Legislature(2017 - 2018)HOUSE FINANCE 519
03/21/2017 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB111 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 111 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE BILL NO. 111
"An Act relating to the oil and gas production tax,
tax payments, and credits; relating to interest
applicable to delinquent oil and gas production tax;
and providing for an effective date."
1:38:38 PM
KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE,
turned to slide 13 of the PowerPoint presentation: "Oil and
Gas Production Tax and Credits: Background and Bill
Analysis." The slide discussed the background on Alaska's
oil and gas taxes and analysis of CSHB 111(RES).
Mr. Alper moved to slide 14. He explained that the
exploration credit went back to 2003, and was intended to
give a benefit against taxes of some percentage of spending
on desired exploration activities. There was also the
capital expenditure credit, which was part of the Petroleum
Production Tax (PPT) bill. The capital credit was expanded
in 2010 and created a 40 percent credit called the "well
lease expenditure (WLE)." The North Slope credit was
repealed with SB 21 [oil and gas tax legislation passed in
2013] in the previous legislature. House Bill 247[oil and
gas tax legislation, 29th Legislature] eliminated the
capital credit in two stages, to be repealed in the
following year. In Middle Earth there would be a small
credit remaining into the future. The main credit that what
was discussed the most was the Net Operating Loss (NOL)
credit, which paid for a percentage of a company's losses.
That type of credit was "stackable" with exploration and
capital credits. This lead to up to 85 percent state
participation in company expenditures for about a two-year
period.
1:42:30 PM
Representative Guttenberg wondered about stackable credits
and how prevalent they were in the world.
Mr. Alper responded that the whole idea of cashable credits
was quite unique to Alaska. He did not know whether they
existed in other jurisdictions.
1:43:52 PM
Co-Chair Seaton acknowledged Representative Ortiz and
Representative Tilton at the table.
Vice-Chair Gara asked whether Mr. Alper knew of another
jurisdiction that pays for a portion of a company's losses.
Mr. Alper responded that it was not unusual for losses or
pre-production spending, also considered losses, to be
carried forward and captured once there was production and
value. There were many ways to do this, but it was the
nature of a profit system that the costs from pre-
production ended up in the taxes post-production.
Vice-Chair Gara indicated that the major producers saw a
35 percent credit for NOL and a 35 percent deduction on
their expenses, but did not pay a 35 percent tax rate. He
asked whether it was not more common to see a deduction
based on tax rate as opposed to something much larger than
the effective tax rate.
Mr. Alper pointed out the difference between the nominal
versus the effective tax rate. He suggested it would be
easier if it were just a flat tax rate. He had a slide that
provided a better NOL rate. He agreed that the system
created nuances such as those mentioned.
1:46:24 PM
Mr. Alper scrolled to slide 15. He spoke about some of the
different tax credits. The small producer credit went back
to the beginning of PPT. It was designed to make the first
amount of a company's profits effectively tax-free if it
fell beneath a certain production threshold which worked
out to be the first $12 million of tax liability for the
first nine years of production. In order to qualify, small
producers had to have first production by May 2016. There
would be a gradual phase out of small producer credits over
the subsequent nine years. The per-taxable barrel credit
had been the foundational credit for the SB 21
calculation. He mentioned the sliding scale for legacy oil.
The new oil would receive the $5 flat rate credit. Other
credits were essentially cash, and were not really
considered production tax credits, but were against the
state's corporate income tax.
Mr. Alper discussed credits against corporate income taxes.
In 2007, the state began to buy back the credits at face
value from the companies. He explained the rationale behind
the choice. The state created a tax credit fund and created
certain rules for buyback. One of the rules governing this
was that the company had to produce less than 50,000
barrels per day in order to be eligible for cash. The
larger companies would have to carry their credits forward
to the following year. Exxon, ConocoPhillips, and BP, as
well as Hilcorp as of 2015, all fit this category.
1:50:10 PM
Representative Wilson asked if it made a difference whether
a company wrote off the loss in its taxes or if the state
paid a check to the company.
Mr. Alper answered that there was no real difference. He
pointed to a big table in the Revenue Sources Book, Table
8-4, which broke out cash credits, credits subtracted
against liability, North Slope/non-North Slope, with a lot
of detail. The main difference was time. If the company was
set to receive cash, they would receive it the following
year, whereas if the credit was used against the company's
own taxes, they may receive it five or seven years later.
Representative Wilson asked if those were the same credits
that a company could take to a bank as collateral.
Mr. Alper responded that there had been a provision added
in 2013 that enabled a company to assign the rights to its
credit cash to a bank. For the state, that meant that it
was paying directly to the bank, which allowed for some
bankruptcy protection to the bank. Much of the lending for
small oil companies was venture capital, high-risk money.
What began to occur was companies would borrow an extra $50
million in year 1. They had the same startup money from
venture capitalists and would bank on that credit to pay
the second lender back. The banks that were making the
short-term loans were left hanging with the lack of credit
cash.
Representative Wilson asked if the credit system increased
oil production.
