Legislature(2015 - 2016)BARNES 124
03/07/2016 06:00 PM House RESOURCES
| 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
6:03:13 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."
6:04:36 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
continued his PowerPoint presentation on behalf of the governor
entitled, "Oil and Gas Tax Credit Reform- HB247, Additional
Modeling and Scenario Analysis - Part 2a," which he had begun at
the committee's 1:00 p.m. meeting today. He noted that slides
47-50 in many ways parallel slides 40-46, all of them being
modeling of the status quo looking at the assumptions of a new
oil field [of 50 million barrels of oil (MMbo)] being developed
in Cook Inlet. The only difference between the two sets of
slides is what happens in the year 2022 when the current tax
caps are scheduled to sunset under existing law. The modeling
on slides 40-46 show the answers for the taxes that would be
paid under the underlying tax regime of 35 percent net profits
tax. The modeling on slides 47-50 show the answers for what
would happen if the Cook Inlet caps were extended indefinitely.
MR. ALPER turned to slide 48, "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, Tax Caps extended, $60/bbl." He pointed out
that at an oil price of $60 per barrel (bbl), the amount of
production tax paid would be zero because the current statutory
production tax on oil in Cook Inlet is zero. This is based upon
the conditions that were in place in 2006 when the production
profits tax (PPT) was passed [Twenty-Fourth Alaska State
Legislature, House Bill 488]; those are the old Economic Limit
Factor (ELF) multipliers. In a zero tax scenario at a price of
$60, this field would be quite robust for the producer, but the
state's net present value (NPV) would be negative $37 million.
The state would receive money from royalty and eventually would
have a positive cash flow, but not enough to compensate the
state for credit cost up front, especially without any backend
production tax revenue.
6:06:27 PM
REPRESENTATIVE SEATON understood that a minimum of 25 percent of
the royalty is required to go to the permanent fund and so
unavailable for the general fund, and that the property tax is
split about 50:50 in Cook Inlet. Referring to the bottom right
chart on slide 48, he requested an explanation of what is
included in the figures on lines 6-9.
MR. ALPER offered his belief that these numbers include the non-
permanent fund share of the royalty, meaning the general fund
portion of the royalty which is 75 percent. He said he is
fairly certain that the numbers include only the state's portion
of property taxes, meaning the portion that is shared with
municipalities is not included in this analysis. So, this is
the state's unrestricted general fund cash flow as an isolated
dataset. He requested Ms. Cherie Nienhuis to confirm whether he
is correct in his answer.
CHERIE NIENHUIS, Commercial Analyst, Tax Division, Department of
Revenue (DOR), offered her belief that the state revenue in this
case does include the amount that would go to the permanent
fund. If only the revenue that goes to the general fund was
represented it would be called general fund unrestricted revenue
(GFUR). She further offered her understanding that this is
state revenues only and does not include the amount that would
go to the municipalities for the property tax, but it does
include the amount that would go to the permanent fund.
REPRESENTATIVE SEATON requested that the department get back to
the committee with a verification of the answer so committee
members can understand exactly what is included.
MR. ALPER thanked Ms. Nienhuis for correcting him and explained
that part of the confusion is that DOR did the analysis both
ways for Representative Seaton's request. The request had asked
for a broader set of analysis with different cash flows and he
was not sure which one survived to the version that is now
before the committee.
6:09:00 PM
MR. ALPER addressed slide 49, "Cook Inlet Life Cycle Modeling,
50 mmbo Status Quo, Tax Caps extended, $80/bbl." He specified
that once again no production tax is paid, but when the royalty
is included the state has a positive NPV of $63 million.
However, he qualified, if this is looking at general fund only,
then that might go back to being a negative number and so that
needs to be found out. The producer's discounted cash flow is
relatively robust at $612 million. Generally speaking, there is
not a lot of difference in the shapes of the curves on slides
47-49, it is just a matter of the magnitude that is tied to the
different prices of oil.
REPRESENTATIVE JOSEPHSON said that when looking at these slides
his eyes continually focus on the comparison with opportunity
lost. He asked whether this is what DOR is trying to reflect in
the state NPV 6.15 percent.
