Legislature(2015 - 2016)HOUSE FINANCE 519
04/02/2016 08:30 AM House FINANCE
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| 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 |
HOUSE FINANCE COMMITTEE
April 2, 2016
8:33 a.m.
[NOTE: Continuation of April 1, 2016 5:00 p.m. meeting]
8:33:57 AM
CALL TO ORDER
Co-Chair Thompson called the House Finance Committee
meeting to order at 8:33 a.m.
MEMBERS PRESENT
Representative Mark Neuman, Co-Chair
Representative Steve Thompson, Co-Chair
Representative Dan Saddler, Vice-Chair
Representative Bryce Edgmon
Representative Les Gara
Representative Lynn Gattis
Representative David Guttenberg
Representative Cathy Munoz
Representative Lance Pruitt
Representative Tammie Wilson
MEMBERS ABSENT
Representative Scott Kawasaki
ALSO PRESENT
Janak Mayer, Chairman and Chief Technologist, enalytica
PRESENT VIA TELECONFERENCE
Nikos Tsafos, President and Chief Analyst, enalytica
SUMMARY
HB 247 TAX;CREDITS;INTEREST;REFUNDS;O & G
HB 247 was HEARD and HELD in committee for
further consideration.
Co-Chair Thompson discussed the meeting agenda.
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."
8:34:47 AM
JANAK MAYER, CHAIRMAN AND CHIEF TECHNOLOGIST, ENALYTICA,
addressed a PowerPoint presentation titled "HB 247: Key
Issues and Assessment" dated April 1, 2016 (copy on file).
He provided a brief recap on slide 10 titled "Alaska's
Production Tax: Origins in 2006 Proposal." He explained
that if an entity had nothing other than a 25 percent net
tax rate and combined it with a 20 percent capital credit -
the core ideas that had eventually gone into Alaska's Clear
and Equitable Share (ACES) - it would curve the 25 percent
effective tax rate down (25 percent would become the
maximum rate); the 20 percent capital rate meant that the
25 percent would not ever be achieved and the line would
continue to decline to zero around $60 per barrel. He
elaborated that the capital credit was applied after the
tax was calculated and the capital credit was a fixed
amount relative to price (assuming a fixed amount of
spending) and it represented a larger portion of the
profits on a $40 per barrel of oil versus the profits on a
$100 barrel. The capital credit created a progressive
component to the curve; if there was nothing but a 25
percent rate and the capital credit it would bend the tax
rate down to zero.
8:37:05 AM
Mr. Mayer moved to slide 12 titled "ACES: Steep
Progressivity, High Spending Support." He explained that
ACES had used the basic design [outlined on slide 10] and
built in additional progressivity. He detailed that under
ACES the goal had been to enable the tax rate to keep
climbing so it would reach and exceed 25 percent. When the
production tax per barrel reached a certain point ($60 to
$80 per barrel illustrated on the slide) - below a certain
threshold the tax rate was 25 percent - but above a certain
threshold it began climbing in increments for each dollar
increase until it reached an inflection point. He stated
that for $25 to $50 in production tax value it increased at
one rate and at a slower rate above that. The change
resulted in a steady increase (yellow line on ACES chart on
slide 12). He stated that the inflection flattened out at
$140 per barrel and increased more slowly after that. He
furthered that the base rate of 25 percent could go much
higher under ACES and could also drop to zero depending on
the oil price. He discussed the reason the rate could drop
to zero. He explained that notionally statute contained a 4
percent gross minimum floor - the idea of the floor had
been to provide additional protection to the state when oil
prices were low. In reality, the 20 percent capital credit
was applied in the stack after the net versus gross
assessment. He furthered that as long as there was any
basic level of capital spending it could mean a drop below
the floor, meaning that the 4 percent gross floor was never
actually binding.
8:39:20 AM
Representative Gara reasoned that without the 20 percent
capital credit, ACES would never have dropped below the 4
percent tax floor. He remarked that it had been an
expensive proposition in ACES, which had been fixed. He
asked for verification that the 20 percent capital credit
was still allowed in Cook Inlet.
