Legislature(2015 - 2016)BARNES 124
03/07/2016 01:00 PM House RESOURCES
Note: the audio ![]()
and video ![]()
recordings are distinct records and are obtained from different sources. As such there may be key differences between the two. The audio recordings are captured by our records offices as the official record of the meeting and will have more accurate timestamps. Use the icons to switch between them.
| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
1:11:08 PM
CO-CHAIR NAGEAK announced that the only order of business is
HOUSE BILL NO. 247, "An Act relating to confidential information
status and public record status of information in the possession
of the Department of Revenue; relating to interest applicable to
delinquent tax; relating to disclosure of oil and gas production
tax credit information; relating to refunds for the gas storage
facility tax credit, the liquefied natural gas storage facility
tax credit, and the qualified in-state oil refinery
infrastructure expenditures tax credit; relating to the minimum
tax for certain oil and gas production; relating to the minimum
tax calculation for monthly installment payments of estimated
tax; relating to interest on monthly installment payments of
estimated tax; relating to limitations for the application of
tax credits; relating to oil and gas production tax credits for
certain losses and expenditures; relating to limitations for
nontransferable oil and gas production tax credits based on oil
production and the alternative tax credit for oil and gas
exploration; relating to purchase of tax credit certificates
from the oil and gas tax credit fund; relating to a minimum for
gross value at the point of production; relating to lease
expenditures and tax credits for municipal entities; adding a
definition for "qualified capital expenditure"; adding a
definition for "outstanding liability to the state"; repealing
oil and gas exploration incentive credits; repealing the
limitation on the application of credits against tax liability
for lease expenditures incurred before January 1, 2011;
repealing provisions related to the monthly installment payments
for estimated tax for oil and gas produced before January 1,
2014; repealing the oil and gas production tax credit for
qualified capital expenditures and certain well expenditures;
repealing the calculation for certain lease expenditures
applicable before January 1, 2011; making conforming amendments;
and providing for an effective date."
1:11:26 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
on behalf of the governor, provided a PowerPoint presentation
entitled, "Oil and Gas Tax Credit Reform- HB247, Additional
Modeling and Scenario Analysis - Part 2a." Displaying slide 2,
"What We'll Be Discussing," he said today's presentation is a
continuation of the deeper details of the proposed provisions in
HB 247. He said he will start by looking at how the proposed
minimum tax in the bill would affect some of the economics of
current production and then he will look at how the proposed
credit changes would impact the analysis of a new field on the
North Slope and in Cook Inlet.
MR. ALPER turned to slide 3, "North Slope Production Tax
Snapshot With Impact of Minimum Tax Changes." He then turned to
slide 4, "Assumptions," to outline the assumptions used in DOR's
modeling. He said the department's model is called the
Snapshot, a comingled map of all of the oil fields working
together, and therefore it doesn't incorporate the specifics of
any individual producer. He drew attention to DOR's assumptions
shown in yellow from DOR's fall 2015 Revenue Sources Book, which
forecasts for fiscal year (FY) 2017: average per barrel (bbl)
transportation cost - $11.16; state royalty rate - 12.5 percent;
average state corporate income tax (CIT) rate - 6.5 percent
based on apportionment formula applied to the state's statutory
9.4 percent rate; federal CIT rate - 35 percent; total per
barrel of [deductible] upstream capital expenditures ("capex")
and operating expenditures ("opex") - [$31.62]; total FY 2017
production [at 1,000 barrels/day] - $504,900; and state's share
of property tax per barrel produced - $1.25.
MR. ALPER explained that the chart on slide 5, "FY 2017 snapshot
(legacy oil)," is the format used during DOR's presentations for
Senate Bill 21 [passed in 2013, Twenty-Eighth Alaska State
Legislature]. The chart shows the split of producer, state, and
federal share of profit across a range of prices. The versions
of the chart that were before the committee a few years ago
didn't contemplate the lower prices being seen today. At an oil
price of $50 a barrel state take is 98 percent and at $40 the
state take is in excess of 100 percent because the companies are
effectively losing money and because of the impact of the
minimum tax. At $90 total state and federal government take is
60 percent; at $60 total government take is 70 percent; and at
$70 total government take is 62 percent.
1:15:02 PM
REPRESENTATIVE JOSEPHSON, regarding the state taking in excess
of 100 percent at a price of $40, inquired whether the credits
have been subtracted.
MR. ALPER replied no, the calculation here is simply that the
divisible profit is less than $0 because the companies are
losing money on cash flow. So, any state take, in this case the
minimum tax, is more than 100 percent of the divisible profit.
1:15:36 PM
MR. ALPER said the chart on slide 6, "FY 2017 snapshot (legacy
oil) with 5 [percent] min. tax," is the same analysis if the
minimum tax were increased from 4 percent to 5 percent. At a
price of $80 a barrel total state and federal government take is
60 percent; [at $90 government take totals 60 percent and at
$130 government take totals 66 percent]; at $70 total government
take is 64 percent. At a price of $50 a 5 percent minimum state
tax would take 102 percent of divisible profits. So, when in
marginal places where there are no profits to divide, the
increase to the minimum tax has the most impact.
MR. ALPER stated that the chart on slide 7, "FY 2017 snapshot
(new oil)," provides the same analysis on new oil, oil that is
eligible for the Gross Value Reduction (GVR). For new oil,
government takes across the board are quite a bit lower at the
higher prices, ranging from 57-58 percent. At $50 state take is
81 percent as opposed to 98 percent for legacy oil. The main
reason for this difference is that new oil is not required to
pay at the minimum tax level. Producers are able to use their
per taxable barrel credits to reduce payments all the way down
to $0 and therefore they are able to pay at the lower level, so
the total state and federal government take is 88 percent.
MR. ALPER displayed slide 8, "FY 2017 snapshot (new oil) with 5
[percent] min. tax and hard floor," and pointed out that
layering in the changes proposed in HB 247 would result in a
dramatic change at, say, a price of $50 because in addition to
having to pay the higher minimum tax of 5 percent the producers
must pay a minimum tax. Under current law, new oil eligible for
GVR benefits can go to zero, while the proposed changes would
prevent that. Therefore, at the lower prices, the economics on
slide 8 are similar to the economics on slide 6 because the GVR
becomes immaterial due to the imposition of the minimum tax.
1:17:48 PM
Mr. ALPER next discussed the distribution of revenues for North
Slope production with the proposed minimum tax changes [slide
9]. He explained that the two charts on slide 10, "Distribution
of Revenues for Legacy Oil, $40," represent a barrel of oil that
is divided. The charts take the value of a barrel oil and show
what the cost is, what the state's share is, and what the
different tax slices are of the value. At a price of $40 it is
a money-losing proposition and therefore numbers go below the
zero line. [Under current law of Senate Bill 21], at a price of
$40 the producers have an estimated operating loss of $7.39 per
barrel (blue bar) and the total government take is $5.86 (green
bar). If HB 247 was passed as written, the main change at a
price of $40 would be the 5 percent minimum tax, which would add
about $.26 to the state's take and which is $.26 that would come
out of the producers' piece.
MR. ALPER displayed slide 11, "Distribution of Revenues for
Legacy Oil, $60," and continued the aforementioned discussion at
a price of $60. At $60 the industry does see profits, he said,
although relatively small ones compared to historic norms.
[Under current law], at $60 the producer share of the divisible
profit after all costs and all taxes would be $5.72. If HB 247
passed as written, there would be the reduction of $.26 that
brings the producer share of the divisible profit down to $5.46.
Government take would go up by the same $.26 to $13.01. These
numbers line up to that roughly 70 percent government take
calculation seen a few slides ago.
MR. ALPER showed slide 12, "Distribution of Revenues for Legacy
Oil, $80," and continued the aforementioned discussion at an oil
price of $80. He said this is the highest price that DOR looked
at for the purpose of the analysis for this presentation. At
$80 there is no change - the producer share is $15.56 under
current law and would still be $15.56 if HB 247 were passed.
This is because at a price of $80 the minimum tax is not part of
the calculation; there is enough profit and enough value that
the state is actually receiving the full 35 percent tax, less
per taxable barrel credits, and therefore the change to the
minimum tax doesn't have any impact. This would also be the
case at any price above $80 a barrel.
1:20:22 PM
MR. ALPER pointed out that the next three slides are the same as
the previous three, only rather than for legacy oil they are for
new oil, oil that is eligible for the Gross Value Reduction
(GVR). Moving to slide 13, "Distribution of Revenues for New
Oil, $40," he said that [under current law] the producers are
losing $6.39 per barrel. If HB 247 was passed, the producers
would lose $7.65 per barrel, an increase of $1.25, and the
government take would correspondingly increase by $1.25.
MR. ALPER displayed slide 14, "Distribution of Revenues for New
Oil, $60," and noted that the producer share [under current law]
is $6.76; if HB 247 was passed it would be $5.46, which is $1.30
less. [Government take would be raised to $13.01.] The after
effects of HB [247] would make these numbers look identical to
the non-GVR oil, essentially. By throwing in the minimum tax
requirements of legacy oil at the lower prices there is no
benefit to the Gross Value Reduction.