MR. ALPER responded that when it is said "state NPV 6.15
[percent]," yes. It is the value of what is called a discounted
cash flow. A dollar received next year is 6.15 percent less
valuable than a dollar received this year. A dollar received
two years from now would be 6.15 percent times 6.15 percent less
valuable. So, the deeper into the future the less the money is
worth to the state.
REPRESENTATIVE JOSEPHSON, regarding slide 49, inquired whether
the state's $337 million is the comparison to [the producer's]
$1.385 billion.
MR. ALPER answered that the [net] cash flow, the money in/money
out, without worrying about time, is $337 million for the state
as compared to the producer's [net] cash flow of $1.385 billion.
In terms of the time value of money, the state's $36 million
compares to the producer's $612 million.
6:11:15 PM
MR. ALPER moved to slide 50, "Cook Inlet Life Cycle Modeling, 50
mmbo Status Quo, Tax Caps extended, Fall 2015 FC Price," and
specified that in all of these models the forecast price falls
somewhere in between $60 and $80. In this scenario, the state's
NPV number of $14 million is almost exactly zero because with a
dataset this large $14 million is essentially a rounding error.
The producer's cash NPV is $481 million. This slide is a
relatively unlikely scenario of the status quo in that it
presumes that the legislature chooses to indefinitely extend the
existing caps on Cook Inlet taxes without making any other
changes to the tax and credit regime in Cook Inlet.
REPRESENTATIVE JOSEPHSON recalled that when asked about this at
the committee's 1:00 p.m. meeting today, Mr. Alper responded
that it was unlikely the legislature would extend the caps
beyond 2022. Representative Josephson posited that the
arguments heard before would be the same arguments [in 2022],
short of having a gasline coming from the North Slope to the
city gate and in which case the legislature might logically ask
what it is doing with Cook Inlet at that point. He asked Mr.
Alper to address why the arguments would be any different.
MR. ALPER replied that to his knowledge no one is actively
asking for extension of the Cook Inlet tax caps right now. As
heard in last week's invited testimony before the committee, he
continued, there are certainly many proponents to keeping the
tax credit regime in place the way that it is. The caps were
left in place for 15 years, a very long time. A production tax
of zero is hard to justify over the long term unless the state
simply did not have a production tax and that would be a very
different thing. The state does have a production tax on the
books that pays out a lot of credits. As shown by the red bars
[in the upper left graph], at the forecasted price the state is
spending $347 million on tax credits of various sorts to the
owners of that field without any production tax. As a diligent
sovereign, as an entity desiring to balance a budget and do all
the many things that the Alaska state government needs to do, it
is hard to imagine a justification for that over the indefinite
long term.
6:13:53 PM
MR. ALPER looked at the first of several slides dealing with the
impact of HB 247. Turning to slide 51, "Cook Inlet Life Cycle
Modeling, 50 mmbo HB247, 2022 Tax Caps expire, $40/bbl," he
explained that the bill's proposed cap of $25 million per
company is clearly apparent in the red bars on the upper left
graph. He noted the reimbursements are at $25 million for
several years before they reduce and the state gets positive
cash flow from the production tax. Even with that, at a price
of $40 it is not really making a lot of money for anybody. But
the production tax is enough to provide positive cash flow to
the state of $159 million, with a discounted cash flow of
negative $19 million. The state's total cash flow, including
apparently permanent fund royalties, creates a positive net
present value of $108 million. Although he argued earlier that
a scenario of maintaining the tax caps forever is too low, this
tax regime for Cook Inlet is almost certainly too high. This is
a 35 percent net profits tax without any sort of comparable
benefit like the Per-Barrel Credit that exists on the North
Slope and without any sort of Gross Value Reduction (GVR)
benefit for new oil that exists on the North Slope. At just the
35 percent net tax the state has a positive net present value,
and once the royalty is included the producer is losing money at
an oil price of $40.
6:15:33 PM
MR. ALPER discussed slide 52, "Cook Inlet Life Cycle Modeling,
50 mmbo HB247, 2022 Tax Caps expire, $60/bbl." He pointed out
that at a price of $60 this is a money-making field to the
producer at a positive net present value of $80 million, despite
the onerous production tax regime and the cutting off of the
credits at $25 million. The state would have a discounted net
present value of $121 million on the production tax. The
state's total revenue would provide a net present value of $331
million. In this scenario the tax credits themselves would be
cut off at $25 million per year. Mr. Alper outlined the state's
numbers shown in the bottom right chart: state's production tax
NPV - $121 million; state's NPV - $331 million; producer's cash
NPV - $80 million. He then brought attention to slide 44
[depicting the status quo at $60 a barrel with the tax caps
expiring: state's production tax NPV - negative $50 million;
state's NPV - $167 million; producer's cash NPV - $202 million].