Mr. Alper responded that he did not want to speculate on
increased production, but that it certainly had accelerated
spending.
1:53:07 PM
Mr. Alper moved to slide 16 on the history of oil and gas
production tax credits.
FY 2007 thru 2016, $8.0 Billion in Credits
North Slope
· $4.4 billion credits against tax liability
Major producers; mostly 20% capital credit in
ACES and per-taxable-barrel credit in SB21
· $2.3 billion repurchased credits
New producers and explorers developing new fields
Non-North Slope (Cook Inlet & Middle Earth)
· $0.1 billion credits against tax liability
Another $500 to $800 million Cook Inlet tax
reductions (through 2013) due to the tax cap still
tied to ELF
· $1.2 billion repurchased credits (most since
2013)
Mr. Alper elaborated that $8 billion was offered in credits
in the first 10 years of the program. About $4.5 billion of
that was not an expenditure by the state, but an offset to
taxes and a reduction in revenue received. This occurred
mostly in the North Slope, and almost entirely via either
the per-barrel credit in SB 21 or the old 20 percent
capital credit from ACES. If a major producer spent $600
million, and earned 20 percent capital credit, they would
be subtracting $120 million from that year's taxes. The
other $3.5 billion were cash credits.
1:54:28 PM
Vice-Chair Gara asked if the state still allowed companies
to sell their credits to other companies at a discount.
Mr. Alper explained that the credits could be sold to
another company and that the company had to inform the
state of the activity, but it was not required to specify
how much it received. The private market for secondhand tax
credit was an unknown, private negotiation.
Vice-Chair Gara provided an example of the state buying
back credits from BP for the full amount. He asked whether
it had been proposed that the state participate at the same
level, buying them at a discount.
Mr. Alper responded that he did not know whether that had
been proposed, but the Senate added language to HB 247 in
the previous year which said that a company could get up to
$70 million in a given year. The first $35 million had to
be paid at face value. If it wanted more, the company would
have to accept a 25 percent haircut. The most any company
could get would be $61.25 million to purchase $70 million
worth of credits. There had never been a discussion to buy
the credits at a discount.
1:56:51 PM
Representative Pruitt spoke to the credits against tax
liability. He asked whether when Mr. Alper meant the $8,
$7, $5 when referring the per-taxable barrel credit in SB
21..
Mr. Alper replied in the affirmative.
Representative Pruitt asked how much of the $4.4 billion
was associated with that particular credit.
Mr Alper replied that the credit became effective in
January 2014, with the effective date of SB 21. In the
first 18 months or so, it was around half a billion
dollars. It had been a much smaller number since prices had
fallen, to where most North Slope production was well under
the minimum tax threshold. He noted that a later slide
would show that the numbers quickly went to $8 [slide 47]
then dropped rapidly at prices under $70 and companies
bumped up against minimum tax.
1:58:06 PM
Representative Pruitt was trying to recall the discussion
around SB 21. He recalled that there had been concern that
the state was moving away from the progressive tax in
Alaska's Clear and Equitable Share (ACES). He wondered if
the state should be grouping the tax with other credits. It
was an integral part of that particular tax.
Mr. Alper remarked that the answer to the representative's
previous question was $1.2 billion. He stated that it was a
credit, it was called a credit in statute, it needed to get
accounted for when credits were accounted for, and it was
used to offset taxes. He agreed it was an integral part of
the SB 21-based tax system. The change had been made for
reasons of progressivity. The original bill presented by
Governor Parnell had been a 25 percent flat tax, without
progressivity or per-barrel credits. The problem with that
was that, when layered with royalty, which was slightly
regressive, it lead to an overall regressive tax regime.
The goal of the then legislature had been to have a
relatively flat total government take curve. That changed
from $25 with no credit to $35 with a $5 credit, and was
roughly revenue neutral at $100 per barrel oil. It wasn't
viewed as a tax increase, only an increase in the tax rate,
with a credit benefit that roughly equaled each other out.
Suddenly, it added $800 million a year in credit liability
to the state, even though it was revenue-neutral.
2:00:47 PM
Vice-Chair Gara reported that the 35 percent credit was
called a 35 percent tax - he strongly disagreed. When the
so-called credit, which was really a price-sensitive tax
reduction, takes place, at $80 per barrel the state
received 15 percent profits tax. He stated it was not
really a 35 percent tax.
Mr. Alper stated that the bill introduced in 2013 had a
flat 25 percent tax. Had that structure survived, it would
be a 25 percent tax at all prices. By throwing in the
subtractive feature, nominally the state received above 25
percent at certain prices, but for the last three years
those prices were quite a bit lower than that.
2:02:17 PM
Mr. Alper explained slide 17.
