel in 2008, ACES brought in about $2 billion more than PPT
would have.
MR. MARKS reiterated that the ELF provisions for Cook Inlet were
kept in ACES. Additionally, a new provision in ACES provides
that any gas used in-state for fuel, meaning fuel used for space
heat or power production, is also subject to the April 2006 Cook
Inlet ELF of $.17 per MCF, which grandfathers out in 2022.
2:14:27 PM
MR. MARKS compared the ELF, PPT, and ACES severance tax rates as
a percent of net under various Alaska North Slope (ANS) market
prices based on a cost of $29 [slide 31] and a cost of $39
[slide 32]. On a percent of gross the ELF is just flat: if ELF
was still in effect right now and DOR figures are used, the
weighted average ELF would be about .37, which when multiplied
by a 15 percent tax rate comes out to an effective tax rate of
5.5 percent of gross flat. He explained that as prices go up
the net is a higher percent of gross, so when a flat percent of
gross is put on a net basis, it is a decreasing percent of net,
which is why the ELF curve slopes downward on the graph. He
interjected that this is also how royalties currently work: as
prices go up, the royalty, which is 12 percent of gross, becomes
a smaller percent of net.
2:16:32 PM
MR. MARKS noted that on slides 31 and 32 the ANS market price
begins at $50 per barrel. However, at ANS market prices below
$50 the ELF severance tax gets "weird" [supplemental slides].
He reiterated that the ELF is based on gross and gross is the
difference between market price and transportation cost, which
in Alaska is about $6. Until oil prices reach $6, there is no
gross value, so ELF is zero. However, even though the ELF
becomes positive at a price of $6, the ELF curve is negative
when calculated as a percent of net because the net value is
negative until a price of $29 a barrel is reached. When a
positive net value is reached at $29 a barrel, the ELF then
shoots up because a positive value is divided by a positive
value. In response to Co-Chair Seaton, Mr. Marks confirmed that
if this ELF was expressed as actual money paid, the ELF would be
positive.
2:19:44 PM
MR. MARKS added that he did not have time to make models of
another dimension of ELF, PPT, and ACES, which is that they have
"higher of" provisions. For PPT and ACES, it is the higher of 4
percent of gross or the PPT calculation, and under ELF there was
also a minimum tax of $.80 per barrel. Regarding the two
supplemental slides, he added that the ELF spikes at a price of
just over $39 a barrel because it is a tax based on gross which
is a very, very high percentage of net, and this is why most
economists believe that taxes based on gross are not efficient.
2:21:11 PM
MR. MARKS reviewed the credits, many of which came out of Dr.
van Meurs' recommendations and which still exist today (slide
33). One is the 20 percent credit on capital costs. Another is
a 40 percent well lease expenditure credit for areas outside the
North Slope; these credits are directly related to drilling
wells and were put into law last year. Governor Parnell's bill,
HB 110, proposes to expand that 40 percent credit to include the
North Slope. There are exploration credits ranging from 20
percent to 40 percent depending on the location of the bottom
hole in the exploration well and depending on whether the well
is inside or outside of an existing unit or how far the well is
from an existing unit. There is a credit of $12 million for
companies that produce less than 50,000 barrels per day and that
have enough offsetting income. Last year some very aggressive
credits were added for the first three parties to explore the
Cook Inlet pre-Tertiary zone with a jack-up rig. The first
party will receive a 100 percent credit up to $25 million, the
second party will receive a 90 percent credit up to $22.5
million, and the third party will receive an 80 percent credit
up to $20 million. If there is any commercial production as a
result of this exploration, 50 percent of the credit will have
to be re-paid. There is no double-dipping on the credits - an
expenditure used for claiming one credit cannot be used for
claiming a second credit.
2:23:42 PM
MR. MARKS noted that a company unable to use all of its
deductions because of a net operating loss can convert its
unused deductions at 25 percent to a credit (slide 34). There
is a floor of zero of the tax, so a company that cannot monetize
its credits because it is down to zero tax can either keep the
credit until it has sufficient offsetting income or can sell its
credits to other taxpayers. When selling credits, a company
will always get less than 100 percent on the dollar; however,
under an ACES provision for companies producing less than 50,000
barrels a day, the state will buy the credit.
REPRESENTATIVE GARDNER, referencing a previous Department of
Revenue presentation before the committee, understood that the
small company credit and another $6 million credit were
cumulative. She asked whether that is an exception to the rule.
MR. MARKS replied correct, an additional $6 million credit is
available to anyone, not just small companies, for producing
either non-North Slope or non-Cook Inlet. Because it expires in
2016, he said he doubts that the credit will ever be used. The
credits of $12 million and $6 million are use-or-lose credits,
so if a company does not have offsetting income in the year it
earns the credit, the credit cannot be carried over.