Comparing the numbers for both scenarios, he said that under HB
247 the state would gain about $170 million on the production
tax NPV and the producer's cash NPV would lose about $120
million. This gain for the state would primarily be from moving
the cash flow around of the $25 million per year cap on the
refunded tax credits.
MR. ALPER moved to slide 53, "Cook Inlet Life Cycle Modeling, 50
mmbo HB 247, 2022 Tax Caps expire, $80/bbl." He noted that in
this scenario the state would get a robust cash flow from the
production tax [$263 million], an excellent cash flow from total
state take [$557 million], and the producer would see a cash
NPV/discounted value of $278 million. He clarified that in
these various scenarios the cost profiles and all other
assumptions have stayed the same as the price of oil was moved
around, thus the changes are purely the impact of the changes in
the price of oil.
6:18:29 PM
REPRESENTATIVE JOSEPHSON inquired whether Mr. Alper is saying
that a future legislature would need to revisit this tax before
2022 or in 2022. He further inquired whether the passage of HB
247 along with the expiration of the tax caps would result in a
scenario that is too favorable to the state.
MR. ALPER responded that the expiration of tax caps in 2022 is a
pending issue before the legislature with or without the passage
of tax credit reform this year. In his opinion, that production
tax is likely too generous and, frankly, unstable for Cook Inlet
given the inlet's constraints. That tax system would also be
the same tax system for gas - 35 percent of net profits without
any offsets or Per-Barrel Credits. He explained that it was not
so much left there to be the tax system, but was left there
because a previous legislature, when looking to reform North
Slope taxes, did not need to worry about the Cook Inlet yet
since it was enough years off in the future. It is a problem
that might not need to be addressed until the Thirty-Second
Alaska State Legislature in the 2021 session. He recounted that
the legislature's consultant, Mr. Janak Meyer of enalytica, and
whose testimony he is inclined to agree with, testified that
industry finds instability in Alaska's system in a couple of
different places. First, the State of Alaska has giant deficits
and therefore industry does not know what the state's government
is going to look like in a year or two. Second, and more
importantly in the context here, industry sees the state's
extensive negative cash flow from the tax credit system. The
state is spending hundreds of millions of dollars that are more
than the amount of production tax revenue coming in and industry
is presuming, on a certain level at least, that some sort of
reform is going to be made and industry is building that
instability into its assumptions. Third is the sunset of the
tax caps. Industry does not know what the fiscal system is
going to be for the majority of the life cycle of any decision
that industry might make now. Any investment decision made now
or soon is a multi-year decision and industry does not know what
the tax is going to be for the tail end of it. He said he would
be happy to work with the committee, if it is so inclined, to
create a new Cook Inlet oil and gas tax system.
6:21:56 PM
MR. ALPER resumed his presentation and addressed slide 54, "Cook
Inlet Life Cycle Modeling, 50 mmbo HB247, 2022 Tax Caps expire,
Fall 2015 FC Price." In this scenario, he said, the forecast
price is going up from $50 now to $56 next year and stabilizing
into the $70s. Without considering inflation, DOR sees the
state with positives on the production tax [$197 million],
higher positives on the overall take [$451 million], and the
producer with a positive value of $183 million. He pointed out
that the cash flow on such a field drops off quite rapidly after
peak production, which is the nature of any large oil field.
Fields of 50 MMbo, he continued, peak at 17,000 barrels a day of
production, but production declines rapidly after that peak.