Providing some detail out of confidential data:
Of the nearly $3.5 billion in state-repurchased
credits through the end of FY16:
· $1.5 billion went to eight North Slope projects
that now have production
· $0.8 billion went to 11 North Slope projects that
do not yet have any production. Some of these are
abandoned, and some are in process
· $0.9 million went to eight non-North Slope
projects that have production
· $0.3 million went to eight non-North Slope
projects that do not yet have any production
Mr. Alper remarked that the data was all confidential, but
that of the $3.5 billion in state-repurchased credits,
about $1.5 billion went to 8 companies on the North Slope
that were currently in production. Another roughly $0.8
billion went to 11 North Slope projects that did not yet
have production. $0.9 million went to 8 non-North Slope
projects that had production, and about $0.3 million went
to 8 non-North Slope projects that did not yet have
production.
Mr. Alper continued to slide 18.
North Slope Repurchased Credits
· Between FY07-FY16 spent $1.5 billion supporting
eight producing projects
· Total production from these producers through end
of 2015 is 63 million barrels
· Total credits = $24 / barrel
o Doesn't include payments to non-producing
projects
o This number will decrease over time due to
additional production from these fields
· Lease expenditures for these projects, through
FY15, were $6.0 billion
o Credit support was 25% of lease expenditures
Mr. Alper elaborated on slide 18. Narrowing down to North
Slope credits that went to companies in production, through
the end of calendar year 2015, that came to 63 million
barrels of oil produced. The state's investment was about
$24 per barrel. The total credit support for lease
expenditures was 25 percent.
2:04:24 PM
Representative Wilson asked how much money the state
received through royalty, oil, and other taxes up to FY 16.
Mr. Alper explained that $61 billion was the total oil and
gas revenue.
Representative Wilson surmised that the state had paid out
$3.5 billion for the $61 billion that it received.
Mr. Alper suggested it was important to recognize that the
great bulk of that revenue came from older assets that were
producing long before the state began buying tax credits.
He agreed that a relatively small amount had gone to tax
credits in the early years. It was becoming a larger
percentage as prices declined.
2:07:06 PM
Representative Wilson disagreed, stating that some of the
repurchasing was owed for what had been previously
received.
Mr. Alper responded that the numbers represented in the
slides were paid in full. The issue of unpaid tax credits
was limited to FY 17 and beyond.
Representative Wilson asked whether there was not a way to
say that credits coming forward had nothing to do with
projects that came online that provided benefit to the
state.
Mr. Alper remarked that the slide attempted to identify
projects that were specifically tied to the credits
received.
Representative Wilson stated that a lot of the credits that
were written off had to do with production already
received, as there were not a lot of new projects going
forward. She wanted to ensure that it was not the case that
the state was not getting its money's worth from 2017.
Mr. Alper gave the example of a project for which a company
received $100 million in credits over time, with 5 million
barrels of production in a few years. Simple division would
say that the state had invested $20 per barrel. Three years
on, that company could be up to 10 million barrels, from
those same wells, and not earning more credits as they were
not drilling more. At that point the $20 per barrel figure
drops to a $10 per barrel figure, as all the old credits
would be divided among more barrels.
2:08:32 PM
Representative Guttenberg reiterated that the state had
paid $1.5 billion on eight producing projects, for a total
of 63 million barrels. He asked how many of the barrels
were in production before the credits came online. A lot of
the projects were already in place pre-SB 21, which changed
the economics. People applauded all of the things that
happened with SB 21, but many of those were already in
place. He asked Mr. Alper to extrapolate how much of the
$63 million was a result of those credits.
Mr. Alper responded that there were inevitably decisions
that had to be made when putting together the data set he
was presenting. The projects which were already in the
pipeline before SB 21 were not included, however Economic
Limit Factor (ELF) projects were included in the 63 million
barrels.
Representative Guttenberg concluded that it was really
difficult to understand the results of the credits outside
the boardroom
Mr. Alper explained that he attempted to get as much
information to the decision-makers as he could within the
current laws regarding confidentiality.
2:11:08 PM
Mr. Alper spoke to slide 19. He highlighted that the slide
showed the production tax received by year since FY 07. The
first bar showed calculated tax, or the tax rate. The
middle bar showed the amount of revenue actually received
by the state. The darker red bar was the net income to the
state after cash credits have been paid. The system had
developed in a time in which the state was receiving $2
billion to $6 billion a year. Investing in the future of
Alaska made a certain fiscal and long-term strategic sense.
Then the price fell and the credits remained similar in
scope. Suddenly, the revenue was offset by the credits. In
FY 15 and FY 16, the amount of credits paid was more than
the revenue coming in. All of the liability for FY 17
rolled forward and would become FY 18 liability, shown in
the negative red bar in the slide. The forecast showed a
small number.
Mr. Alper turned to slide 20 which showed the same data set
but with unrestricted petroleum revenue. The only thing not
shown was royalties going into the Permanent Fund. High
numbers get higher, but the amount of total revenue is more
dramatically impacted by having a several hundred million
dollar credit system.
2:13:59 PM
Vice-Chair Gara asked Mr. Alper to return to slide 19. He
asked whether, with all owed credits paid, there would be a
net zero in 2019.
Mr. Alper responded that he would have to examine the
numbers but that to the naked eye it looked like a fairly
low number.
Representative Wilson wondered why the state would not add
all of the royalties into the chart, as the state still
receives them.