1:21:24 PM
REPRESENTATIVE JOSEPHSON posed a hypothetical scenario in which
the GVR concept was in effect in 1967 when oil was discovered in
Prudhoe Bay. He asked whether under the existing definition of
GVR the Prudhoe Bay oil would still be treated as new oil today.
MR. ALPER replied that the definition of new oil in statute is a
field that was unitized subsequent to 2003. Had a net profits
tax regime with a new oil provision been passed back in the
1960s, yes, if Prudhoe were to fit under that definition then,
there is no mechanism by which oil would graduate and go from
being new oil to being old oil. Once something qualifies for
new oil, the way Alaska statutes are currently written it
remains new oil indefinitely.
1:22:16 PM
MR. ALPER addressed slide 15, "Distribution of Revenues for New
Oil, $80." He reminded members that for legacy oil at a price
of $80 there would be no impact from the changes contemplated by
HB 247. However, he continued, for new oil there would be an
increase of $.97 because of the GVR benefits. The cross over
point, the place where a producer would switch over from paying
at the minimum tax rate to paying at the full tax rate is
actually a few dollars higher.
MR. ALPER next discussed DOR's field life cycle modeling for the
North Slope [slide 16]. Turning to slide 17, "North Slope Life
Cycle Modeling Assumptions," he explained that DOR modeled two
field sizes on the North Slope, a small field of 50 million
barrels of oil (MMbo) and a large field of 750 MMbo. The small
field is analogous to some of the smaller fields that have come
into production in the last few years as well as some that are
under development, or under active exploration or delineation
right now. The 750 million barrel field is a much larger type
of field, something along the lines of the Alpine Field [also
known as Colville River Unit]. Although it doesn't directly
model the expectations of, say, the large Armstrong/Repsol
development [Pikka Unit], it could in some ways be seen as a
proxy for that.
1:24:03 PM
REPRESENTATIVE SEATON asked whether a 50 MMbo field is analogous
to 15,000 barrels a day at peak production in the life cycle.
MR. ALPER responded yes, about 15,000 barrels a day.
1:24:22 PM
MR. ALPER continued his discussion of the assumptions outlined
on slide 17, noting that in modeling the two field sizes, two
types of producers were modeled - those producers eligible for
cash refunds and that under HB 247 would be imposed a $25
million limit per company per year, and those new producers with
worldwide revenue greater than $10 million that under HB 247
would not be eligible to receive any credit in cash and would
have to roll it all forward until production occurs. The prices
modeled were for $40, $60, and $80 held static, uninflated,
through the life of the field as well as the fall 2015 forecast
price, which is in the $50s now and moving up gradually into the
$70s for the bulk of the study time. The fall 2015 forecast
numbers will often split the difference of the $60 and $80 as
far as the net result. The two tax systems modeled were the
status quo system with new fields qualifying for the 20 percent
GVR that would be in place throughout the life cycle of the
field, and the system that would be put in place under HB 247.
He said DOR is willing to do custom modeling per the committee's
request. Today's modeling includes all the changes proposed in
HB 247: an increase and hardening of the minimum tax; limit on
the credits/refunds by the dollar amount, worldwide revenues,
and the 10-year expiration of Net Operating Loss Credits; and
that the GVR cannot be used to increase the size of the net
operating loss (NOL).
MR. ALPER displayed slide 18, "North Slope Life Cycle Modeling
Assumptions, 50 mmbo field assumptions," and outlined the
assumptions for this size field: field life cycle - 30 years;
peak oil production - 15,000 barrels per day; transportation
cost - $10 per barrel from wellhead to Pump Station 1 to the
pipeline to marine transport; royalty rate - 12.5 percent;
capital expenditure - $18 per barrel, generally frontloaded in
the beginning of a project; operating expenditure - $15 per
barrel, which is more back loaded, running alongside the
production itself; property tax - $1.25 per barrel; [state
corporate income tax (SCIT) rate - 6.5 percent of production tax
value (PTV) after production tax; and federal corporate income
tax rate - 35 percent of PTV after SCIT]. He noted that the
production, and state and federal corporate income tax rates
line up with the existing rates.
1:26:51 PM
MR. ALPER moved to slide 19, "North Slope Life Cycle Modeling,
50 mmbo Status Quo, $40/bbl," the first of four modeling slides
for a 50 MMbo field under the status quo tax system. He said
the series of three graphs on this slide will be seen on all of
the slides related to life cycle modeling. The upper left graph
is the state's cash flow from the production tax program itself.
Any numbers below the line (red bars) are paying out credits, so
are negative revenues. Any numbers above the line (blue bars)
are positive payments under the production tax. At a price of
$40 there is not much positive payment. The upper right graph
is total state take, which is in many ways more important, and
includes the royalty, the corporate income tax, [property tax,
and production tax], with the production tax depicted in green.
The lower left graph is the producer's cash flows. It
represents the producer's spending money and getting some
fraction of it back in credits. The lower right chart is an
aggregate and summary of the data to come up with discounted
numbers. He said DOR chose to use a net present value (NPV)
discount rate of 6.15 percent. Elaborating, he said this type
of analysis originated last year with some specific requests
made to the Tax Division by Representative Seaton. The division
did the modeling at that time based on what was then the
Permanent Fund Corporation's expected 10-year return, so "we
were saying the state's loss of money." The permanent fund
subsequently revised that number upward to 6.9 percent, but the
model still uses the 6.15 percent. The modeling uses the same
number for the producers as for the state. The hurdle rates
used by the companies tend to be a little bit higher, he
allowed, companies want to make a higher rate of return on their
money than 6 percent. But, he explained, in the interest of
equity and symmetry the same discounted cash flow was used for
the investor as for the state.
1:29:34 PM
REPRESENTATIVE JOSEPHSON, regarding the modeling on slide 19,
surmised that Company X was successful in finding a 15,000
barrel a day field and would do so for 30 years. Noting that a
lot of companies haven't found anything yet, he surmised that
these slides are portraying a success story.
MR. ALPER answered yes, the company has found a field and now is
starting to develop it. What is seen in the graph in the lower
left corner is all the spending that ramps up as the company
starts building the oil field and bringing it into production.
1:30:31 PM
MR. ALPER returned to his discussion of slide 19 and noted that
no matter how big or small the field and no matter the tax
structure of status quo or under HB 247, no field makes any
money at a price of $40 a barrel. By the time positive cash
flow is reached for a field of 15,000 barrels a day at a price
of $40 the state will have cashed out $221 million in production
tax credits. Very little tax will ever actually be paid because
of the continued low prices. Referring to the bottom right
chart, he reported that the effective discounted loss to the
state through the production tax system is negative $153
million. Things are better for the state when the royalty and
other state revenues are included, but still the state's overall
cash flow loss is $24 million. When the time value of money is
included (the discounted cost) the state loses $58 million and
the producers themselves will have spent $365 million and gained
$384 million, so the producers are barely cash flow positive.
However, because of the time value of money, the producers show
a substantial loss of $99 million.
1:31:51 PM
REPRESENTATIVE OLSON inquired whether any credits are available
after 50,000 barrels a day.
MR. ALPER replied yes, but pointed out that the peak for this
model is 15,000 barrels a day. If a producer drills and
produces more than 50,000 barrels a day, the producer gets its
credits but cannot turn them into cash - the credits must be
rolled forward and used against the producer's tax liability.
REPRESENTATIVE OLSON remarked that the producer can get the
credits but cannot use them.
MR. ALPER responded not exactly and explained that the producer
can use the credits to reduce its production tax payments. So
long as the price is high enough to support a tax payment, a
producer could offset that all the way down to $0 or the minimum
tax depending on the credit. A producer can use the credits to
reduce its tax payments, but cannot use them to get cashed out
by the state. Responding further to Representative Olson, Mr.
Alper said he will address the cap of 50,000 barrels a day when
he gets to the analysis for large fields. Even if a new company
builds a giant field, that new company would put itself in that
50,000 category under the status quo analysis pretty quickly.
1:33:14 PM
REPRESENTATIVE SEATON asked whether the basic presumption for
including the production tax net present value (NPV) of 6.15
percent in the analysis is so a look doesn't need to be taken at
alternative investment of that money. In other words, he
surmised, the state is paying out cash and if that cash had been
left in the permanent fund the state would have expected a 6.15
percent 10-year average of return.
MR. ALPER answered yes, exactly right. The state does have time
value to its money. Traditionally and historically the state
has not really contemplated that because it sort of operates the
government on a cash basis. But now suddenly the state is using
savings and there is opportunity cost to using those savings. A
similar conversation was had in this committee during the
interest rate conversation. The provisions of the bill that
would change the interest rates are also designed to compensate
the state for the money it would have earned had that money
stayed in savings. The companies themselves use the term
"hurdle rate," which relates to their opportunity for investment
options around the world and the companies will invest money
with the expectation of earning a cash flow profit on it as well
as a discounted rate of return on that profit. The 6.15 percent
is used here with the understanding that quite likely the
typical company operating in Alaska is going to expect a larger
number than 6.15 percent, which would reduce those discounted
value numbers. "The higher the interest rate that you're
charging yourself on your future money," he explained, "the less
money a dollar in the future is worth today."