Mr. Mayer replied in the affirmative. He added that the
full suite of ACES tax credits plus additional credits were
allowed in Cook Inlet without any corresponding profits
based production tax.
Representative Gara stated that ACES had a tax rate that
rose and rose, but the 20 percent capital tax credit was
affordable. He surmised that in Cook Inlet there was no
tax, but the cap of the 20 percent capital tax credit was
allowed.
Mr. Mayer answered in the affirmative. In addition to the
20 percent capital credit there was a 40 percent credit on
well work, which was never on the North Slope gas.
8:40:14 AM
Mr. Mayer continued to address slide 12 and summarized the
debate around the ACES system. He explained that the high
progressivity meant high marginal tax rates because the
rate increased with each additional dollar increase in oil
price. He explained that the structure meant that marginal
rates were upwards around 86 percent and higher at yet-
unseen prices. It meant that in many ways from a producer's
economic perspective, the spike in oil prices that had
occurred over the past 6 or more years in some ways had
never really happened. He explained that for each $1.00
increase when 80 to 90 percent of the increase was going to
the state rather than to the producer, it looked very
different in terms of the producer's incentive for further
reinvestment than under a slightly less progressive system.
More importantly, it had also meant that there was very
high state support for spending, which varied dramatically
depending on a wide range of assumptions. For example, a
new producer without any existing liability had 45 percent
support for spending because they received a 20 percent
capital credit stacked with a 25 percent net operating loss
(NOL) credit. He explained that the 25 percent NOL credit
was effectively the same thing as the existing incumbent
writing off against their taxes. He elaborated that it
would be true if the rate was a flat 25 percent, but due to
progressivity the benefit for the incumbent producer had
varied widely; the benefit could be 25 percent plus the 20
capital credits; however, if an entity had an 80 percent
marginal tax rate plus a 20 percent capital credit, the
marginal benefit of reduced taxes on spending could reach
over 100 percent under ACES. He summarized that there could
be very high effective support for spending or significant
reduction in revenue from additional spending. As long as
spending was low and prices were high, an enormous amount
of revenue came in through the system; however, when
spending was high and prices were low, it was a major risk
to the treasury.
8:42:53 AM
Vice-Chair Saddler pointed to the two bottom lines on the
chart (slide 12) and asked what the percent gross and
percent net rows demonstrated. Mr. Mayer replied that it
continued the same format from previous slides. He detailed
that the percent net illustrated what it would look like as
an effective tax rate (green line shown on the chart). The
percent gross showed what it would represent as a
proportion of the gross value (e.g. compared to a 4 percent
gross tax).
Vice-Chair Saddler surmised that the gross was the
percentage of value in a tax and the percent net
represented the effective net tax rate. Mr. Mayer answered
in the affirmative.
Mr. Mayer turned to slide 13 titled "SB21: Protect on the
Low End, Give Back at The High End." The chart summarized
the difference between SB 21 [oil and gas tax legislation
passed by the legislature in 2013] versus ACES related to
effective tax rates. Exactly what the comparison looked
like varied slightly depending on the level of spending. He
explained that part of the point of SB 21 was to make the
overall tax rate less sensitive to changes in spending;
less overall support for spending and more predictability
in the overall system. He pointed to a chart on slide 13
and explained that at oil prices between $70 and $110 per
barrel the lines were close, but SB 21 was lower than ACES
(under the current assumptions $18 per barrel of capital
and operating expenditures in the Department of Revenue,
Revenue Sources Book for FY 16). He furthered that using
the numbers from either of the previous two years (closer
to $20) would mean the lines depicting SB 21 and ACES were
the same in the $70 to $110 price range.
Mr. Mayer considered what ACES would have netted versus SB
21 (slide 13). He detailed that when prices were around $80
to $100 and spending was in the $20 range, the numbers were
basically the same. The key difference was what happened
when oil prices were well above $100 to $110 where the tax
rate under SB 21 tapered off and reached a maximum of 35
percent. Alternatively, 25 percent was the nominal or base
rate under ACES that could go lower or substantially
higher. Under SB 21 the rate could reach a maximum of 35
percent and tapered down at prices below $150 and $160 per
barrel. He explained that in the same way as ACES had the
20 percent capital credit that bent the line down to zero,
SB 21 had the dollar per barrel credit for old production.