Mr. Alper answered that the chart was made at the beginning
of the process. The unrestricted royalties could be added.
Representative Wilson believed that including all
royalties made the graph transparent and easier for
constituents to understand.
Mr. Alper indicated that it was a robustly edited graph,
with requests from committees over the last year. He would
be more than happy to add another layer.
Representative Pruitt asked if Mr. Alper recalled that the
throughput forecast for 2026 was around 309,000 barrels per
day.
Mr. Alper agreed that it was in the 300,000 to 350,000
range. At the beginning of the chart, it was around 700,000
per day of throughput in 2007 and 2008.
Mr. Alper turned to slide 21. He spoke to the unpaid
balance:
· FY2009-2015 Legislature used "open ended"
appropriation language. All credit certificates
presented were purchased
· FY16 Appropriation Capped at $500 million
o $498 million paid out by end of June
o About $211 million North Slope, $287 million non-
NS
· FY17 Governor proposes $1 billion to clear credit
liability as part of reform package and full fiscal
plan
o Legislature appropriated $460 million towards
expected demand of $775 million
o Governor vetoed all but $30 million (formula
calc.)
o Funds were paid first in-first out; most went to
Cook Inlet capital and well lease expenditure
claims
Mr. Alper expounded that the amount presented for
repurchase estimated to be $400 million was appropriated
from the General Fund to the tax credit fund. He stated
that the most that was ever spent in a given year was $628
million. For FY 16, the governor struck out the open-ended
language and replaced it with $500 million. It turned out
to be $498.5 million, so the appropriation was spent. A
little over 40 percent was North Slope, and the rest non-
North Slope, meaning half of the credits were Middle Earth
and Cook Inlet credits. He reported that Representative
Geran Tarr had mentioned the governor's complete fiscal
package introduced in the previous legislative session
including a one-time $1 billion appropriation to put money
into the tax credit fund. This was envisioned as an overall
solution that would eliminate most of the credits into the
future and fix the existing problem. The package had not
passed and what was eventually appropriated by the
legislature was $460 million. He did not know the origin of
the amount. At the time the estimated demand had been $775
million, so this was underfunded. The governor vetoed $460
million down to $30 million, based on a formula
calculation. The formula was a statutory guideline.
2:19:19 PM
Mr. Alper continued to address slide 21 showing the
$30 million had been spent and most of the money had gone
to Cook Inlet earlier claims. He moved to slide 22 and
shared that the Tax Division had issued about $600 million
in certificates in FY 17; about $100 million had either
been paid or transferred.
· $600 million in certificates have been issued in
FY17
Of these, about $100 million have either been:
o Paid (from the roughly $30 million available
funds);
o Transferred (to be used against another company's
tax liability); or
o Are ineligible for repurchase
· Total remaining awaiting repurchase ~$500 million
· Applications in-hand about $200 million
o $50 million "023" credits (NOL and Cook Inlet
drilling)
o $150 million "025" credits (Exploration; have
sunset)
· So total known demand is roughly $700 million
· Additional ~$400 million forecasted for FY18
Mr. Alper specified that the current amount awaiting
repurchase was $500 million. About $200 million was in-hand
applications, about $50 million in NOL and Cook Inlet
drilling, and $150 million in the exploration credits had
sunset. The division was currently working through a very
large last slug of the exploration credits. The division
knew about $700 million and anticipated another
$400 million in FY 18. That meant $1.1 billion in
liability, minus appropriations and current credits
changing hands, leaving a hanging balance of $900 million.
2:21:53 PM
Representative Pruitt asked what kind of credits
represented the $400 million forecast in FY 18.
Mr. Alper answered they were mostly NOLs and Cook Inlet
capital and WLE credits. All of the 2016 NOLs would come in
roughly March 31 [2017].
Representative Pruitt suggested the NOLs were not cashable.
He was trying to understand the partial payment.
Ultimately, he wondered how much would have to be cashed
out.
Mr. Alper responded that they were cashable. The current
number was more like $500 million.
Mr. Alper turned to slide 23. He explained that the
greybars represented what the statutory formula would
appropriate in a given year, expected to be $50 million to
$100 million. Meanwhile credits would accrue at a faster
rate. The rate of increase was shrinking due to reforms.
The graph only represented known, current projects, leading
to $1.6 billion by 2026.
Mr. Alper moved to the formula on slide 24:
Credit appropriation formula AS 43.55.028(b) and (c)
· Based on a percentage of production tax revenue
before subtracting credits that are taken against
liability)
o Forecast price below $60: 15%
o Forecast price above $60: 10%
· Was never used in previous years' budgets before
FY17
· Earlier years would have generated large
appropriations that would have exceeded the demand
for credits, "endowing" the fund
· Recent years would have spent down any past
surpluses; reducing the fund to zero by FY2016
· We'd be in the same place now- only there wouldn't
be the expectation that we'd provide unlimited
funding
Mr. Alper relayed that had the formula been followed then,
the amount appropriated would have been more than the
demand. It would have endowed a tax credit fund. Once lower
prices occurred, the unpaid credits would still be an
issue, but the difference would be that there would not be
the expectation from industry that the state would provide
unlimited funding.