1:35:24 PM
MR. ALPER resumed his presentation and addressed slide 20,
"North Slope Life Cycle Modeling, 50 mmbo Status Quo, $60 bbl."
Referring to the upper left graph, he noted that much more
[positive cash flow] (blue bars) is seen at a price of $60. At
a price of $60 the companies will be paying production tax by
the fifth or sixth year when they get towards peak production.
That production tax adds up to $183 million against the $162
million that the state pays out in credits. However, while
there is a bit of positive production tax, applying the discount
rate results in a production tax net present value to the state
of negative $37 million. Regarding total state take (upper
right graph), he noted that green represents the production tax,
blue is royalty, purple is state corporate income tax, and red
is state property tax. The state receives $380 million in
positive cash flow out of this field at a price of $60 in the
status quo, with a net present value of about $136 million.
Referring to the lower left graph, he explained that the cash
flow for the producer is negative (red bars) while the field is
under construction, but after construction the cash flow turns
to profits after taxes (green bars). The producer receives
about $400 million in positive cash flow and a discounted value
of $112 million.
1:36:49 PM
REPRESENTATIVE SEATON inquired whether the production tax net
present value of negative $37 million can be translated to mean
that the state is advancing credits early in a project and over
the life of the project the state is not going to recover that
money by approximately $37 million.
MR. ALPER provided a reply by assuming two scenarios - one the
status quo and the other a field that never happened and so the
money remained in the permanent fund for the duration. Had that
money stayed in the permanent fund earning a 6.15 percent return
over the multiple years, the state would have had $37 million
more at the end of the day than if the state had paid it out in
tax credits and received it in production tax with that field
invested. He pointed out that this is purely on the production
tax and does not include the other state revenue.
1:38:11 PM
REPRESENTATIVE JOSEPHSON noted that in the aforementioned
example the money was kept in the permanent fund, but posited it
would be more likely that the money would not be kept in the
permanent fund. In this case there would then be assorted
arguments about what the state did do with the money and who
benefitted from it.
MR. ALPER responded that that is why the state hasn't
historically discounted its cash flows - the state has more or
less operated on a cash basis. More likely in the recent past
and an era of short-term or expected short-term deficits, the
money would be in the Constitutional Budget Reserve (CBR), not
the permanent fund. The CBR itself now has the great bulk of
its money in very liquid cash-type investments that earn less
than that. Until about a year ago the bulk of the CBR was in
the "sub-account," which was invested diversely out in the
financial markets and earned a comparable rate of return to the
permanent fund itself. The limitations on the CBR's sub-account
were that there needed to be five years' worth of money. Once
prices fell as catastrophically as they did as quickly as they
did, almost immediately the state no longer had five years'
worth of money in the CBR and the decision was made last spring
to liquidate CBR's securities portfolio and turn it into cash.
1:39:56 PM
MR. ALPER continued his presentation, moving to slide 21, "North
Slope Life Cycle Modeling, 50 mmbo Status Quo, $80/bbl." He
explained that at higher prices more taxes and more royalties
are seen. At an oil price of $80 there is a positive production
tax value to the state of $110 million in discounted cash flow,
and $364 million in total cash flow. To the owner and producer
of the field, a price of $80 over the life cycle of the project
creates $287 million in value.
MR. ALPER brought attention to slide 22, "North Slope Life Cycle
Modeling, 50 mmbo Status Quo, Fall 2015 FC Prices." He said the
fall 2015 forecast price is somewhere in between $60 and $80.
In this scenario the state's production tax net present value is
a positive $40 million and total state take is $255 million in
value. The producer is at $203 million in net present value.
1:40:57 PM
MR. ALPER explained that slides 23-26 look at the same four
price scenarios under the changes proposed by HB 247. He
compared slide 23, "North Slope Life Cycle Modeling, 50 mmbo HB
247, $40 / bbl," to the status quo on slide 19, and noted that
the state's cash flow in the status quo is a payout of $50-$60
million a year in credits during the peak construction years.
Under HB 247, however, the credits paid out by the state would
never be more than $25 million a year due to the proposed cap of
$25 million per company per year. Larger numbers would also be
seen a couple of years in the future because the company would
be rolling its tax credits forward and getting them against its
taxes in the years after the company is under production. For
example, in the sixth or seventh year the state's cash flow
would be nearly negative $20 million because the company would
have about $7-8 million in tax liability that would be offset by
the $25 million of carried forward credit and then the company
would get the remaining $18 million in actual credits. Under
the status quo at a price of $40 (slide 19) the state is out-of-
pocket $221 million, while under the proposed changes of HB 247
the state would be out-of-pocket $150 million. Under the status
quo the state's net present value is negative $153 million,
while under the proposed changes of HB 247 it would be negative
$95 million. Under the status quo the producer's net present
value is negative $99 million, while under the bill's proposed
changes it would be negative $155 million.
1:42:50 PM
MR. ALPER compared slide 24, "North Slope Life Cycle Modeling,
80 mmbo HB 247, $60 / bbl," to the status quo on slide 20. He
pointed out that a price of $60 a barrel is something like a
break-even model for the state. The state's net present value
under the status quo is negative $37 million, while under the
proposed changes of HB 247 it would be negative $10 million.
Under the status quo a producer's net present value would be a
profit of $112 million, while under the proposed changes of HB
247 it would be $93 million, an erosion of less than 20 percent
to the producer and an improvement to the state's cash flow of
about $60 million over the life of the project. Under the
status quo the state's net cash flow gain is $380 million and
net present value [is $136 million], while under the proposed
changes of HB 247 the state's net cash flow gain would be $412
million and net present value [would be $163 million]. So, at a
price of $60 there would be a small impact on the project itself
but not an impact that DOR considers catastrophic.
1:44:19 PM
REPRESENTATIVE SEATON understood that the red bars in the upper
left graph on slide 24 represent the investment by the state, or
money out from the state. He further understood that the lower
left graph on slide 24 shows the negative for a producer but
that there are two or three years of net gain for a producer
while the state is still seeing a net outflow.
MR. ALPER answered that it is actually two years because there
is actually a zero bar all the way on the left of all these
scenarios for the state because no one starts claiming credits
until after the first year of work. In the upper left chart for
the state there are six red/negative bars but the last negative
bar is actually year seven; however, by years six and seven a
producer is in a positive place. So there are two years where a
producer is having positive cash flow while the state is still
repaying credits. Referring to the upper right chart, Mr. Alper
noted that the state's positive cash flow under the provisions
of HB 247 would start in year six because once a producer is in
production the state starts receiving a royalty. In year five
the state would receive about $13 million in primarily royalty
revenue and would pay out $20 million in continuing tax credits,
so the state would be negative $7 million. In year six the
state would receive about $28 million in revenue (blue bar) and
would pay out about $15 million [green bar], so the state would
now start being in a positive cash flow.
1:46:26 PM
REPRESENTATIVE JOSEPHSON requested clarification on which of the
graphs on slide 24 were being compared.
MR. ALPER replied that Representative Seaton's original question
was comparing the state's cash flow [upper left graph] with the
producer's cash flow [lower left graph]. Representative Seaton
was making the observation that the producer gets into a
positive cash flow while the state is still paying out credits.
Mr. Alper agreed that that is true for one or two years.
1:47:06 PM
MR. ALPER resumed his presentation. He stated that slide 25,
"North Slope Life Cycle Modeling, 50 mmbo HB 247, $80 / bbl," is
the "after" comparison to the status quo or "before" depicted on
slide 21 for an oil price of $80 a barrel. Referring to the
upper left graph he said the credits that would be paid out by
the state would be restricted by [the proposed $25 million cap].
Mr. Alper pointed out that the scale on the three graphs keeps
changing throughout the different slides. When there is more
money the scale needs to be extended because if the scale were
to be kept constant the numbers would be nearly invisible for a
large portion of it. The state's positives from the production
tax at $80 oil reach as much as almost $60 million a year. The
state's total take at the peak of that is close to $100 million
a year. A discounted total state take cash flow of about $380
million is seen with the changes envisioned in the bill. The
comparable number [for the status quo at $80 on slide 21] was
$364 million. The state would gain about $16 million in value
over the life cycle of the project, while the producers would go
from $289 million to $277 million, a loss of $12 million. As
prices get higher the changes envisioned in HB 247 become much
less material. Most provisions of the bill are protecting the
state's interest at low price. Although the impact is higher at
a price of $60, the impact is less at $80.
MR. ALPER displayed slide 26, "North Slope Life Cycle Modeling,
50 mmbo HB 247, Fall 2015 FC Prices," stating that the fall 2015
forecast price is somewhere in between. In this scenario the
state would have a positive production tax net present value of
$60 million, while under the status quo it is $40 million.