MR. MARKS concluded his presentation by reporting that between
1977 and Fiscal Year 2010 a total of $40 billion in severance
tax has been collected from across the state (slide 37).
2:25:53 PM
The committee took an at-ease from 2:25 p.m. to 2:29 p.m.
2:29:50 PM
CO-CHAIR SEATON requested Mr. Marks to tell where the figure of
$12 million came from and how it was arrived at.
MR. MARKS responded that the $12 million credit is a second area
where ELF lives on. When Dr. van Meurs was designing the PPT he
understood that there were some projects under development,
small fields, that would have had a zero ELF and companies had
started developing these fields assuming they would be under ELF
and have a zero tax. This provision was put in so that small
development would continue to have a zero tax; additionally, it
would create an incentive for small companies to produce small
fields. Dr. van Meurs arrived at the $12 million by looking at
the amount of oil these fields would produce and the price of
oil, which was $45 a barrel at that time. He then backed in the
amount of credit a company would need to bring the tax to zero
under PPT, and that was $12 million. Quite frankly, he added,
another reason for putting in this credit was to get political
support for the PPT from small companies during the 2006
session.
CO-CHAIR SEATON expanded on Mr. Marks' response, saying that it
was looked at as $60 million in deduction, so that for the first
$60 million of production from a field the company would not
have a tax. This was later converted at 20 percent to a tax
credit of $12 million because that was easier to implement.
MR. MARKS concurred.
2:32:20 PM
REPRESENTATIVE HERRON, saying he understands why the credits of
$12 million and $6 million were needed to get buy-in for passing
the PPT, asked whether it is important to maintain these two
credits or to increase the amounts.
MR. MARKS answered that he would say it is for small fields. He
clarified that it is not really small fields, it is small
companies. Getting into new areas gets into really high costs,
and these credits create additional incentives for small
companies to come in. Additionally, the biggest risk takers
around the world are the small companies. As a way to get small
companies into Alaska, to get bigger risk taking, it probably is
a good feature to retain as a way to encourage a wider number of
views as to what is geologically attractive.
2:33:59 PM
REPRESENTATIVE HERRON inquired whether it would have a profound
effect on the taxes if the state was to figure out how to value-
add the resource, which in this case is oil. For example, if
the oil was refined in the state and then left the state as a
refined product, would the severance tax, the tax on that oil,
be significantly different?
MR. MARKS replied that what gives value to the oil is its market
price. The value of what comes out of the ground is its market
price less its cost, and that is the tax base. When value is
added, cost is added, and while there is a little bit of profit
on that, the basic feedstock that goes into a refinery basically
reflects the value of the oil which is being taxed, which is how
the severance tax is based. As a feedstock to a refinery, it is
the same thing - it is the value of the oil.
REPRESENTATIVE HERRON expressed his frustration that [a raw
resource has more value than a finished product]; for example, a
log exported from the state in the round has more value than
manufacturing that log into lumber in the state and exporting
that finished lumber.
CO-CHAIR FEIGE suggested looking at what kind of credits could
be given for in-state use.
2:36:46 PM
REPRESENTATIVE MUNOZ, regarding the PPT progressivity that
kicked in at $40 profit per barrel, asked whether that tax
applied to the full profit or just to the profit over $40.
MR. MARKS directed attention to slide 24 and explained that for
this example the total PPT tax rate with progressivity and the
base rate is 27.75 percent. He said it is important to
understand why there is discussion about the high marginal tax
rate under ACES. Under ACES, progressivity starts when [the
profit] goes above $30, at which point [12.4] percent
[progressivity] is added to the 25 percent [base rate] to arrive
at [a total tax rate] of 37.4 percent. This 37.4 percent does
not apply to the thirty-first dollar, it goes all the way back
to the very first dollar and applies to every single dollar of
value, and this is the genesis of the argument by some people
that ACES has high marginal tax rates. In further response, he
confirmed that this same method was used under PPT.
2:38:48 PM
REPRESENTATIVE MUNOZ understood that Prudhoe Bay, Kuparuk, and
Endicott were the only fields that paid under the ELF factor.
MR. MARKS responded after it passed in 1989 (indisc.)....
REPRESENTATIVE MUNOZ requested Mr. Marks to explain again why
the Kuparuk field was the poster child for a broken ELF.
MR. MARKS answered that the ELF was going down, down, down.
Between 2000 to 2005 or so, Kuparuk was producing about 130,000
barrels a day at very healthy prices at the time of $40 to $50.