He directed attention to the "$/bbl credit" row and $140
per barrel column on slide 13 to demonstrate his point. He
elaborated on the "$/bbl credit" row, which started out at
$8 per barrel at the lowest prices and tapered down to zero
at the highest prices. The effect of the tapering was to
bend the curve of the effective tax rate; there was a
maximum tax rate of 35 percent at the highest prices, which
could come down much lower. He continued that if it were
not for the 4 percent gross floor, the number could
eventually drop to zero; however, that did not happen for
existing production because one of the other large changes
in SB 21 for legacy production (currently the vast bulk of
the North Slope tax base) was to make the comparison after
accounting for the dollar per barrel credit.
8:47:20 AM
Mr. Mayer continued to address slide 13. He explained that
under ACES the capital credit happened almost last in the
stack. However under SB 21, the $/bbl credit and net tax it
created were compared to the gross floor; whichever amount
was greater applied. He detailed that it meant the tax rate
would drop down to about 10 percent and would shoot back up
again quickly to reach 100 percent around the $50 per
barrel mark.
Representative Gara stated that there were a number of
older ACES fields (Oooguruk and Nikaitchuq) that received
the lower tax rate. He surmised that the definition was
complex, but that essentially post-2002 fields received the
break.
Mr. Mayer replied in the affirmative. He elaborated that
the term "new" pertaining to oil fields did not necessarily
mean new since the enactment of SB 21. He detailed that
various points in time and definitions around units
specified what qualified as a new field.
8:48:56 AM
Mr. Mayer continued to address slide 13. Under ACES there
was highly variable support for state spending (i.e. 25
percent to 100 percent), the benefit for an incumbent
producer looked very different from the benefit for a new
producer, and the level could vary widely depending on the
price of oil and the amount of spending. Alternatively,
under SB 21 the idea had been to increase predictability in
terms of the overall level of state support for spending
and that the tax rate should be brought down to 35 percent
and should apply to everyone. The goal had also been
reduced tax rates at high prices for competitiveness with a
4 percent gross floor, which would dramatically increase
the tax rate as prices dropped as an effort to protect the
state.
Representative Gara pointed to the red line representing SB
21 on slide 13. He noted that the tax rate decreased under
an $8/bbl credit. He asked for verification that the credit
had nothing to do with whether an entity invested any
money, but was a function of price.
Mr. Mayer answered in the affirmative. He explained that it
was very deliberate.
Representative Gara observed that at $76 per barrel the
profits tax was lower than the 4 percent minimum. He asked
for verification that the 4 percent minimum kicked in at
prices below $76 per barrel.
Mr. Mayer answered in the affirmative. He elaborated that
the reason for the sharp inflection point was the two
different tax systems; the inflection point - based on the
series of assumptions at hand - was where there was a
transition between the net and gross tax.
Representative Munoz asked for a restatement of the
explanation.
Mr. Mayer explained that either there was a net or gross
tax; whichever amount was greater applied. Under the
assumptions on slide 13 (it varied by cost structure), the
net tax would eventually drop to zero. He explained that
the intersection of the orange and red lines indicated the
point where the gross tax yielded more than the net tax;
therefore the gross tax applied.
Representative Munoz asked if the committee had been told
previously that the NOL could take the gross tax below the
4 percent.
Mr. Mayer answered in the affirmative. He explained that
the concept was difficult to show on a chart related to
effective tax rates. He detailed that to plot and talk
about an effective tax rate there had to be a profit to be
taxing. He noted that the lines on slide 13 stopped a
little below the $50/bbl mark because at that point it was
no longer meaningful to talk about an effective tax rate
below that point. He furthered that there were $18/bbl in
operating and capital expenditures plus $10/bbl in
transportation costs; below that point there was no
production tax value per barrel to tax. At that point an
NOL credit kicked in and could further reduce taxes. He
summarized that it was reducing taxes at a time when there
was no profit by definition and therefore an infinite tax
rate.