6:22:36 PM
MR. ALPER brought attention to slide 55, "Cook Inlet Life Cycle
Modeling, 50 mmbo HB247, Tax Caps extended, $40 bbl," explaining
that this scenario is the tax caps extended with the impact of
HB 247 [at a price of $40 a barrel]. The credits are capped at
$25 million per year with a sum total payout in tax credits of
negative $142 million. Passage of HB 247 would also result in
the repeal of the Cook Inlet Well Lease Expenditure (WLE) Credit
and the Qualified Capital Expenditure (QCE) Credit. In this
scenario the state would only be paying 25 percent of costs
through the development phase via the Net Operating Loss Credit,
as opposed to the 50-60 percent that the state is currently
paying. The state's cash obligations would be cut by more than
half, which tremendously helps the state's bottom line. Even
with that, at a price of $40 a barrel the state would be losing
money on production tax because there is no production tax and
would barely be making money on the total state take [$29
million in state NPV]. The producer would lose money [negative
$76 million in cash NPV], as is also the case in the status quo.
The difference in these numbers is about the same between the no
tax system and the underlying tax system, as there is between
the before and the after with the passage of HB 247. The order
of magnitude is about the same.
MR. ALPER discussed slide 56, "Cook Inlet Life Cycle Modeling,
50 mmbo HB247, Tax Caps extended, $60/bbl," noting that a price
of $60 is closer to a breakeven price for everyone. At this
price the state would pay $134 million in credits, with a
discounted value of negative $97 million. The total state take
would be decent at $126 million. The producer does better at
this price [with a cash NPV] of $214 million.
6:24:52 PM
MR. ALPER turned to slide 57, "Cook Inlet Life Cycle Modeling,
50 mmbo HB247, Tax Caps extended, $80/bbl." Drawing attention
to the top right graph he pointed out that while it looks like
the numbers are smaller, it is only because the scale of the
graph is at $100 million while the scale for this same graph on
slide 56 is at $50 million. Total state take in the $80
scenario is close to $80 million a year in the peak years of the
project, with a total state take discounted value of $225
million. [The production tax NPV is negative $92 million.] If
the tax caps are extended, the production tax is never going to
be a positive number, he noted. If the state spends any money
on credits in any one year it becomes a negative money for the
entirety of the calculation because there is never a positive
number to offset against. The producer would be at a cash NPV
of $[494] million.
MR. ALPER displayed slide 58, Cook Inlet Life Cycle Modeling, 50
mmbo HB247, Tax Caps extended, Fall 2015 FC Price," and said the
state does pretty well at an oil price of $80 and the producers
do better. A regime of the tax caps extended, he added, would
be a very generous regime to industry.
6:26:15 PM
MR. ALPER drew attention to the summary tables on slides 60 and
61. He explained that slide 60, "Summary Table- North Slope,"
includes on one page all 20 of the North Slope modeling
scenarios that he presented. The first eight scenarios were
based on a smaller field of 50 MMbo, four of the scenarios
depicting the status quo at four different prices and four of
the scenarios depicting what would happen under the proposals of
HB 247 at four different prices. Each scenario includes a
summary column for the total credits paid by the state, the
state's net of production tax credits minus eventual taxation,
the state's discounted value of that cash flow, net state gain,
state net present value (NPV), the producer's cash flow, and the
producer's NPV/discounted value. Across the board, all of the
$40 scenarios are losers for the producer. All of the $60
scenarios for the smaller field are winners for the producer
under both the status quo and the proposed changes of HB 247.
The changes made by HB 247 do turn the large field from a small
gain to a loss, with the main reason for that being the cap of
$25 million a year on how much credits the state is prepared to
purchase; this is a much bigger deal for a much bigger field.
The 12 scenarios for the 750 MMbo field include two different
"after" scenarios - one where a company gets the $25 million and
one where a very large company of more than $10 billion in
revenue is completely excluded from being able to get state cash
rebates. He drew attention to the last column for producer NPV
at a price of $80 for a 750 MMbo field at the status quo, noting
it would be $2.216 million. This amount drops to $1.415 billion
if the producer gets $25 million a year from the state, and when
the company gets no credits the producer NPV drops by only $60
million [to $1.355 billion]. So, there is far more impact done
from the reduction in credits to $25 million than the further
reduction to zero in credits.