2:26:24 PM
Mr. Alper advanced to slide 25, showing how the formula
worked and how it would have worked. Open-ended language
for the appropriation became more convenient and was more
for the sake of simplicity rather than policy. He explained
the differences between budgeted versus actual versus
statutory tax credit funding formula. The graph showed
credits received, actual production tax, credits against
liability, revenue due to AS 43.55.011, oil price
forecasts, credit caps per AS 43.55.028 (c) and end year
fund balances.
Representative Wilson asked whether, because the
calculation was based on ACES, when there was a change to
credits, the state should have been utilizing the formula
to ensure that funding followed the formula as well. She
wondered if the numbers would be different. She thought the
formula should be looked at every time there was a proposed
tax change.
Mr. Alper answered that had the formula been followed from
the beginning, what she had described would the case, and
the formula would have been revisited. As no one was in the
habit of using the formula, it had not been revisited. The
moment in which that would have been important was in the
era of the Cook Inlet Recovery Act. It created what lead to
a new liability of a couple of hundred million dollars per
year. Had it been built into the system, the formula may
have had to adapt.
Representative Wilson asked whether one could speculate
that, had the formula been used, and the numbers were
positive rather than negative, the state would be
revisiting the tax structure if there was not the liability
since the state had a formula that worked and that the
state followed.
Mr. Alper responded that the poster child for the tax
credits were the companies wanting to explore areas that
were too marginal for the major producers - the 50 million
to 10 to 20 thousand barrel per day fields. What happened
was a handful of rather large, unexpected discoveries. If
the current system applied to those projects going forward,
that would mean billions of dollars in credit liabilities
which the state simply did not have the resources to pay
for. The system would need to be revisited anyway.
Representative Wilson explained that most of the time North
Slope and Cook Inlet were thrown together, when one of them
was subsidized. She wondered if Cook Inlet were taken out,
leaving only North Slope, what the number would look like.
Mr. Alper stated that the department would look at the
assumption that Cook Inlet had its own revenue-neutral
funding source, and what the endowed fund would have looked
like with only the North Slope credits.
Representative Wilson asked in the department to include
interest in the data it was compiling.
Mr. Alper replied that the department would put the
information together.
Co-Chair Foster recognized the presence of House Resources
Co-Chair Representative Geran Tarr.
2:32:25 PM
Vice-Chair Gara asked for verification that the Cook Inlet
credits disappeared in FY 19.
Mr. Alper responded that Cook Inlet credits would disappear
completely in calendar year 2018. The last credits from
calendar 2017 would be paid in FY 19, so they would
disappear completely in FY 20.
Vice-Chair Gara asked to return to slide 19. With no new
Cook Inlet credits in FY 19 and FY 20, the graph showed
North Slope credits deducted from production taxes, close
to zero.
Mr. Alper responded that in the 2020s, the forecast price
of oil was creeping up, but still in the range of receiving
the minimum tax. At very low prices, very little per-barrel
credit could be used. Once oil prices reached the $60 to
$70 range, there was still a minimum tax but all $8 was
being used. He noted that cash credits (represented by the
gap between the second bar and the red bar on slide 19),
were using up about half of the remaining revenue.
Vice-Chair Gara referred to the large fields as non-GVR
fields. The GVR fields were new fields and post-2002
fields. The fields that received credits for the first
seven years pay close to zero production tax at oil prices
up to $70 per barrel. He asked for verification that this
was true.
Mr. Alper responded that the $5 per barrel credit for new
oil was not held to the minimum tax so it would pay zero.
Vice-Chair Gara reported the state was getting a zero
percent production tax until oil prices reached $70 per
barrel. He asked for committee discussion on the zero
revenue for no production, when some of those were projects
that were already moving ahead.
Mr. Alper replied that there were many things the bill did.
He remarked that the legislation was substantial. It shrunk
the size of effective NOL credits, it abandoned cash
payments for them, and it hardened the minimum tax.
Specific provisions in the legislation addressed the issues
in the status quo.
2:37:04 PM
Mr. Alper returned to slide 25. He posited what would
happen to a company that had $900 million in credits. The
credits were not considered debt and did not incur
interest. They were a tax offset document. They could be
sold or transferred to another company. There was not much
demand at present especially as even major producers have
low tax liability. The companies were not paying very much,
and it could only be used to offset 20 percent of tax. The
exploration credits were not under that restriction,
however, the last of the exploration credits would be
issued later in the year. The secondary market for credits
was not robust.
Mr. Alper moved to the topic of the major provisions and
regional impacts of HB 247 on slide 28. The final law had
been largely based on the Senate's version of HB 247.