8:52:55 AM
Representative Gara had heard it said by some that the
crossover point where SB 21 raised more money was $110/bbl.
He pointed to slide 13 and observed that the intersection
point appeared to be closer to $70 per barrel. He asked
about the difference. He asked for verification that the
chart on slide 13 indicated that ACES started raising less
money than SB 21 at around $70/bbl.
Mr. Mayer answered that it depended entirely on the cost
assumptions used. He detailed that using the capital and
operating expenditures of FY 14 and FY 15 (instead of the
$18/bbl expenditures from the current year Revenue Sources
book) the yellow line representing ACES would be shifted up
a bit more (because ACES was more sensitive to costs) and
the red line representing SB 21 would be the same at prices
between $75 to $100/bbl.
Representative Gara asked for verification that given the
current cost structure and how it would affect the 20
percent capital cost deduction under the ACES system, the
crossover point was about $70/bbl.
Mr. Mayer replied in the affirmative. He added that as
costs declined the crossover point was reduced.
8:54:59 AM
Mr. Mayer moved to slide 14 and discussed "SB 21: Special
Incentives for 'new oil.'" He noted that new oil included a
number of things developed over the course of the past
decade and excluded the bulk of production from legacy
fields. He addressed the gross value reduction (GVR), which
had been created for the purpose of reducing the gross
value at the point of production (GVPP). He pointed to a
chart on slide 14 - the red line pertained to old oil under
SB 21 and the purple line represented new oil under SB 21.
He noted there was a similar shape to the curve, but SB 21
new oil had a lower effective tax rate at all of the prices
listed. He explained that GVR was used because previous
proposals (e.g. HB 110) had looked at establishing a lower
rate for particular new production, but it was very
difficult in practice to do that. He detailed that a big
part of the way the profits-based production tax on the
North Slope worked was that it did not "ring fence" or look
field by field. He elaborated that the state did not want
to get into the business of identifying which costs went to
which production streams in order to determine what
different tax rates for different assets should be.
Instead, on the North Slope each company was considered one
combined unit with one set of costs and one set of
revenues. To try to reduce the tax rate without ring
fencing, the only way to distinguish between different
streams of production was at the level of production and
revenue, which was easy. He furthered that if it was the
only area to make an intervention, the tax rate could be
reduced - not by reducing the tax rate - but, for example,
if revenue was 10 to 20 percent less than it had been, it
was effectively the same thing as reducing the tax rate.
8:58:08 AM
Representative Gara remarked that the chart seemed
consistent with a report issued by DOR, but he believed it
did not seem consistent with a chart provided earlier in
the week by Dan Stickel (assistant chief economist, Tax
Division, Department of Revenue). He asked for verification
that based on the chart on slide 14, the percentage paid
for profits on production tax went down to zero at about
$73/bbl for GVR oil.
Mr. Mayer answered in the affirmative (based on the cost
assumptions on slide 14).
Representative Gara asked for verification that for older
oil fields the floor of 4 percent was reached at about
$76/bbl. Mr. Mayer answered that an effective tax rate of 4
percent was never reached; it went down to slightly below
10 percent.
Representative Gara surmised that 10 percent of profits was
about the equivalent of a 4 percent gross tax rate. Mr.
Mayer answered in the affirmative.
Representative Gara answered that the information was
consistent with a report provided by DOR. He restated the
tax rates. However, Mr. Stickel had presented a chart
showing a good amount of production tax revenue for GVR oil
even below oil at $73/bbl. He asked for an explanation.
Mr. Mayer was not familiar with the specific chart. He
stated that there was still substantial revenue coming into
the fiscal system at those prices. Taxes declined and in
some cases down to zero at precisely the point when the
royalty was becoming a bigger portion (steadily more
regressive). In general, SB 21 for new oil was designed to
have an overall government take rate of about 65 percent
across a wide range of prices; in order to achieve that,
the rate needed to go down to zero because the royalty was
increasing and taking up more and more. At lower prices,
revenue was derived from royalty and property taxes rather
than from production tax.
Representative Gara stated that the tax rate went down
under SB 21 with the exclusions. He asked for verification
that the exclusions (credits) had nothing to do with
investing money, they were merely a function of price for
GVR and old oil.