6:29:40 PM
MR. ALPER reviewed slide 61, "Summary Table- Cook Inlet," which
includes on one page all 16 scenarios that he presented for the
Cook Inlet. He reminded committee members that DOR only looked
at the smaller field of 50 MMbo because the department does not
anticipate elephant fields in Cook Inlet. Two tax regimes were
looked at [for the status quo and proposed changes under HB 247]
with the question being asked of whether the tax caps sunset
(third column). At an oil price of $80 in the status quo and a
sunset of the tax caps, the producer's NPV drops from $396
million to $278 million, a loss of about $118 million in net
present value. If the tax caps are extended, the producer loses
about $120 million. So, similar numbers but the increment
between a sunset of the tax cap and not a sunset within the
status quo is actually bigger; it is over $200 million benefit
to the company of extending the tax caps within the status quo
and over $200 million benefit from the company from extending
the tax caps within the HB 247 scenario. He said the argument
he is making is that the credit changes, while material, are
smaller in magnitude than any other decisions that a future
legislature would make about the tax regime itself that impacts
production in Cook Inlet.
MR. ALPER further mentioned that DOR would like to put together
some gas field life cycle modeling and that this could be done
in fairly short order. Slides will be provided to the committee
so DOR does not need to be scheduled again before the committee.
He noted that Representative Olson after today's earlier hearing
asked whether DOR had other scenarios. Something DOR has done
on the North Slope side is to look at a field of 750 MMbo and
what the impact would be if it were in a high royalty location,
a part of the state where the producer is paying the one-sixth
rather than the one-eighth royalty. Although the state gains
money on the royalty side with that higher royalty, the state
loses money on the production tax side because of the way Senate
Bill 21 [passed in 2013, Twenty-Eighth Alaska State Legislature]
is constructed so that the Gross Value Reduction (GVR) for new
oil increases from a 20 percent benefit to a 30 percent benefit
if the entirety of a field is at the high royalty level. The
bottom line numbers are about the same and DOR will be providing
these slides to the committee, but it is more royalty and less
production tax.
6:32:40 PM
REPRESENTATIVE OLSON asked whether this same type of summary
table could be done for the Interior, Middle Earth, and
everything that is going on in Fairbanks.
MR. ALPER answered he is pretty sure it can be done but he will
check with his staff. He offered his belief that Middle Earth
has its own statutory tax caps of 4 percent of gross value that
are good until 2027, thus providing a bit more certainty for the
short and medium term as to what the tax is going to be. He
noted that something could be done along the lines of the kind
of development that Doyon, Limited, is talking about for the
Nenana area.
REPRESENTATIVE OLSON inquired whether there are tax credits for
the Fairbanks liquefied natural gas (LNG) storage facility and
suggested that those be included. He also inquired about
including the in-state refinery up north.
MR. ALPER replied that these are hard credits to build into
project-level modeling. The Fairbanks utility, the Fairbanks
regional project, is going to benefit from the storage tank
credit, which is a comparable credit to what was received by the
Cook Inlet Natural Gas Storage Alaska (CINGSA) facility. He
said he does not know where the refinery credits can be built
into that as he does not know enough about the local utilities
and needs as to where that might play into the project itself.
He offered for Representative Olson to talk to him after the
hearing for directions on how to run this modeling request.
REPRESENTATIVE OLSON said he thinks he and Mr. Alper are on the
same page, which is why he asked the question. He acknowledged
that his request will be a lot of work but said it will help the
committee.
MR. ALPER noted that DOR provided three presentations to the
Senate Working Group last fall - one dedicated to Cook Inlet,
one to North Slope, and one to Middle Earth credits. He said he
will provide the committee co-chairs with the links to those
presentations so committee members can read those presentations
which provide a good overview of how the credits are structured
and used, what the benefits are, and what the sunsets are. The
presentations will serve as a good background document and DOR
will do some modeling on a theoretical future project.
6:35:26 PM
REPRESENTATIVE SEATON asked whether DOR can also make sure that
the committee receives some modeling on private royalty/private
land and what the state is providing in that type of scenario.
He said it would be helpful to know what the state's cash flow
is for projects where the state does not receive any royalty.
MR. ALPER responded that DOR earlier provided the committee with
an analysis that was done for a member of the other body showing
the royalty breakdowns for federal lands such as the National
Petroleum Reserve-Alaska and Arctic National Wildlife Refuge, as
well as for private royalty that will be shared with the
committee soon. The department would like to run some
scenarios. The first project by Doyon, Limited, works out great
because it is on state land, but Doyon's second project is on
its own private land and would have a very different cash flow
to the state. He said DOR may not get into the multiple
variations and different price scenarios, but maybe a few less
options for each possible scenario so as not to inundate the
committee with 50 more slides.