[Under the proposed changes in HB 247] the state's net present
value would be $274 million, while under the status quo it is
$255 million. Under HB 247 the producer's cash net present
value would be $189 million, while under the status quo it is
$203 million. So, about $14 million of the producer's value
would be taken by the changes envisioned in HB 247.
1:49:38 PM
REPRESENTATIVE SEATON asked about the fall 2015 forecast price.
MR. ALPER responded that the price for the current fiscal year
is $50 and the FY 2017 price is $56. He deferred to Mr. Dan
Stickel to provide further details.
DAN STICKEL, Assistant Chief Economist, Tax Division, Department
of Revenue (DOR), answered that the fall forecast has a few
years of price increases and prices end up leveling out in the
$70 real range. For instance, looking out through 2024 the
price is $84.53 in nominal terms, which is $70-$71 real range.
MR. ALPER added that DOR is using uninflated numbers throughout
the life cycle here. So, when $60 is seen or $50 million is
seen, those are current-year dollars; DOR did not build in any
sort of inflation. The department has a forecasted oil price
that is going up slightly. The last year of DOR's forecast is
in 2025 and that 2025 number is then held flat for the rest of
the life cycle of these fields - in that $70-ish range. That is
why these forecast numbers come out splitting the difference
nicely between the $60 and $80 because for the bulk of the time
period it is a $70 forecast.
1:51:13 PM
MR. ALPER next discussed the large field model. He turned to
slide 27, "North Slope Life Cycle Modeling Assumptions, 750 mmbo
field assumptions," the first of four modeling slides for a 750
MMbo field under the status quo tax system. He said the
assumption for the life of a field this size is 40 years and the
assumption for peak oil production is 120,000 barrels a day.
The capital cost is assumed to be $13 a barrel, which is less
than the cost of $18 for a smaller field due to economies of
scale from drilling pads and processing facilities. However,
$13 multiplied by 750 million barrels is close to $10 billion;
$10 billion is what it would cost the producer that develops and
builds such a field. The department must contemplate what that
means in its tax credit modeling when someone comes up and
spends $10 billion on the North Slope.
1:52:18 PM
REPRESENTATIVE JOSEPHSON understood that a 750 MMbo field is
comparable in size to Alpine, Alaska's third largest field. He
inquired whether Alpine received credits when it was started.
MR. ALPER answered that Alpine began operating in 2004 and peak
production was 124,000 barrels a day in 2007. Alpine went into
production under the Economic Limit Factor (ELF) system, a gross
production tax, and therefore there were not credits associated
with that field's buildout or construction. Unitization of that
field was prior to 2003 so it does not enjoy the Gross Value
Reduction (GVR). For all intents and purposes Alpine is legacy
oil. When the switch was made in 2006 to the production profits
tax (PPT) [Twenty-Fourth Alaska State Legislature, House Bill
488], people talked about the weighted average of the tax rates
among the different fields that were in production on the North
Slope and attention was brought to the fact that many of the
smaller fields were below a 1 percent effective tax rate. The
Kuparuk River Unit had fallen to a very low tax rate. All of
the taxes were coming, really, from Prudhoe Bay and Alpine;
Prudhoe Bay because it was so large and its wells still very
productive and Alpine simply because it was so new it was in its
peak productivity per well and there was a relatively high
multiplier that was paying a 10 percent or higher gross tax rate
in 2006 when the switchover was made from ELF to PPT.
1:54:16 PM
MR. ALPER returned to his presentation. He brought attention to
slide 28, "North Slope Life Cycle Modeling, 750 mmbo Status Quo,
$40/bbl," the first of four modeling slides for a 750 MMbo field
under the status quo tax system. He noted that the numbers are
bigger for this field size and correspondingly the scales on
each of the slide's three graphs are bigger. In this scenario,
the state's share through the tax credit program is just less
than $3 billion; that is what the state would be paying out in
cash to get this field up and running. Given the low price, the
value the state gets from that is relatively small, so the
discounted loss [the production tax net present value] to the
state is about negative $2 billion. When royalty and corporate
tax are included, the state ends up with just over $3 billion in
total revenues over the life of the project against a negative
$2.8 billion in cash flow. Thus, the total gain is $367
million, but the discounted value of the state's gain is
negative $1.016 billion. The producer is also losing a large
amount of money under the status quo, with a [producer cash net
present value] of negative $1.768 billion. Continuing with the
thesis that was begun earlier, no one is going to make any large
investments in Alaska going forward if it is thought that the
price of oil is going to stay at $40 indefinitely.
1:56:05 PM
REPRESENTATIVE JOSEPHSON asked whether slide 28 is depicting GVR
oil or legacy oil.
MR. ALPER replied that DOR's assumption for the modeling of any
new fields on the North Slope is that they will be eligible for
the GVR. So, there are two primary assumptions for this new
oil. First, should a field be profitable, the production tax is
going to be reduced by the multiplier that takes a fraction of
the gross and subtracts it from the production tax value; so,
this new oil will enjoy a lower tax rate. Second, at lower
prices this oil would receive the $5 Per-Barrel Credit rather
than the sliding-scale Per-Barrel Credit. The $5 Per-Barrel
Credit can reduce the producer's production tax liability to $0
because there is no minimum tax in a GVR field.
1:57:09 PM
MR. ALPER continued his presentation, moving to slide 29, "North
Slope Life Cycle Modeling, 750 mmbo Status Quo, $60/bbl." He
noted that at a price of $60 under the status quo the credits
are still very large during the early years of construction,
approaching $2.9 billion. In about 10 years the state starts
seeing positive production tax cash flow; prior to that the Per-
Barrel Credit is enough to wipe the tax down to $0. Referring
to the upper left graph, he drew attention to the years where it
appears that nothing is happening and explained that in the
early years of production from this field there is some
production tax liability, but it is wiped out to $0 by the Per-
Barrel Credit, which is why a gap of nothing is seen. The state
does start getting royalties as soon as production begins and
the state gets positive cash flow in about year eight, but by
the time the state gets to that place it is negative cash flow
somewhere between $2.5 and $3 billion. The producer, meanwhile,
at the 6.15 percent discount rate, is in a mildly profitable
circumstance of $312 million. The producer has a lot of cash
flow at $7.4 billion, but because of how frontloaded a project
like this is it is quite likely that a decision would not be
made to invest in a large, expensive project like this if the
expected oil price was in the $60 range. He offered his
presumption that producers would not make this kind of
investment unless they expected the price of oil to be higher
than $60 for the next 40 years.
1:58:43 PM
MR. ALPER addressed slide 30, "North Slope Life Cycle Modeling,
750 mmbo Status Quo, $80/bbl." He said the upfront cost to the
state at this price under the status quo is still in the range
of $2.8 billion being spent in credits. The difference is that
the state gets to positive cash flow a bit quicker and gets to
really good cash flow somewhere down the line. In the eighth to
tenth year of production, during the peak years where those
120,000 barrels a day are flowing, the state is going to get $1
billion a year in revenue. He recalled testimony by Mr. Bill
Armstrong [President, Armstrong Oil & Gas Inc.] that the state
will get $1 billion a year in revenue. However, Mr. Alper
pointed out, that $1 billion comes on the heels of several years
where the state is paying multiple hundreds of millions of
dollars per year during the construction and development phase
of the project. The producer's cash flow in this scenario is
much more robust - a discounted cash flow of $2.2 billion and a
discounted cash flow to the state of $3.5 billion. So, this
scenario is great except for the part about the state not having
the money to pay for the upfront costs, leading to the
conversation about what to do about that.
MR. ALPER brought attention to slide 31, "North Slope Life Cycle
Modeling, 750 mmbo Status Quo, Fall 2015 FC Prices," and said
this scenario falls somewhere between and is the forecasted FY
fall 2015 Revenue Sources Book prices. In this case the state
has about $2.5 billion in value and the producer about $1.4
billion. Once again, however, there are very large credits in
the early years of the development phase, peaking out at just
over $800 million of state cash liability to that producer in
about the fifth year of the project, which is peak construction.
2:00:38 PM
MR. ALPER discussed slide 32, "North Slope Life Cycle Modeling,
750 mmbo HB247, $40 / bbl," the first of four modeling slides
for a 750 MMbo field under the changes proposed by HB 247. He
said this is a very dramatic change, with two things happening.
One is the state is only paying out $25 million a year.
Comparing slide 32 with slide 28, he noted that under the status
quo for this same scenario the production tax credits cashed was
just less than $3 billion. However, under HB 247, the state
would only spend $134 million, a tremendous decrease in the
state's credit liability. The reason for this decrease is the
proposed cap of $25 million per company per year. Under HB 247
the state would have something of a positive because the
producer would be paying an actual minimum tax at the rate of 5
percent during the life cycle of the project. The producer's
cash flow at $40 is worse under the proposed changes of HB 247
[negative $3.744 billion] than under the status quo [$1.768
billion]. Therefore, Mr. Alper said, he would rather have this
conversation around the oil prices of $60 and $80 where such a
project would be more likely to happen than at a price of $40
where the math is almost ludicrous - it is technically correct
but such a project isn't going to happen.