Cook Inlet
· Complete phase-out of NOL, QCE, and WLE by 2018
· Extends "tax caps" on gas indefinitely, adds $1/
bbl oil tax
· Municipal utility pro-ration of costs
Middle Earth
· Reduces the NOL, QCE, and WLE credit rates
· Extends "Frontier Basin" exploration credit to
July 2017
North Slope
· GVR "Graduation" provision after three to seven
years
· GVR can't be used to increase the amount of an
NOL
Statewide
· $70 million per company per year cap ($61 with
"haircut")
· Interest rates increased for 3 years, then drops
to zero
· Transparency, local hire, state obligation
offsets, surety bond
2:43:17 PM
Co-Chair Seaton referred to the qualified capital
expenditure (QCE) credit, which had been extended past a
July 1 date in the Senate version of the bill. He asked if
the particular credit could be used for Hilcorp's flow out
gasline in Cook Inlet.
Mr. Alper responded that the QCE credit had been reduced
from 20 percent to 10 percent for 2017. Middle Earth would
continue on and Cook Inlet would go to zero. If capital
work was to be carried out in 2017, the company could apply
for the credit. He did not know about specific restrictions
for repairs. There was specific language in statute that
covered restrictions.
2:44:18 PM
Vice-Chair Gara asked Mr. Alper to explain the effective
tax rate on oil produced in Cook Inlet.
Mr. Alper relayed that the Cook Inlet oil and gas paid the
lowest tax under ELF. The smaller fields paid the lowest
tax. He detailed that PPT locked ELF multipliers from 2005
into place for all oil and gas fields in Cook Inlet through
2022. On the gas side the average gas production was taxed
at 17 cents per 1,000 cubic feet, and all oil was taxed at
zero. In HB 247, the 17 cent tax was extended in
perpetuity, and it would no longer sunset. On the oil side
the zero was seen as unsustainable; therefore, the Senate
placed the $1 tax in HB 247. There were about 5 million
barrels of oil produced in Cook Inlet, so the result was $5
million.
2:46:55 PM
Vice-Chair Gara asked if there was a way of converting to
terms of gross or profits tax that were more commonly used.
Mr. Alper said that he did not know the actual costs of
producing oil in Cook Inlet. The tax cap in place made it
less important for tax calculation. He reported that all of
the oil produced in Cook Inlet was sold to local
refineries, not to the global market, and did not have the
same shipping costs associated with it. It would be easy to
describe it as a gross tax. He did not think there was
enough information to convert it to a net tax.
Vice-Chair Gara stated that oil was a global commodity so
the price was the same regardless. Taxing oil by a dollar
would not make the cost for oil higher.
Mr. Alper agreed. For the sake of simplicity, one could
assume that that oil was being sold for $50, which was
about what a barrel of oil was worth. He specified that a
$1 production tax was about 2 percent of the gross.
2:48:56 PM
Co-Chair Seaton asked Mr. Alper to provide a comparison
which would help to determine an appropriate tax for Cook
Inlet, considering that it did not incur the same expenses
as North Slope oil.
Mr. Alper complied and suggested that if the market price
was $50, the gross tax from the North Slope was 4 percent
of $40 and the dollar tax in Cook Inlet was 2 percent of
$50, it could be determined what tax would be comparable
for the Cook Inlet.
Co-Chair Seaton asked about the gross value reduction of 20
percent. He asked whether the extra 10 percent used to
lower the royalties was still on the books.
Mr. Alper thought Co-Chair Seaton was referring to the late
addition to SB 21, which created the gross value reduction.
It was a 20 percent benefit for "new oil," and a new layer
was added. If all leases on a given field are greater than
12.5 percent then the company would receive a 30 percent
benefit. This was characterized as a payback for high state
royalties. He underlined that this only regarded state
royalties.
2:51:53 PM
Representative Pruitt asked where the oil would come from
if the refineries did not purchase the Cook Inlet oil. Mr.
Alper thought it would come from the North Slope or
somewhere else in the world.
Representative Pruitt asked if the cost for a similar
product from somewhere else would include delivery.Mr.
Alper thought that all oil contracts were different, but
believed that there would be a higher price due to
delivery.
Representative Pruitt indicated that the market cost of $50
for oil, for example from the Middle East, would have an
added cost for delivery.Mr. Alper mentioned that the
contracts were private, but that he assumed that closer oil
would be attractive due to this lesser cost for delivery.
Representative Pruitt asked whether a state increase to
Cook Inlet oil tax would increase the costs to customers.
Mr. Alper thought it was reasonable to assume that
companies would pass those costs on. It would be another
cost to the refineries. He underlined that there was no
change to Cook Inlet tax in the legislation.
Mr. Alper continued with slide 29 regarding concerns over
tax and credit system:
· Hybrid system with a net tax above $75, a gross
tax between $45 and $75, and a net tax (via the
NOL credit) below $45
· Possible multi-billion dollar future liability
for large new discoveries
· Possible ability to use carried forward operating
loss credits to zero out all taxes ("hardening
the floor")
· Equity between major producers and new explorers
if major changes made to operating loss credits
· High per barrel credit keeps us in the 4%
"minimum tax" at up to nearly $80 oil
Representative Wilson asked if the same effect occurred due
to constant changes to the tax structure.