6:36:56 PM
REPRESENTATIVE TARR commented that in regard to evaluating these
different tax structures it is frequently heard that there not
be winners and losers, or that one company size not be favored
over another, or development opportunity. She said HB 247 moves
away from some of the other credits to net operating loss
structurally, but keeps 35 percent for North Slope and 25
percent for Cook Inlet. She asked what the reasoning was for
that and whether DOR has considered doing the same for both
areas and why that would be good or bad.
MR. ALPER answered that the 35 percent Net Operating Loss Credit
on the North Slope came along for the ride with the 35 percent
base tax rate in Senate Bill 21. That change was only applied
to the North Slope. However, the portion of the tax code that
talks about the base rate did not parse it out, it actually put
that 35 number in statute. That is why Alaska has this 35
percent tax rate in Cook Inlet. It would certainly be possible
to put in a 35 percent operating loss credit without a terribly
complicated amendment. That would increase the state's cost,
the state's liability. A part of the rationale for the higher
operating loss credit on the North Slope is that the companies
actually are paying those taxes. So, there is some measure of a
playing field leveler in play here. For example, if a major
producer spends one more dollar on some new field, the producer
reduces its taxable income and therefore saves 35 cents on its
taxes. Regardless of the Per-Taxable-Barrel Credit, the tax
savings is at the marginal rate of 35 percent, so the state
offers a 35 percent operating loss credit to the new company
that does not have profits. Up until such time as the incumbent
producers in Cook Inlet are actually paying taxes, there is not
really a playing field to level; the state does not need to give
a higher benefit to the company on its loss credits to make them
equitable with the taxpayer if the taxpayer's effective rate is
zero for the next five years. At such time as there is a new
Cook Inlet tax regime, it seems to him that a new Cook Inlet
operating loss credit would be an important component of that.
6:39:48 PM
REPRESENTATIVE JOSEPHSON, following up on Representative Tarr's
question, said the other factor is the whole issue of the need
for natural gas in Southcentral Alaska. [indisc. - technical
sound difficulty] ... more parity with the North Slope.
MR. ALPER replied that that is an excellent point. Although not
as overwhelming or as imminent as it might have been a few years
ago, there remains some sense of gas supply anxiety for the Cook
Inlet utilities. If the state needs to provide a higher level
of benefit to keep that gas being produced, especially in a
world where the proposal is to eliminate the drilling credits,
it is a reasonable argument to say that 35 percent as a sort of
a compromise number going forward might be viable. [The
administration] is not proposing that and he is not in a
position to offer that, but while going from 50, 60, to 25,
going to 35 might certainly blunt the impact.
6:40:52 PM
REPRESENTATIVE OLSON inquired whether DOR has done any models on
the Agrium bill [HB 100] and the potential impact of the credit
that is proposed by that bill.
MR. ALPER responded that he is familiar with the provisions and
the economics embedded in [HB 100] because he wrote DOR's fiscal
note for the bill and the bill analysis for the governor. He
said it is an interesting concept and has a lot of upside for
the state without that much downside simply because there is no
upfront cash expended. It is very different as envisioned to
any of the credits that the administration is looking to reform
here in that it would require the producer, Agrium, to do all
the work and make the commitment to redevelop its facility and
then begin purchasing large amounts of gas and then earn a
profit and start having a corporate income tax obligation.
Then, any credit that Agrium earned through HB 100 would be an
offset against Agrium's corporate income tax liability. What
that bill could do potentially is provide the security for gas
suppliers to drill and develop new fields. For example, Furie
Operating Alaska, LLC, ("Furie") may have made a large discovery
and has signed some relatively small sales contracts. But if
Furie is in fact sitting on a large resource, Furie would like
to be able to develop it but cannot do that unless it has a way
to sell it. Something like a rebuilt Agrium facility might go a
long way towards giving Furie the security it needs to do that,
and in that case it would make it easier to modify some of the
Cook Inlet tax credits because there would be a lot less supply
anxiety going forward.
REPRESENTATIVE OLSON asked whether there is something that the
administration might support.