2:02:02 PM
REPRESENTATIVE JOSEPHSON noted he is undecided on HB 247 and
said he thinks he just heard Mr. Alper, in effect, make the oil
industry's argument. He further asked whether the life cycle is
30 years or 40 years.
MR. ALPER responded it is a 40-year life cycle. He said he is
uncomfortable with the scenario of a price of $40 because it is
so implausible for all of this to happen at a price of $40.
About $2 billion in value is shifted from the producer to the
state in this modeling over the 40 years. The all-in present
value to the state under the status quo on slide 28 is negative
$1 billion, while under the proposed changes of HB 247 on slide
32 it is about positive $1 billion, which is the $2 billion
shift. He urged that this conversation be had at a more
reasonable oil price and therefore turned to a price of $60.
2:03:10 PM
MR. ALPER drew attention to slide 33, "North Slope Life Cycle
Modeling, 750 mmbo HB247, $60 / bbl," and said that under the
proposed changes of HB 247 the state's credit liability would be
capped at $25 million for the producer. He pointed out that a
project like this is unlikely to have only one partner and the
way the bill is written the cap would be $25 million per company
per year. So, if there were four companies involved in such a
project, the allowable amount of credits would be quadrupled and
that would dramatically change a lot of these numbers. But the
modeling had to start somewhere and so DOR started with the bill
and the modeling as DOR literally interprets it. He said DOR
would be happy to look at split fields to come up with different
scenarios if the committee wishes. Continuing, Mr. Alper noted
that the state's cash flow in the before/status quo scenario
depicted on slide 29 was close to $3 billion out the door. Part
of the reason the administration is before the committee is that
the state does not have $3 billion, the state does not have the
ability to participate in a new oil field development with $3
billion in cash. So, the administration is looking at
mechanisms to limit that and the changes proposed in HB 247
would greatly limit that amount of cashed credits to only $116
million in a one partner, $25 million modeling.
2:04:46 PM
REPRESENTATIVE JOSEPHSON understood Mr. Alper to be saying that
when looking at a large, new, Alpine-sized development, the
unaffordability of these credits becomes extremely magnified and
under existing statutes creates some real risks of insolvency
because the state does not have $3 billion.
MR. ALPER answered he would say that the State of Alaska's
credit regime was designed to try to get new players on the
North Slope, generally presumed to be smaller. But, if someone
finds something that is big, the law is silent on the size of
the field. He recalled that a year ago he and Mr. Stickel sat
before the committee and discussed theoretical long-term cash
flows for the Arctic National Wildlife Refuge (ANWR). The chair
had asked DOR to look at what would happen if the refuge was
developed and 20 different fields were layered on and there was
a great river of money and a great river of oil in the later
years. However, DOR saw billions of dollars in negative credit
cash flow in the early years of it because people would be
spending $5-$6 billion a year to get the refuge developed. If
it were to fall into the literal interpretation of the state's
current law, it would be unaffordable for the state in the short
term and the state would have to find a way to afford that.
That is part of why the administration is before the committee
now - to recognize that these projects are very much wanted to
happen, but as the law is currently written the state does not
have the money to afford the obligations that it has taken on
for these larger projects.
2:06:39 PM
REPRESENTATIVE OLSON posed a scenario in which Mr. Alper owns an
oil company and is thinking about doing business in Alaska under
the terms proposed in HB 247. He asked where Mr. Alper would
seriously start thinking about price.
MR. ALPER replied he does not have an oil company and so it is
hard to imagine. He related that he found Mr. Armstrong
refreshing in a lot of ways when he was before the committee,
but Mr. Armstrong is bullish and thinks the price of oil is
going to be high and is prepared to make very large investments
and borrow a lot of money. However, Mr. Alper continued, some
of his anxiety is that the state cannot be as bullish as is Mr.
Armstrong, the state has obligations to its citizens that it
cannot be on the hook for a 35 percent partner based upon Mr.
Armstrong's optimism. If he were a very wealthy person and
investing in oil projects in Alaska, he would probably want to
know that prices are going to be in the range of $80 or better.
REPRESENTATIVE OLSON remarked that $80 is the range he was
thinking of as well.
2:07:55 PM
REPRESENTATIVE HERRON commented that changes to HB 247 probably
have to be sensitive to $40, $50, and $60 over 40 years, not the
reverse. In a nutshell, the biggest reserve in the world, the
Saudi's, does not want to become irrelevant. Therefore, it is
important to concentrate on tweaks to HB 247 that are down in
the price ranges of $40 and $50. As was just said by Mr. Alper,
the state cannot afford to play with the big boys; a far more
conservative approach to this must be taken.
REPRESENTATIVE SEATON understood Mr. Alper's point to be that
regardless of whether the price is $40, $60, or $80, under
current law the state does not have the money to invest in this
size field because that investment would be $3 billion over the
next seven years. He inquired whether Mr. Alper's message is
that even if the expected price is $80, the state does not have
the $3 billion to put into the field as cash credits to go
forward with the project under the current statute.
MR. ALPER responded yes, and he would go further to say that at
a price of $80, although the fields might pencil out better, it
is not like the state's budget woes are solved. The budget
presented by the governor this year balances at an oil price of
about $103. The administration is expecting additional cuts and
revenue measures and the like, and if something structural is
done with how the state treats its savings that number will be
able to be dropped dramatically. The state is far away from
seeing the kind of surpluses that will enable the state to
afford these multi-hundred million dollar per year investments
in a single new project.
2:10:32 PM
REPRESENTATIVE TARR observed that slide 32 includes the cap of
$25 million on the production tax credits cashed, while on slide
28 the credits cashed reach almost $600 million in the third or
fourth year and then go above $800 million. Given that the gap
between these two examples is so great, she asked whether
anything in between was looked at during the drafting of HB 247.
She also asked how $25 million was selected as the right limit.
MR. ALPER answered that the modeling done earlier by DOR was
based on smaller fields. As seen in this presentation, the
impact was far less dramatic when the credits in play were a lot
smaller, the $25 million limit. The department didn't model the
very large fields until embarking on this project right here.
The number of $25 million comes from historic statute. When the
state first got into the business of paying cash for credits in
2006 with the passage of the PPT bill, there was a specific $25
million per company per year cap on repurchases. It was not
initially intended to be an open-ended benefit. Credits in most
places in the world are not cashable, credits in places that
offer them are generally used against taxes. Other Alaska
statutes offer credits that can be used against taxes, the
Education Tax Credit being an example. Alaska's credits for oil
and gas development are unique that way. The state is paying
cash into the industry, the state is becoming indirectly an
investor. So, $25 million was an historic number and was chosen
for HB 247 because it had legislative history. One could easily
say that that could be inflation-proofed. However, that number
was only a limit for real for 15 months - between the effective
date of PPT and the effective date of Alaska's Clear and
Equitable Share (ACES) [House Bill 2001, passed in 2007, Twenty-
Fifth Alaska State Legislature], which eliminated the cap.
2:13:06 PM
REPRESENTATIVE OLSON recalled that Mr. Alper was around during
consideration of the PPT.
MR. ALPER replied yes, at that time he was working for
Representative Eric Croft.
REPRESENTATIVE OLSON recalled that a round table was held toward
the end of PPT hearings, to which the three major producers and
a number of the explorers were invited and asked questions. He
recounted that the companies were asked how far forward do they
look for the development of assets and reserves that they
already have. Only one company answered the question and that
company's answer was in excess of 60 years. He asked how the
state can compete with that.
MR. ALPER responded he does not know the state would compete
with that; the state is not really competing with that. The
state has a co-dependent, or a co-mingled, relationship with
industry. The state is a sovereign, it owns things, it runs a
state, it has a school system and they are an oil company that
is trying to plan its strategy to develop a field and then the
next field with the cash flow from the first one. The two are
very different business models. It is easier to be a passive
sovereign, it is easier to let them come to Alaska and let them
do their investments and then pay the taxes when they produce
something. A conscious choice was made 10 years ago for the
state to participate with cash. That changed everything. It
has caused a lot of positives for the state, especially in the
years where prices were high and the state had tremendous
surpluses and was able to save large amounts of money. Today
the state is experiencing the flip side of that, with tremendous
negatives and liabilities to the state being seen. In some ways
they are the mirror image of each other. On the other hand, if
these kinds of lower prices are being expected for years into
the future, the state needs to contemplate how to react to it.
REPRESENTATIVE OLSON remarked that industry has one advantage
that the state does not and that is time. Industry can wait
until it feels it has a chance to make a profit, which is not a
dirty word because industry is not nonprofits. If the state has
to do something now it can only do it a few years out and that
gives industry a distinct advantage in how things are done and
he is thinking the state is seeing that again right now.
2:15:45 PM
REPRESENTATIVE SEATON, regarding the proposed $25 million cap
per company, inquired whether there are any sideboards on the
percentage of ownership. He posed a scenario in which a company
has six 1 percent partners and inquired whether each partner as
well as the main company would get the $25 million cap under the
current language of HB 274.