Despite being one of the largest fields in North America, it was
paying just about zero tax because of the ELF calculation, and
that is what he means by the poster child of a broken ELF - a
very, very economically healthy field was paying no tax.
REPRESENTATIVE MUNOZ asked whether the changing of Alaska's tax
regime 4 times in 25 years would be considered erratic or
unusual as compared to other oil provinces in the world.
MR. MARKS replied that most oil companies generally expect that
an oil tax will change about every 10 years.
2:40:46 PM
CO-CHAIR FEIGE noted that the committee is trying to put more
oil in the pipe, so in its immediate deliberations the committee
is not necessarily looking at how much money the state is making
or how much profit the oil companies are making. The objective
is to structure HB 110 in the best way for putting more oil in
the pipe. All kinds of different development could happen on
the North Slope - new fields adjacent to currently unitized
areas; development within each unitized area; different kinds of
oil such as heavy, viscous, and source rock; and tapping
individual fault blocks using directional drilling. He asked
Mr. Marks to provide his opinion on the best way to structure HB
110 to encourage companies to put more oil in the pipe.
2:42:08 PM
MR. MARKS responded that under the progressivity structure, when
the price goes up $1, the tax rate is drawn up for every single
dollar below that. The concept of marginal tax rate is that
when the price of oil goes up $1, what percentage of that dollar
goes to government? Progressivity is an absolutely fine and
straight-forward philosophy that at lower income a company can
afford to pay less, so there is a lower rate, and at higher
income a company can afford to pay more, so there is a higher
rate. In his judgment, the progressivity structure within ACES
is seriously dysfunctional because of the way it works. When
the value goes up from $89 to $90, not only does the tax rate on
the ninetieth dollar go up, the tax rate on all the previous
dollars of value is drawn up as well. That is what is called a
high marginal tax rate, and it can exceed 90 percent at high
prices. This is a problem because when a company looks at
developing a prospect it looks at the expected price. Since
prices are very volatile and hard to forecast, a company looks
at what is going to happen under a range of prices and there are
now non-frivolous oil price forecasts that go up to $200 per
barrel by 2020. Most people expect that more things can happen
to make prices go up in the future than down. So when companies
look at their price forecasts and how things work under a
variety of prices, what happens on the high side of high prices
can be very important to their outcome because if high prices
materialize they can make a lot of money.
2:44:49 PM
MR. MARKS pointed out that the high marginal tax rate of ACES
caps upside potential because as price goes up the marginal tax
rate gets higher and higher to the point where not much money is
being made by the company anymore. From what he can tell,
Alaska, at high prices, has the highest marginal tax rates in
the world, and he believes this makes Alaska seriously
uncompetitive. Evidence for this is Department of Revenue data
that shows only three exploration wells drilled in 2010 - the
smallest number of exploration wells since 1988 when prices were
$8 a barrel, which he thinks is a problem.
2:46:08 PM
MR. MARKS said he believes that the PPT was as dysfunctional on
the upside as ACES because it had the same progressivity
structure. A comparison of Department of Revenue or Department
of Natural Resources production forecasts made in 2006, before
PPT, with current forecasts for the years 2010 to 2020 shows a
reduction of hundreds and hundreds of millions of barrels. This
reduction is not because a field that was thought would come
online did not materialize; it is for basically the same fields
- the core fields of Prudhoe Bay, Kuparuk, and Alpine. Eighty
to ninety percent of the oil in the forecasts is forecast to
come from these core fields because there is a lot of oil to be
developed from them. While ACES and PPT may not be 100 percent
of the cause for this reduction, he believes they are a major
contributing factor.
2:47:15 PM
MR. MARKS stated this could be fixed by fixing the progressivity
structure. The bracketing proposed by HB 17 and HB 110 would
provide for an incremental tax paid on an incremental value,
which lowers the marginal tax rates and is how progressivity
universally works around the world. He has spent a lot of time
on this and nowhere else in the world has he encountered a
progressivity structure like the one in PPT or ACES, be it oil
or non-oil. He said his judgment is to go to a bracketed tax
structure and to use international competitiveness to come up
with comparable marginal tax rates. He added that he thinks the
current credit system is very strong and very good for
encouraging development, so he would not focus on the credits.
Credits coupled with deducting costs are significant incentives
for developing, but the high tax rates dwarf anything the
credits do. In his judgment, fixing the progressivity structure
will put more barrels in the pipeline.
2:49:00 PM
CO-CHAIR FEIGE noted that under the current system the capital
costs are reported as one item and include operations and
maintenance as well as exploration. He asked whether there is
any advantage to having companies report those exploration,
operations, and maintenance costs separately and then adjusting
the credit structure to apply to either side of that, such as
favoring more exploration and development versus operations and
maintenance.