Mr. Alper was unaware of how oil companies factor in
changes in Alaska oil tax. He thought that the current
structure was unstable. The potential credit liability was
larger than the anticipated revenue. Regardless of what
action was taken, the state still would not have the means
to pay $1 billion per year in tax credits going forward.
Companies needed to know how the state would resolve that
issue before they could commit to producing that oil.
2:59:24 PM
Representative Wilson remarked that Alaska was the unstable
entity. The projects are long-term, and the changes to the
tax system were yearly. She asked Mr. Alper whether he was
confident that the proposed legislation would ensure the
tax structure could stay in place for at least three years,
resulting in more oil in the pipeline.
Mr. Alper replied that he could not promise anything, but
noted the importance of resolving the credit issue in a
stable manner. He did not think the current bill before the
committee would address the issue of tax. He thought issues
of oil tax would continue to come up inevitably, but the
issue of oil credits needed to be addressed in the current
year.
3:01:47 PM
Representative Pruitt asked which credits Mr. Alper thought
should change.
Mr. Alper answered that NOLs in current law were not
affordable as cash. If the policy were to be that the state
would not buy credits, then it should be put into statute.
He would address the sectional of the bill in later slides.
The overarching change in the legislation was getting the
state out of the business of paying cash for NOLs.
Representative Pruitt asked if the oil companies felt
similarly about the issue and whether the state could
expect a similar conversation with them.
Mr. Alper suggested that no company would gladly give up a
benefit, however no one was proposing taking away the
$900 million in credits. Going forward, the state needed to
know what the companies need to move ahead with projects,
with the understanding that the State of Alaska was getting
out of the cash business.
Representative Pruitt stated that the companies make plans
years into the future. He wondered if they would come to
the state to indicate that losing that benefit would affect
those plans.
Mr. Alper said that the oil companies had paid 90 percent
of state government in the past. When the state needed
money, it would previously go to oil companies rather than
a cigarette tax which would have raised $25 million.
Suddenly a substantial percentage of the GF was coming out
of invested assets. In all likelihood, it would take some
of the pressure off future legislatures because expectation
and demand would be lowered.
3:07:28 PM
Vice-Chair Gara asked about the page 2 in Mr. Alper's
response to Vice-Chair Gara dated February 6, 2017 (copy on
file), regarding the effective tax rates on GVR and non-GVR
oil at various prices. He asked for verification that there
was an approximate tax of 4 percent from non-GVR fields
(i.e. Prudhoe Bay and older fields) at prices slightly
above $70 per barrel.
Mr. Alper replied that the statement was mostly accurate,
but noted things varied from producer to producer. He added
that the minimum tax governed to around $70 or so.
Vice-Chair Gara referred to new oil (i.e. Nakaitchuq,
Oooguruk, Point Thomson, and other post-2003 oil). He
stated that for the GVR oil the state did not receive the 4
percent tax up to oil prices at about $70 per barrel. He
stated that according to Mr. Alper's report, the average
North Slope GVR field did not pay the 4 percent minimum tax
and paid no taxes up to prices of about $70 per barrel for
the first seven years.
Mr. Alper replied in the affirmative related to production
tax. He detailed that there was no hard floor on new oil.
There tended to be zero tax at low prices.
Vice-Chair Gara stated that one of his biggest concerns was
related to what he termed the "zero percent and four
percent tax problem" the state would live with until oil
prices exceeded the current price by 25 to 40 percent. He
suggested that if the state were to have the audacity to
raise those taxes, for every $1 increase the company only
paid about $0.60.
Mr. Alper thought the net $0.60 was fairly accurate.
Co-Chair Foster indicated that the committee would have to
adjourn in about 20 minutes.
Mr. Alper stated that the next few slides would prove
important as they contained graphs which illustrated the
legislation.
Co-Chair Foster asked Mr. Alper to proceed with the
sectional analysis.
Mr. Alper advanced to slide 31. He spoke to the impact on
interest rates in Section 2:
Interest rates were amended in HB247
· DOR expressed concern when Senate Finance CS
introduced the "zero interest after 3-year"
provision
· Makes it very hard to settle tax disputes
· Sought to get it removed in Conference Committee
· Proposed removing it in HB 5005(July session)
· Currently, doesn't impact any actual interest
calculation until 2020 so can be retroactive to
1/1/17
Concern with language: HB247 separated the Oil and Gas
Production Tax interest rate from all other taxes for
the first time. HB111 does not fix this. We would
prefer all taxes to use the same interest.
Mr. Alper elaborated that the problem with interest going
to zero after three years was that there was no incentive
to settle. This bill could go through the court system
while earning the time-value of money in appeal. He thought
the interest rate should stay the same. He did not think
there should be a zero interest rate. No one would be
paying zero until 2020, so it could be made retroactive to
2017.