Mr. Mayer agreed. He believed the word "credit" was almost
a misnomer in that sense. He elaborated that it was simply
an integral part of the tax system and was not dissimilar,
in some ways, to progressivity under ACES.
9:01:52 AM
Representative Pruitt surmised that GVR credit was really
just a function of creating a progressive tax. He
elaborated that instead of doing what had been done under
ACES, the legislature had elected to use the credit. He
believed the term "credit" was almost an incorrect way to
describe it. He agreed that it was a credit, but it was
really just a function of the tax.
Mr. Mayer answered that it was important to distinguish
between two things. He addressed new oil and the GVR at the
top of slide 14, which was applied to the GVPP calculation.
From an accounting or statutory perspective, it was not
considered a credit; it was simply a reduction in GVPP. He
explained that later there was a fixed $5/bbl credit, which
was accounted for as a credit used against liability in
DOR's data. He agreed that it was not a credit in the way
that capital credits under ACES were - it did not depend on
investment - it merely filled the same role as
progressivity had under ACES. He detailed that it was an
integral part of the mechanism to define an effective tax
rate curve (effective tax rate shown in purple on slide
14). He elaborated that it was determined by saying that $5
represented a much bigger portion of a $40 barrel than a
$140 barrel; therefore, it would bend the tax rate down. He
added that it was listed in statute as a credit, but it was
best understood as an integral part of the tax system that
existed to shape the effective tax rate.
Representative Pruitt thought the credit could be referred
to as a deduction or reduction. He thought it was
appropriate to make the distinctions because as
conversations about the overall tax credits continued, the
item would become lumped in with other tax credits. He
surmised that if the legislature was going to appropriately
speak to the current tax regime, it needed to distinguish
between the intent of the particular credits (a reduction
or deduction) because it was not an apples-to-apples
comparison.
Mr. Mayer agreed.
9:05:06 AM
Mr. Mayer continued to address slide 14. He explained that
at lower prices such as $40/bbl there was an NOL credit;
later slides would show that the credit was calculated
based on production tax value/barrel (PTV/BBL). The PTV/BBL
was determined by GVPP; the GVP existed to reduce the GVPP.
One of the issues the administration had raised, was that
at the moment, because of the way the things cascaded (e.g.
the NOL credit was determined by PTV/BBL), it could be much
higher than 35 percent of an actual NOL. He would address
the issue in more depth later in the presentation.
Representative Munoz asked at what point new oil should be
considered old oil to match the overall tax system.
Mr. Mayer answered that it was a difficult question. There
had been substantial discussion on the topic surrounding SB
21. There had been discussion about how much incentive the
state wanted to offer for new investment. The basic idea
was that legacy production required relatively little
additional investment compared to new projects - if the
state wanted to ensure things were economic, it required a
boost. The state also had to decide how much of a boost to
give to new development. Once the decisions had been made,
there were various ways of structuring the system. For
example, the state could determine that the GVR applied
indefinitely; or, it could specify the GVR was higher, but
limited to the first 5 to 15 years of production. He
explained that similar economics could be achieved for a
new producer in both situations. The decision had been made
to have a slightly lower rate on the GVR; it would apply
indefinitely, rather than worrying about making changes to
incentives and other things that happen when it starts
running out. Slowly over time, SB 21 new oil represented a
bigger share of things. He did not want to suggest that
fiscal terms should continue to be changed; stability was
more important than anything. However, he did believe that
whether the GVR should be indefinite or time-limited was a
reasonable question.
9:08:20 AM
Mr. Mayer continued to address slide 14. From the
perspective of field economics things that change after the
first 10 to 15 years of an asset's life, had a much lesser
impact on the economics of development than things
occurring in the first decade.
Representative Pruitt surmised that if the goal was to
incentivize oil, it may be appropriate to understand what
the state expected the total amount of new oil to be. He
asked if new oil was projected to be a major portion of the
oil produced. He wondered about the state's goal and
whether it was to incentivize new oil. He reasoned that if
the goal was to take over the revenue stream, it was
something the legislature should talk about. Alternatively,
if the goal was to work to stem the decline and make sure
something was being generated, it was a separate
conversation.