MR. ALPER answered he is not in position to speak for the
administration and does not know if the governor has taken a
position on HB 100. He added that he did his best to analyze HB
100 and model it as dispassionately as he could and talk about
the potential benefits. It is a hard year to have a tax credit
bill, given there is negative cash flow to the state, the state
is losing money, and the state has big deficits. He is before
the committee with a bill to reduce the state's spending on tax
credits by several hundred million dollars, so it is hard to add
another credit. However, there is a lot of argument to be made
for targeted, smaller, focused credits which have a really good
multiplier for the state's economics.
6:43:38 PM
REPRESENTATIVE SEATON, regarding the Cook Inlet, recalled the
legislature's consultants stating that $5-$7/Mcf is sufficient
gas price to develop even the most expensive gas around the
world. So, he surmised, those credits are not needed for gas
production in almost every scenario. If the state continues to
pay the credits in Cook Inlet and getting the multiple of 8,000
or more barrels a day, the state will be paying annual credits
in the range of $200-$400 million. The state is effectively
subsidizing $68-$136 per barrel, even if some of the companies
are drilling for gas but the credits were not needed to get that
drilling. He inquired whether there is a mechanism that could
be applied to separate oil from gas, given the combined drilling
costs and combined capital costs equation.
MR. ALPER replied that the figure of $136 comes from an analysis
done by Representative Seaton in which the 8,000 barrels a day
of increased oil production seen in Cook Inlet in the last few
years is divided among the $400 million that the state spent on
credits last year. Obviously, he noted, that does not provide
the benefit with the gas. As large as this number is, it is not
outrageous because the numbers are real - the state did spend
$400 million. As far as dividing costs between oil and gas,
that is always complicated. In 2010 a decoupling bill spent a
lot of time before this committee and one issue was how to
adequately separate costs between oil and gas. The BlueCrest
Energy, Inc., ("BlueCrest") project might be easier than most
just because BlueCrest has a very different and distinct
drilling location for its oil project versus its gas project -
the resources themselves are in the same part of the earth but
are vertically above each other; however, that is more the
exception than the rule. He deferred to Mr. Dan Stickel to
speak to DOR's ability to separate oil and gas expenditures.
6:47:15 PM
DAN STICKEL, Assistant Chief Economist, Tax Division, Department
of Revenue (DOR), offered his understanding that currently if a
unit within Cook Inlet produced both oil and gas, those
commingled costs would be separated based on the gross value at
the point of production of the oil versus the gas. If 60
percent of the value came from oil, then 60 percent of the costs
would be attributed to the oil. Before calculating the tax, the
zero tax ceiling for oil would be applied along with the 17.7
cents per Mcf ceiling for gas.
REPRESENTATIVE SEATON posed a scenario of a new field with all
the investments and earned credits up front, and with production
coming later that varies in how much gas and how much oil. He
asked whether DOR, if working on that kind of a scheme, would go
back and recover some credits from the company if it had more
gas than oil if credits were not being given for gas since the
price is adequate to support gas development. He said he cannot
recall the conversation from when decoupling was discussed.
MR. ALPER offered his belief that the decoupling bill ended up
with a formula tied to gross value at the point of production.
He said it is in-artful and in-exact, but it would be possible
to a certain extent to do a more comprehensive separation
although it would be a workload within the department. He said
he thinks the question that Representative Seaton is really
asking is, "Could we establish a different level of credit
support for oil versus gas?" He said he thinks that could be
done but he needs to check with a few people about what the
hurdles and pitfalls might be because the ultimate desire of the
Cook Inlet Recovery Act was to get a big benefit to make sure
people found enough gas to keep the lights on. However, he
reported, an analysis done by DOR found that about one-third of
that money got spent on oil that might not have been necessary
to get the oil developed because the oil had a more stable
market and was not as much of a life or death situation. If it
is wanted to do two different things for oil versus gas, he said
DOR would have to look at how to implement it but he believes it
could be done.
6:50:13 PM
REPRESENTATIVE OLSON remarked that he thinks oil is an issue in
parts of Cook Inlet, particularly to Tesoro who used to get all
its oil in Cook Inlet but is now bringing it around from Valdez
or elsewhere because there is not an adequate supply.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| 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 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 |
| 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 |
| 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 - 2.24.16 HB 247 2nd Presentation- fiscal details part 1a.pdf |
HRES 2/25/2016 8:30:00 AM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |
| 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 |