MR. ALPER said the easy answer is yes, with the caveat that it
is not tied to the project. It is tied to the company's entire
North Slope operations; every taxpayer can get up to $25
million. Things have been done in both statute and regulation.
For example, the Small Producer Credit has a per-company fixed
dollar cap. Because of conversations like this the final
version of the language was written so that a company cannot
artificially split itself in two to try to double dip on the
Small Producer Credit. [The department] would try to provide
some sort of protections whereas a legitimate number of
companies if they were truly partners would be able to benefit
from something, but there wouldn't be any intentional workaround
to try to increase a company's ability to claim credits.
2:17:17 PM
REPRESENTATIVE SEATON said he has some concern if what is trying
to be done in HB 247 is to lower the state's liability so it is
not hundreds of millions of dollars per year for seven years as
this model of a larger field goes. He posited that without
sideboards in statute the state's exposure to paying large
upfront cash credits into a project would not be limited. He
requested that consideration be given to that limitation in
order to make it a real limitation and not something that could
be gone around and that this be brought back to the committee.
MR. ALPER replied two things happen. He posed a scenario in
which there are four partners and they are getting $100 million
a year. Not only does it change the cash flow model and the
state is out four times as much money, but also seen especially
at lower prices is the sunset of the credits themselves after 10
years. What was seen in the low price, large field modeling was
expiring credits where people were not actually able to enjoy
the full benefit of their credits because after five years they
were literally falling off the table. If that was bumped to a
larger number with multiple partners, both of those problems
would go away for the producers. On the other hand, the state
would be paying four times as much money per year in the
upfront.
2:19:09 PM
REPRESENTATIVE SEATON noted that this is being talked about and
thought about as a project, but the credit limitation is per
company. He asked whether there is anything that keeps
additional companies from coming into the project later and
having that same $25 million and therefore extending the credits
out for longer than 10 years.
MR. ALPER responded he hadn't contemplated a technical name
change, but the credit itself is a certificate. The company
earns the credit in year one. If, for example, a company earned
$500 million but is only able to use $25 million a year of it,
if the company doesn't ever have any tax liability after 10
years the company is going to lose a certain portion of it.
Even if the tax credit certificate is transferred or sold or a
company changes name, the certificate is what would be expired.
Typically after a few years the expectation is that there is
going to be tax liability and the company will be using the bulk
of that certificate not to get $25 million a year but to offset
a tax bill. If the prices are high enough the tax bill is
enough to use it up more quickly. When talking about bringing
new partners into a project it is important to remember that the
current refund language in this proposed new $25 million cap is
in Alaska Statute (AS) 43.55.028, which is about the tax credit
fund. It is about the spending of money to purchase
certificates and not anywhere in the language that talks about
how a company earns a certificate. It is very much tied to the
taxpayer, it is tied to per company of limit and that is why the
legislature's consultant, Mr. Janak Mayer, testified that it
would be likely that companies might get nothing. Mr. Mayer was
building a scenario that said the developer of a new field might
already be doing something in Alaska and therefore already
getting its full $25 million from another project and
contemplating the possibility that even in the smaller fields a
company might not get cash. The department did not model the
smaller fields with that set of assumptions, the smaller fields
were modeled with the assumption that a company would enjoy the
full $25 million.
2:21:19 PM
REPRESENTATIVE JOSEPHSON presumed that when Mr. Alper stated
Alaska has great benefits from its credit systems that he meant
Alaska is either optimistic that more production will come on
line or that the industry's argument is correct that it has
stemmed the decline, particularly over the last three years;
that the decline curve would be worse had it not been for these
credits. He said he is playing a mystery game where he doesn't
know what the world would look like without the credits.
MR. ALPER answered, "Neither do we, we can't know what would
have happened." He explained that when he said the state has
benefitted, he primarily meant the state benefitted from the net
profits tax regime that brought in very high rates and very high
revenues at high prices. The credits in many ways were a built-
in offset to that, the flip side of it. When ELF replaced PPT
there was a crossover. At low prices the state makes more money
in a gross tax; at high prices the state makes more money in a
net tax. North Dakota does much better than Alaska at low
prices, whereas Norway does better than Alaska at high prices.
North Dakota is not getting as much as it could because it has a
flat gross tax. On the other hand, at these low prices North
Dakota is doing very well because it is getting at least a
limited amount of revenue with the caveat being that people
aren't drilling wells anymore because their type of development
isn't profitable at prices of $30 or $40.
2:23:11 PM
MR. ALPER resumed his presentation, turning to slide 34, "North
Slope Life Cycle Modeling, 750 mmbo HB 247, $80 / bbl." He
commented that this is the more ambitious price, but as recently
as three years ago it would have been the low side. At a price
of $80 a barrel under the proposed changes of HB 247 the state's
cash flow out would be only $109 million, whereas under the
status quo (slide 31) it is $2.8 billion in credit spend. The
expected value of the state's production tax under the proposed
changes would be $1.7 billion, as compared to about $900 million
under the status quo. The overall state take under HB 247 would
be $4.4 billion, while under the status quo it is $3.5 billion.
The amount that would be removed from the producer's side of the
ledger to the state's is far less than it was at the lower
prices - [under HB 247 the producer cash net present value]
would be $1.4 billion, while under the status quo it is $2.2
billion, a migration of about $800 million in present value
through the tax credit reform contemplated in the bill.
MR. ALPER displayed slide 35, "North Slope Life Cycle Modeling,
750 mmbo HB 247, Fall 2015 FC Prices," and said it again splits
the difference. Similar amounts of increase in state value of
about $900 million and a similar decrease in company value of
about $900 million, and there would be the tremendous changes to
the state's cash flow between the big credit cost and the $25
million a year cap.
2:24:53 PM
MR. ALPER explained that slides 36-39 in many ways parallel
slides 32-35, only now what is being contemplated is that the
developer/producer in question would be a large international or
domestic company with $10 billion in revenue. [Under HB 247] a
company with $10 billion in global revenue would no longer be
able to get cash from the state, meaning the company would have
to use all of its credits and hold them against future
liability. Therefore, on slides 36-39, the upper left graph no
longer has any red bars below the line because the state isn't
paying any credits at all. The presumption is that a producer
of this size has enough money on its balance sheet to simply
build the project and pay the taxes and accept the credits when
it is done, much like Alpine, Kuparuk, and every other older
large legacy field in Alaska that was built without any credits
or state cash participation on the frontend. So, that is what
the modeling here is contemplating as well.
MR. ALPER addressed slide 36, "North Slope Life Cycle Modeling,
750 mmbo HB 247, $40/bbl, Co. w/ > $10 billion revenue." He
noted that at an oil price of $40 the state would have positive
value because it has no years with negatives; there would be no
less-than-zeroes dragging down a present value. The state's
total production taxes received would be just less than $1
billion and the discounted value of that would be $337 million.
The total state take would be $3.86 billion with a discounted
cash flow of $1.3 billion. The producer would have a big loss
of $3.8 billion, but under the status quo that number was a very
large negative as well. No one is going to make this investment
[at a price of $40].
2:26:49 PM
MR. ALPER moved to slide 37, "North Slope Life Cycle Modeling,
750 mmbo HB 247, $60/bbl, Co. w/ > $10 billion revenue," and
said that the models for the proposed zero credits barely moved
the needle as compared to the models for the proposed cap of $25
million. The numbers at stake here are so large that whatever
value the state is taking from these companies was done by the
time of cutting it down to the proposed $25 million and taking
that last $25 million and reducing the state's cash flow to $0
was a fairly insignificant change. For example, comparing slide
37 to slide 33 the cash flow to the producer [under the proposed
cap of $25 million] would be a non-economic negative $870
million, [while for a company with over $10 billion in revenue
it would be negative $974 million], a relatively small change
compared to the quite dramatic change that went from paying
open-ended tax credits to paying only $25 million a year.
MR. ALPER displayed slide 38, "North Slope Life Cycle Modeling,
750 mmbo HB 247, $80/bbl, Co. w/ > $10 billion revenue," and
noted that the field at a price of $80 would be quite profitable
to the producer at $1.3 billion even with all the changes
contemplated in the bill. Pointing to the spike in the graphs
that would happen to the state in about year 11, he explained
that the spike is the 10-year sunset of some of the earlier tax
credits that are rolled forward and used to offset tax
liability. When these credits suddenly go away a much larger
production tax starts to be paid beginning in year 11 or 13.
Some of the earlier tax credits have been overwhelmed by the
ability to use them against tax liability because the tax
liability only goes so high.
2:29:12 PM
MR. ALPER brought attention to slide 39, "North Slope Life Cycle
Modeling, 750 mmbo HB 247, Fall 2015 FC price, > $10 billion
rev." He said the fall forecast price is somewhere in between
$60 and $80, is mildly profitable for the producer and
reasonably profitable for the state, and has no negative cash
flow to the state at the frontend of the project.
REPRESENTATIVE SEATON inquired how this project would play out
if there were six companies, one them a company with revenue of
over $10 billion.