Mr. Mayer agreed. He expounded that at the moment new oil
was a very small portion of the revenue base - it would
increase over time. He would have to look at DOR data to
determine if there were any projections for new oil in the
next 12 to 18 years.
9:10:02 AM
Representative Gara referred to an earlier question about a
possible tweak in the oil tax system. He addressed Mr.
Mayer's response that an oil tax system should not be
changed every year. He stated that the battle between
higher and lower tax legislators and others had gone on
since 2004. He had once heard that the two most unstable
tax regimes (in a safe place to conduct business) were a
tax system that was too high and a system that was too low.
He asked if the statement was fair.
Mr. Mayer agreed. He elaborated that there were many ways
of assessing fiscal regime stability, but it was possible
to look at some regimes and know that they would change at
some point precisely for the reason highlighted by
Representative Gara. He noted that it was not desirable to
invest in regimes that were too onerous, but it was good to
consider that there may be an opportunity for investment in
the future because the rate may be unsustainable. He
elaborated that regimes that were too generous may look
great initially, but it was important to be careful because
regimes that were too generous could not last.
9:11:44 AM
Mr. Mayer relayed that he was finished with his overview of
core fiscal regime concepts for the North Slope, which he
hoped set a background to look at some of the changes
proposed under the original HB 247. He noted that he had
spoken with the committee in a meeting the previous day
about changes the CS contained. He addressed slide 16
titled "Monthly Gross Minimum Calculation: Neutral or Tax
Hike." He had relayed that it was the type of thing that
seemed to be more incremental revenue raising than a
statement of principle about something that should work
differently in the tax system. For instance, in 2014 a
monthly gross minimum would have brought in an additional
$100 million in revenue to the state. He addressed a chart
showing the core revenue calculation for old fields, which
began with ANS WC [Alaska North Slope West Coast];
subtracted transport, operating and capital expenditures,
PTV/BBL; determined 35 percent; and took away an $8/bbl
credit. The horizontal access on represented time;
different prices were applied for the different months of
2014. For 2014 as a whole, the dollar per barrel credit
would have been $8/bbl. The blue text in the latter columns
on the chart represented the core of the net profit-based
calculation. He explained that they began with 35 percent
PTV and subtracted $8/bbl, which equaled the actual tax; it
was then compared to the green column, which represented 4
percent of the GVPP.
Mr. Mayer explained that whichever tax was higher applied -
the PTV was determined by which of the two columns was
greater. For the first half to three-quarters of 2014, oil
prices had been around $100; there had been a sudden price
collapse at the end of 2014 that had ended at $60/bbl in
December. He explained that when calculating the number
annually, it was clearly a net tax year as opposed to a
gross tax year. Alternatively, if the calculation had been
done monthly, the first 10 months would have been net taxed
and the last 2 months would have been gross taxed. He
pointed to the November row on the chart and explained that
4 percent of GVPP was $2.68, which was higher than the net
tax [$1.59]. Taken on an annualized basis it was the net
tax all the way through because the annual numbers showed
net tax terms. However, during periods of price volatility
there were times the gross minimum could be charged on a
monthly basis even though the overall year showed a net tax
environment. If the calculation was done annually, the end
result would be $8.71 per barrel in the net production tax;
whereas, averaging out the 12 months reached a total of
$9.31 [shown at the bottom right of the chart].
Vice-Chair Saddler asked how the annual 2014 production
tax/bbl had been determined (slide 16). He observed that
the production tax/barrel column was the greater of the two
previous columns ["Less $8/bbl" and "4 percent of GVPP").
He observed that in November and December 2014 the gross
tax was higher.
9:16:15 AM
Mr. Mayer explained that the first row of the chart (slide
16) represented the calculation on an annual basis. It
showed the average price for the year.
Vice-Chair Saddler asked for verification that it was the
average price per barrel.