3:15:05 PM
Mr. Alper continued to address slide 31 and pointed out
that HB 247 had separated the production tax from
everything else. If the legislation was going to address
interest rates, the administration requested that the
interest rate be the same for all taxes. He moved to slide
32 and addressed Sections 3 through 4 of the legislation:
Information about credits made public
· These sections were originally introduced as HB99
· Expands provision from HB247 requiring annual DOR
report of who received tax credits and the amount
· Adds to the report how much in tax credit
certificates is issued, as well as
o A description of each company's
expenditures;
o The purpose of the expenditure; and
o The lease or property on which it's
located
Concern with language: As this bill mostly eliminates
"credits," to meet the intent of the original bill it
may be necessary to redraft Sec. 4 to report "lease
expenditures. Also, Sec. 22 is redundant with the
other report requirement in Sec. 4
Representative Pruitt shared Mr. Alper's concern. He felt
it represented a huge change. He understood the
conversation about transparency, but he wondered if there
were Securities Exchange Commission (SEC) violations that
could occur related to lease expenditures.
3:18:59 PM
Mr. Alper replied that the point was valid and he was not
necessarily suggesting that comprehensive expenditures were
released. Since it was converted to a carry forward lease
expenditure, if the same information was desired, the
drafted sections would not obtain that goal. He noted that
Rich Ruggiero [oil and gas consultant hired by the
legislature in 2017] knew more about the nature of
transparency and what was legally required.
3:20:23 PM
Mr. Alper continued to slide 33 related to Section 5 on
executive sessions:
Provides authority for DOR to share certain
confidential taxpayer information with legislators
· As written, legislators would have access to
the same information as our audit
employees
· Section requires developing a substantial
confidentiality agreement to be signed by
legislators
· Some administrative costs and possible taxpayer
concerns
· Would likely engage IRS rules including
background checks, chain of custody, information
retention, etc.
Concern with language: Also may need to change
reference from "credits" to "lease expenditures"
Mr. Alper thought this would involve creating a very robust
confidentiality system. He relayed that when an employee
leaves the tax division, all other employees must be
informed so that no information is thereafter shared.
3:21:34 PM
Representative Wilson asked about the liability. She
wondered if the liability would rest on the legislator or
on the state.
Mr. Alper imagined the state could be held accountable for
negligence. The IRS [Internal Revenue Service] could cut
off access to certain taxpayer data if they deemed it
necessary. The Tax Division was under additional scrutiny.
Representative Wilson wondered about information being
taken with pictures on a smartphone. She wanted to be able
to provide information to her constituents but wanted to be
certain that there was no risk of liability.
3:24:05 PM
Mr. Alper moved to the subject of a minimum tax on slide
34:
The minimum tax is an "alternative" calculation
· The taxpayer calculates their net-profits tax,
which is 35% of "production tax value" less the
sliding scale per barrel credit
· In parallel, they calculate the "gross minimum
tax", which is 4% of gross (wellhead) value when
oil prices are above $25 / bbl
· Actual tax due is the 'higher of' the two
calculations
· Typical "crossover" occurs at about $70-$75 oil
· Amendment raises this minimum tax from 4% to 5%
when the oil price is above $50
·
Mr. Alper expounded that the amendment changing Section 6
would change the tax from 4 percent to 5 percent when the
price of oil was above $50 per barrel.
Mr. Alper referred to the graph on slide 35. He reported
that revenue to the state at various price points was
illustrated by blue, orange and grey lines. He pointed to
the grey line indicating zero minimum tax. Starting at $50
there would be additional revenue. The graph on slide 36
represented the change due to a 1 percent tax increase. At
just over $50 a barrel, the increase represented $60
million, at $70 per barrel, $85 million. A 1 percent
increase, from 4 percent to 5 percent, actually represented
a 25 percent increase.
3:26:19 PM
Mr. Alper moved to the subject of hardening the floor on
slide 37. He explained that the sliding scale per barrel
credit was statutorily hardened to the floor. Many of the
other credits could go below the floor, potentially to
zero. There were six different sections due to changes in
the language regarding a series of different credits.
3:27:29 PM
Mr. Alper discussed the meaning of hardening the floor. He
indicated that regulations say that if the sliding scale
credit was used, no other credit could go below the floor.
The legislation aimed to avoid all other credits going
below the floor. The near-term impact at low prices was
about $20 [million]. In the fiscal note there was an amount
of $20 million. He explained that the fiscal note contained
a spreadsheet in which each line represented a different
change in the bill, each with its own cost. The sum total
of the fiscal note was $20 million in short-term revenue.
3:29:00 PM
Representative Wilson asked if the four credits, because
they could not go beneath the floor, could be carried
forward.
Mr. Alper responded that the small producer credits and the
per barrel credit could not be carried forward. He stated
that in general, credits under AS 43.55.024 fell under the
"use it or lose it" category; however, credits under AS
43.55.023 and 43.55.025 could be carried forward into
future years (i.e. NOLs and exploration credits).
Co-Chair Foster reviewed the agenda for the following day.
3:31:22 PM
AT EASE
3:32:16 PM
RECONVENED
Co-Chair Foster RECESSED the meeting until 9:00 a.m.,
Wednesday, March 22, 2017.
^RECESSED UNTIL 9:00 a.m. ON WEDNESDAY, MARCH 22, 2017
3:32:16 PM
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