MR. ALPER replied by assuming that each of the partners would
own one-sixth of the project and spending one-sixth of the money
up front. Five of the companies would be eligible for the $25
million a year, so the state would be paying out about $125
million in total. The sixth company [with over $10 billion in
revenue] would be a smaller version of the modeling [on slides
36-39]. The $10 billion [revenue] cap is not tied to the amount
of oil the company produces, it is tied to the overall size of
the company. He said he would like to model some scenarios that
look at multiple partners, and his guess is that the economics
and impact of the bill would split the difference somewhere
between the status quo and the HB 247 slides. He advised that
as HB 247 evolves, it is important to create some language to
ensure that any doubling up is authentic and not an artificial
workaround trying to maximize the credit value, but being
several different legitimate companies that happen to be
partners in a North Slope project.
2:31:26 PM
REPRESENTATIVE TARR referred to slides 22 and 23 and asked how
DOR evaluated the status quo versus HB 247 in regard to the $25
million cap and the potential for companies to stretch out the
activity to keep spending around the cap versus accelerated
activity that would happen with more generous credits.
MR. ALPER responded that Mr. Mayer did a good job of talking
about that scenario when he was discussing a Cook Inlet field
that was market constrained. Mr. Mayer said that if companies
have to spend all of this money, but cannot produce enough gas
to pay for it because they cannot find a place to sell their
gas, that is where their economics were the most challenged.
But, if they could sell all the gas they produce and drill all
the wells they wanted, then the companies were fine without tax
credits. Mr. Alper said he thinks the same thing happens here.
The company is concerned about the time value of its money. If
the company stretched out the project for 10 years so as to stay
within the tax credit cap artificially, the company is also
delaying the payback that it will get for selling oil by the
number of years and the company has its own discount rates to
worry about.
REPRESENTATIVE TARR inquired whether DOR could see a scenario
where there would be behavior adjustments for one to three years
rather than ten years as a way to stretch it out.
MR. STICKEL answered that this was discussed internally when DOR
was doing the modeling. Certainly, if there is a $25 million
limit on refunded credits, companies would be expected to take
that into account when planning how to make their capital
expenditures. For purposes of today's modeling, DOR has assumed
the same spend profile on all of the different scenarios. So,
DOR is not assuming that the companies are making any changes to
the timing of their spending.
2:34:02 PM
MR. ALPER showed slide 4, "Field Life Cycle Modeling: Cook
Inlet," and stated that he has concluded the North Slope portion
of modeling and will now switch to the Cook Inlet modeling.
The committee took an at-ease from 2:34 p.m. to 2:44 p.m.
2:44:40 PM
MR. ALPER began the next portion of his presentation with slide
41, Cook Inlet Life Cycle Modeling Assumptions." He explained
that the same structure of modeling was used for the Cook Inlet
as was used for the North Slope. A giant field was not
envisioned for Cook Inlet, he said, so the modeling was only
done for a field size of 50 MMbo in place. He further explained
that in the Cook Inlet a new producer would be eligible for cash
refunds. [The modeling also applies for an incumbent producer
not eligible for cash refunds that can apply credits to other
North Slope fields.] Modeling was for the four price scenarios
of $40, $60, $80, and fall 2015 forecasted price [held static
though life of field and in real uninflated dollars]. The
modeling compares the status quo tax system to the changes
proposed in HB 247. Mr. Alper pointed out that under HB 247:
the minimum tax does not apply in Cook Inlet because it is a
North Slope only law, AS 43.55.011(f); the $25 million per
company per year limit is included; the repeal of the Qualified
Capital Expenditure Credit and the Well Lease Expenditure Credit
is included; and the 10-year limit on the carry-forward of Net
Operating Loss (NOL) Credits is included.
MR. ALPER further pointed out that it is unknown what the taxes
are going to look like for the Cook Inlet beginning in the year
2022. Under current law is a tax cap that has been in place
since the PPT bill in 2006, which severely limits the amount of
production tax that can be paid on both oil and gas produced
throughout Cook Inlet, whether old or new fields. This tax cap
sunsets in 2022. He recounted that in the first hearing he
discussed the underlying tax regime being very high and a little
bit unstable. The modeling here for Cook Inlet was done for two
tax regimes: one where the caps would continue indefinitely and
keep production taxes at effectively $0 for forever; and one
where the tax caps go away completely, which is a 35 percent tax
without any Per-Barrel Credit or any new oil Gross Value
Reduction (GVR) benefit. So, he explained, the status quo
modeling is for both too high and too low a tax regime. At some
point, he noted, the Alaska State Legislature will need to come
up with a future tax regime for Cook Inlet after the year 2022
MR. ALPER drew attention to an error on slide 41 in the fourth
major bullet, first sub-bullet, which states there is a GVR in
Cook Inlet. He said that is incorrect - there is no GVR in Cook
Inlet. The GVR is a benefit from Senate Bill 21 that is
specific to the North Slope.
2:47:46 PM
REPRESENTATIVE JOSEPHSON asked whether the modeling uses a price
per barrel equivalent given there are only 16,000 barrels of
oil, which in the world of oil is a very small amount. He
recalled that the idea behind not taxing the oil was to
incentivize gas production.
MR. ALPER replied that to be fair to the Cook Inlet it did once
produce 200,000 barrels of oil a day. The reason for such small
numbers now is that no new oil fields have come on in a long
time. The recent increases in production have primarily been
from workovers to improve the operation of mature oil fields.
2:48:35 PM
MR. ALPER discussed slide 42, "Cook Inlet Life Cycle Modeling
Assumptions, 50 mmbo field assumptions." He noted that the peak
oil production modeled was for 17,000 barrels a day, which is
what would be expected from a field of 50 Mmbo. The closest
analog to this is BlueCrest Energy, Inc.'s, Cosmopolitan Unit in
the Homer area. Development drilling is about to begin in that
unit and will begin in the oil field first because that is
BlueCrest's first priority. BlueCrest has said it is going to
have a similar dollar and number profile to what is presented on
slide 42, which is peaking out at 15,000-17,000 barrels a day
and capital expenditures of $12 a barrel. Mr. Alper elaborated
that the capital costs are a bit lower in the Cook Inlet than on
the North Slope primarily because the logistics are easier. The
tax caps were put in place to incentivize gas, but in many ways
they were there as a hold harmless. In 2005 the tax rate in
Cook Inlet really was zero - the ELF multipliers had eroded to
the point where all the then-existing oil fields in Cook Inlet
were paying a production tax of zero; all existing gas
production in Cook Inlet was paying around $.17 per thousand
cubic feet [Mcf], it varied from field to field. "So," he
continued, "what the ELF caps did was codify and lock in place
for 15 years that which already was at the moment of transition
to PPT and hold them harmless from what was primarily a tax
increase on the North Slope."
2:50:07 PM
MR. ALPER turned to slide [43], "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, 2022 Tax Caps expire, $40/bbl." He
explained that because the tax caps would expire [in 2022] the
state would get a production tax and it would be reasonably high
at 35 percent of production tax value/net value. Referring to
the upper left graph, he said that at a price of $40 there is
not a lot of net value, so the state would pay out about $350
million in tax credits to get the field in this scenario
produced. A total of $172 million in production taxes would be
generated over the life of the field, with a cash flow on just
the net production tax of about negative $177 million. The
discounted value, or net present value, to the state would be
negative $192 million. Referring to the upper right graph for
total state take, he noted that even with a royalty of 12.5
percent [and property and corporate income tax] in addition to
the production tax there would still be a negative present value
to the state [negative $59]. There would be positive cash flow
for many years and $99 million more would be coming in than
going out, but because of the time value of money the state
would lose $59 million in value. Referring to the lower right
graph, Mr. Alper said that under the status quo the producer
would get a large amount of tax credits in the early years, with
$90 million or more a year for a couple years of peak
construction. Once the producer begins selling oil it would
have a positive cash flow and the producer's cash net present
value would be $3 million. He pointed out that $3 million is
within the rounding error and so this would be a breakeven or
worse field for the producer and therefore not likely to happen
at a price of $40.
2:52:11 PM
MR. ALPER reviewed slide 44, "Cook Inlet Life Cycle Modeling, 50
mmbo Status Quo, 2022 Tax Caps expire, $60/bbl." He noted that
this scenario is the same field of 50 MMbo but at a price of
$60, and with the expectation that the tax caps would expire so
that production tax would begin to be paid in 2022. The state
would pay out $337 million in production tax credits against
$465 million in production tax paid, so a positive net
production tax of $128 million but with the time value of money
it turns into a negative $50 million. However, the state is
positive on total take. There is enough money from the state's
royalties to make up for the loss of money from the production
tax. The net state gain is $579 million with a discounted value
of $167 million at the 6.15 percent discounted rate. The
producer, even though paying a 35 percent tax rate, would see a
positive net present value of over $200 million over the life
cycle of this field in Cook Inlet.