Mr. Mayer affirmed that the top row reflected the average
price for the entire year. He continued that the annual
calculation worked the same as the monthly calculations and
it resulted in a higher net tax; therefore, the net tax
applied. He pointed to the difference between the $8.71 and
$9.31 on the second to last column to the right of the
chart on slide 16. He noted that the chart showed a high
level calculation that treated the entire North Slope as if
it was one tax payer. He explained that it was a difference
of $0.61/bbl, which if applied to all taxable barrels
produced on the North Slope it was a rough difference of
about $100 million.
Vice-Chair Saddler asked if the $9.31 was an average of the
production tax/bbl column. Mr. Mayer answered in the
affirmative.
Vice-Chair Saddler pointed to a row labeled increase [last
row at the bottom of the chart] and asked for detail. Mr.
Mayer answered that the row showed that $9.31 was $0.61
higher than $8.71.
Mr. Mayer continued to address slide 16. He explained that
it was not clear why someone would want to assess the tax
on a monthly rather than on an annual basis. The tax system
was done on an annual basis at present for the same reason
that personal and corporate income taxes were done
annually. He explained that using a longer time period
smoothed volatilities associated with revenues and prices.
9:18:57 AM
Representative Guttenberg stated that usually a situation
like the one presented on the chart included winners and
losers. He wondered what differentiated between the two
groups.
Mr. Mayer answered that the winners and losers on the chart
were the state and producers.
Representative Guttenberg asked for verification that it
did not include competition between producers.
Mr. Mayer agreed. He characterized the situation as a
"heads I win, tails it's a draw" gamble. He detailed that
if there was one uniform price with no volatility for the
entire year, the question about annual versus monthly
calculations would be irrelevant in terms of the end
result. There was a difference when volatility existed.
When there is volatility, the state wanted to take
advantage of the months where more was paid under a gross
tax, even though for the year it would not be in the
situation.
Representative Pruitt surmised that the particular
provision only came into play when focusing on the 4
percent of GVPP (when it was the higher of the two taxes).
He believed that at lower prices the annual versus monthly
calculation was not a concern. He reasoned that whether or
not it was beneficial to the state did not become a concern
until prices reached the $70 or so breaking point. He asked
if his statements were accurate.
Mr. Mayer replied that it was about volatility and that
some months were in the net tax environment, whereas others
were in a gross tax environment. He stated that the entire
year would be month-by-month in a tax calculation; there
could be volatility and it would not make a difference.
Alternatively, if the entire year was in the gross tax
environment, it would not have an impact. Volatility
presenting a switch between gross and net meant that
switching between the two meant more money going into
savings because it was taking advantage of the best of
either world on a month-to-month basis.
Representative Pruitt surmised that in the current year
that was projected by DOR to remain in the gross tax
scenario, it was not a concern.
Mr. Mayer agreed that it was not a concern if there were
not substantial increases in the price of oil later in the
year.
9:22:01 AM
Mr. Mayer addressed slide 17 titled "GVR Raises Net
Operating Loss (NOL) Credit Above 35 Percent of Actual
Loss." The next key item carried over from the original
bill to the CS was how the GVR worked with the NOL credit.
He explained that the GVR was artificially reducing the
GVPP to reduce the overall tax rate. He looked at a chart
on the left and explained that the left hand column titled
"SB 21 GVR" represented current law for new oil; the right
hand column represented new oil under the proposed HB 247.
The difference was what the evaluation of the NOL credit
was based on. Under current statute it was 35 percent of
the negative production tax value per barrel [shown in blue
on the chart]. Under the SB 21 GVR column the PTV/BBL was
-12 percent; however, if it had been calculated without the
GVR the number would have only been -6 percent. Half of the
NOL under assessment was not an actual loss; it was a loss
that existed solely as a function of the GVR. He furthered
that if the number had been calculated before the
application of the GVR it would result in 35 percent
government support for spending through the NOL (which had
been the intent) as opposed to the circumstances shown on
the chart where support for government spending was 70
percent; it varied widely based on price and cost
assumptions. There were circumstances, particularly at
lower prices, where there was substantially higher than 35
percent for government spending because of the way the GVR
interacted with the calculation of how much the NOL was.
Mr. Mayer considered the lifecycle of an oil field. There
was initial capital investment, the startup of the field,
reduced capital investment, operating costs, and revenues.