MR. MARKS answered that it is all production because, in a way,
even maintaining things is production. Encouraging producers to
maintain their fields is wanted and the credits do that as well.
He reiterated that he thinks the current credit structure is
strong and he would focus on the progressivity structure rather
than the credits.
REPRESENTATIVE FOSTER noted that the taxes for individual people
are based on incremental taxation for the incremental value and
do not go retroactive to the first dollar that a person makes.
He understood this to be the point that Mr. Marks is making.
MR. MARKS replied exactly; what is proposed in HB 17 and HB 110
mirrors the Internal Revenue Service (IRS) tax booklet.
MR. MARKS, in response to Co-Chair Feige, said the IRS does have
progressivity, and it is bracketed.
2:52:00 PM
CO-CHAIR SEATON, referring to slide 31, asked what is the effort
being undertaken by an oil company to have the ANS market price
change from $90 a barrel, where the tax rate is about 36
percent, to $125 a barrel, where the tax rate is 50 percent. In
response to Mr. Marks, he noted that the state is charging a
severance tax for a non-renewable resource that is being taken
out of the state. In further response to Mr. Marks, he re-
phrased his question by asking what is a company doing that it
should keep basically most all of that profit difference between
$90 and $125 instead of having significant progressivity.
2:54:18 PM
MR. MARKS allowed that even under ACES the producers are making
a lot of money, but the question is how much more money can they
make somewhere else. At the corporate level corporations have a
finite amount of capital. In today's age of globalization this
capital is very fluid and an oil company can put capital lots of
places. For example, ConocoPhillips has presence in more than
30 countries and can choose to put its money where it will get
the most for that money, which is why looking at international
competitiveness is key. One would think that as prices go up
production would go up, [but in Alaska] the production forecasts
have dropped between 2006 and now. He said he truly believes it
is very possible that because of ACES, when the price goes up
the schism between Alaska's tax and international competitive
tax rate widens. The higher the prices the more capital gets
diverted from Alaska to elsewhere, so at higher prices Alaska
gets less oil.
2:56:02 PM
CO-CHAIR SEATON understood Mr. Marks to be saying the companies
do not do anything to change the price from $90 to $120.
MR. MARKS responded that they do not.
CO-CHAIR SEATON surmised that Mr. Marks is saying the state can
expect the companies to continue removing their investment from
oil in Alaska to gas, which legislators are being told is very
unprofitable. For example, ConocoPhillips has a much higher
percentage of profit coming from its Alaska investment than from
its international investments, which are gas investments; yet
ConocoPhillips is going to take its capital from Alaska and put
it in those gas projects because of the marginal tax rate in
Alaska, even though its percentage increase in profits in Alaska
is much larger than it is internationally.
MR. MARKS answered that ConocoPhillips is an oil and gas company
with interests all around the world; worldwide it produces about
50 percent oil and 50 percent gas. It can invest in oil in
Alaska or elsewhere and if it can earn more profit elsewhere
than it can in Alaska, it will go elsewhere. That is why he
believes Alaskans should be very concerned about how the state
competes. Fair value for oil is no different than fair price
for a loaf of bread. Fair is what can be received in a
competitive environment and as an economist this is how he sees
fair share, although others might see it differently. In his
opinion, if Alaska thinks it is entitled to more than that, it
might end up in a not-very-good place.
2:59:08 PM
REPRESENTATIVE HERRON observed that current law stair steps up
to a certain value and then progressivity takes off; the
proposed legislation stair steps to a certain value and then
goes flat. He said he is unsure whether he supports it being
flat at around $100 because he thinks it should stair step down
to encourage oil development and production. In response to Mr.
Marks, he confirmed he is meaning that it should stair step down
at high prices because more money is needed back in the state to
fill the pipeline.
MR. MARKS replied that the state's interests must be protected,
too. Looking at the international environment, he said he does
not think that stair stepping down at high prices needs to be
done to be competitive. Under these bills the marginal tax
rates peak at about 75 percent, which means the producers walk
away with 25 percent of incremental value. At high prices that
seems to be the lay of the land. He added that the perfect tax
could be passed this year, but that the international
environment must be continually monitored to stay competitive
because that is what life in the age of globalization is.
| Document Name | Date/Time | Subjects |
|---|---|---|
| History of Alaskas Oil Gas Production Tax - Roger Marks 2.9.2011.pdf |
HRES 2/9/2011 1:00:00 PM |
|
| Additional ELF Graphs - Roger Marks Presentation.pdf |
HRES 2/9/2011 1:00:00 PM |