MR. ALPER addressed slide 45, "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, 2022 Tax Caps expire, $80/bbl." He said it
is again the same field with the same assumptions but at an oil
price of $80. In this scenario the state makes enough money
from the production tax to more than make up for the negatives
of the credits. The positive cash flow to the state from the
production tax is $92 million. Adding in the royalties the
state would have almost $400 million in value. The actual
positive cash flow to the state would be about $1 billion,
meaning the state spent $300 million and received $1.3 billion
back, but some of that comes many years later. The producer
would see a positive cash flow of over $150 million in the peak
year and a decline with the decline of the field. The
producer's total cash flow would be $915 million, which is a
discounted cash flow of just less than $400 million.
2:54:21 PM
REPRESENTATIVE JOSEPHSON, regarding slide 45, understood that in
2022 the Qualified Capital Expenditure (QCE) Credit and the Well
Lease Expenditure (WLE) Credit are gone. He inquired whether
this would be a laissez faire do-what-you-will economy or would
the state be incentivizing.
MR. ALPER responded no, this is the status quo scenario. The
QCE Credit and the WLE Credit do not have sunsets in existing
statute. Thus, the relatively high credit spend for the state
(red bars in the upper left graph) are the QCE, WLE, and Net
Operating Loss credits. The tax caps will expire in the status
quo/do-nothing scenario, so slide 45 is the do-nothing scenario.
2:55:34 PM
MR. ALPER moved to slide 46, "Cook Inlet Life Cycle Modeling, 50
mmbo Status Quo, 2022 Tax Caps expire, Fall 2015 FC Price." He
said the forecast price is a number somewhere in between $60 and
$80. The production tax credits to help develop the field would
be [$335] million. To put that [$335] million in perspective,
he noted that the assumption for this 50 MMbo field is a capital
expenditure of $12 [per barrel], so the total company capital
spend is about $600 million to build this field. Thus, the
company is spending $600 million and getting back $335 million
[in credits], which is a bit more than half, and that roughly
lines up with the expectation that there is an operating loss
credit and a drilling credit that are generally stackable
against each other. Today the state is paying in the range of
50-60 percent on new field construction in Cook Inlet, so that
is assumed to continue with the sunset of the tax caps.
MR. ALPER addressed slide 47, "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, Tax Caps extended, $40/bbl." He pointed out
that this slide is the same as slide 43 in that it is the status
quo, but on slide 43 the producer is paying tax because the tax
cap expires. In the scenario on slide 47 the production tax
received by the state is $0 because it is an oil field and the
production tax rate for the Cook Inlet tax caps is zero. That
number is not offset by credits, it is a flat zero. Thus, the
state pays $357 million in credits and that is the total
negative cash flow, there is no positive cash flow on the
production tax side. For total state take, however, there is
the royalty, but the royalty doesn't adequately offset the
negative cash flow for the credits at a price of $40 so the
state would lose $137 million. Regarding the producer, he
specified that this is one scenario where the producer is
actually profitable at an oil price of $40 simply because the
producer is enjoying the high credits on the upfront side and
then not paying any production taxes over the life of the field.
Thus, the producer's discounted cash flow is $54 million.
2:57:59 PM
MR. ALPER turned to slide 48, "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, Tax Caps extended, $60/bbl." He said this
slide is comparable to slide 44 except slide 48 is without the
production tax. The credits are the same, roughly $100 million
a year at peak. Even with the royalty coming in, at a price of
$60 the state is still in a negative cash flow/negative value
situation [negative $37 million], while the producer has a
positive discounted cash flow of $335 million.
MR. ALPER showed slide 49, "Cook Inlet Life Cycle Modeling, 50
mmbo Status Quo, Tax Caps extended, $80/bbl," relating that per
the tax caps the production tax is zero. The credit spend is
offset by primarily the royalty revenue, so total state take is
$63 million in discounted cash flow. The producer sees the
great bulk of the value here with a $612 million benefit versus
the $63 million received by the state. Mr. Alper clarified that
DOR doesn't consider these to be realistic scenarios. He said
he doesn't think it is likely that the decision will be made to
extend the production tax caps forward indefinitely while
keeping the credit system intact as it is, but the modeling had
to start somewhere. The department is looking at reality as
coming in somewhere between slide 49 and slide 45.
2:59:26 PM
REPRESENTATIVE JOSEPHSON asked why Mr. Alper does not foresee an
extension of the tax caps in 2022.
MR. ALPER answered that he has no particular reason; it is
because the state held producers harmless for 15 years with the
changes on the North Slope. He said he doesn't know where that
number came from, why the decision was made for 2022. But, as
seen on these slides, having a production tax of zero while
still paying large credits doesn't work very well for the state.
It might get certain work done, but part of the whole argument
for having a robust tax credit system that might in some ways
wipe out the state's production tax revenue is that at least the
state gets the royalty, a fully legitimate and reasonable
argument to make. But, if the royalty doesn't even make up for
the amount of the production tax, it seems that there is a
little inherent instability in the system. That was mentioned
by Mr. Mayer - industry sees a big unknown looming in 2022.
REPRESENTATIVE JOSEPHSON inquired why the administration would
not have entertained reform of the tax structure in Cook Inlet,
given the administration did not intend to amend Senate Bill 21
and this is not a Senate Bill 21 item.
MR. ALPER replied it is not imminent. Realistically, the tax
reform in Cook Inlet has to happen between now and the 2021
legislative session. There are more pressing concerns related
to the cash flow of the tax credit regime; that is what HB 247
was written to do. The administration did internally discuss
ways to do it and the most straight forward way, which was
actually modeled by Mr. Mayer, is to take Senate Bill 21 and
extend it statewide. That is as plausible and realistic a
scenario as any other and DOR could bring the committee modeling
to that effect. The choice was made to leave the Cook Inlet
taxes in place cleanly and not mess with that in the five-year
gap between now and their expected sunset, but it could be done.
It is a whole different set of things to propose and deserves a
robust process to even think about what the Cook Inlet tax
should be in the future.
3:01:58 PM
REPRESENTATIVE OLSON asked whether the committee will be getting
the Cook Inlet gas modeling tonight.
MR. ALPER responded that DOR did not model a gas field from
scratch from Cook Inlet for this presentation. It gets a lot
more complicated because of cost issues. He requested Ms.
Cherie Nienhuis to speak to why the department was unable in the
short term to come up with Cook Inlet gas field modeling.
CHERIE NIENHUIS, Commercial Analyst, Tax Division, Department of
Revenue (DOR), answered that modeling could be done. However,
part of the issue is the same thing that Mr. Mayer talked about
in that the situation in Cook Inlet for gas is constrained by
the market and part of the difficulty in modeling that is
knowing exactly how much gas can be produced over a lifetime and
what some of the costs are for that gas. She said she would
assume that depending on where the gas is located could make a
very large difference in terms of what the cost is to bring that
gas to market. It is not that DOR cannot do it, DOR could try,
but some of those difficulties presented themselves when DOR was
first doing this modeling.
REPRESENTATIVE OLSON inquired whether that is something that is
needed for making an educated decision on HB 247.
MR. ALPER replied that Mr. Mayer's scenarios of one, two, and
three were very compelling to him, and what he took from them
was that the gas price in Cook Inlet is somewhat regulated and
relatively high compared to the oil price right now. Under the
expected prices under normal circumstances a development is
profitable today. Where the producer's constraint comes from is
the inability to sell it because it is not a liquid market like
oil. For oil, no matter how much oil is produced someone will
be found to buy it. Gas is stranded within the Cook Inlet
Basin. The assumption to be made is whether a producer can
drill all the wells that are needed to develop this field. If a
$400 million platform must be built and then the developer is
not able to drill the few wells a year that it will take to make
the gas come at a worthy pace to justify spending that $400
million, then it is going to be a very difficult project. The
educated guess is whether there is going to be a market for Cook
Inlet gas. If an investment is made to develop that much gas,
there is the second-order question of whether there is a place
to sell it and that is a question that DOR cannot easily answer,
although there is other legislation in this building trying to
answer that.
REPRESENTATIVE OLSON requested that there be follow-up on this
at the committee's hearing tonight.
[Mr. Alper continued his presentation at the committee's 6:00
p.m. meeting on this same day.]
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES HB247 DOR Fiscal Details and Scenario Modeling (Part 2a) 2-26-16.pdf |
HRES 2/27/2016 10:00:00 AM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 ver A.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Sectional Analysis.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Fiscal Note - DOR-TAX-2-1-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB247 Fiscal Note - FUNDCAP-OIL & GAS TAX CREDIT FUND-2-1-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB 247 Oil Credit Bill - Key Features 2-2-16.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HB 247 Production Tax Credits FY07-FY25 Excel Table_Figure 8-4_Fall 15 RSB.pdf |
HRES 2/3/2016 1:00:00 PM HRES 2/5/2016 1:00:00 PM HRES 2/10/2016 1:00:00 PM HRES 2/12/2016 1:00:00 PM HRES 2/22/2016 1:00:00 PM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| HSE RES Dept. of Revenue - Tax Division glossary of terms HB 247 sectional.docx |
HRES 3/7/2016 1:00:00 PM |
HB 247 |