He explained that the model looked at an 80 million barrel
field with approximately 20,000 barrels of production per
day and slightly over $1 billion in development cost. At
oil prices of $40/bbl the cash flows did not look great;
the investment would not make financial sense if $40/bbl
was assumed for the lifetime of the project. He pointed to
the chart on slide 17 that showed a period of negative cash
flows in the early years and some small amount of revenues
at $40 later on. The solid black line represented current
statute and the dotted black line indicated making a
correction related to how the GVR impacted the NOL. He
pointed out that cash flows were $10 million higher at the
most under current statute. In the first years there was no
production at all; therefore the GVR was not an issue - the
NOL was simply 35 percent of the actual capital invested.
Once revenues began coming in, but a substantial profit had
yet to be made, there was a period of a couple of years
where the GVR impacting the calculation came into play. He
noted that if the chart reflected $70/bbl there would only
be a year or two that the issue factored in. The impact was
bigger at $40/bbl - as much as $10 million per year for a
couple of years of production. In the 8th or 9th year there
would be a small profit, but the existing system assessed
it as NOL because it was NOL once the GVR was factored in.
The CS maintained that the intent of SB 21 was to have 35
percent support for government spending for everyone under
all circumstances, but the issue pointed out in the chart
did not seem to be consistent with that; therefore, it may
be worth addressing.
9:27:30 AM
Mr. Mayer turned to slide 18 regarding a hardening of the
floor that raised taxes on losses. He spoke to existing
production. He relayed that SB 21 implemented a floor for
the first time that bottomed out at an effective tax rate
of just under 10 percent and then things began climbing -
[the effective tax rate for] existing production no longer
went down to zero. The bill would raise the floor from a 4
percent to a 5 percent floor (illustrated in red and green
on the chart on the left). He explained that effective tax
rates could only be used as a tool of analysis going down
to just below $50/bbl because after that there was no value
to tax. The chart on the right looked at the absolute
numbers of production tax per taxable barrel. He pointed to
the inflection point around $80/bbl where the gross minimum
kicked in; the inflection point was slightly higher in a 5
percent world versus a 4 percent world. He pointed out that
the red line (SB 21) and the green line (HB 247) flattened
out, but there was a key difference around $45/bbl, which
was the point when the NOL credit kicked in.
Mr. Mayer explained that SB 21 had hardened the floor in
terms of the dollar per barrel credit, but the one thing
that could take the tax below the floor was the NOL credit.
He noted that the concept had been a deliberate policy
choice. He elaborated that if an NOL occurred (there was no
longer a profit to be taxed), tax simply applied to
activity and revenue even in a loss making position.
Overall the system had recognized for a long time that for
all the reasons discussed, all of Alaska's fiscal regimes
had tried at low prices to reduce the impact of the gross
taxes. For example, the Economic Limit Factor (ELF) had
used the economic limit formula, which had only worked for
some period of time; it had been effectively to reduce the
tax rate when wells were less productive. Current statute
reflected a series of assumptions from a different period
in time, but even the current gross tax had been
established at 4 percent in some price range, 3 percent in
another, 2 percent in another, and so on. The idea had been
that it was important to understand and mitigate that a
gross tax had a disproportionate impact at the lowest oil
prices. He continued that in the past it had been hard to
imagine there would ever be an NOL made by major producers;
however, it was now the case.
Mr. Mayer discussed that under the circumstances, the state
may need to think about reducing the gross floor, given
that it was effectively an infinite rate of tax; it should
never go below zero, but there should be the possibility to
reduce it. He noted that it was a policy debate that
peopled differed on. For example, it was reasonable to take
the stance that the gross floor was there to provide the
state with revenue protection and they understood that it
was taxing at a time when there was no profit to tax. He
remarked that it was a difficult and important debate. He
believed the system had worked well overall and had
protected the better state on the downside than the
previous system; competitive regimes balanced risk and
reward. He spoke about North Dakota versus Norway related
to needing a system that was evaluated at both ends. The
danger was that when prices were good there was worry about
whether the state was taking enough on the high end.
Alternatively, when prices were low, the state looked at
North Dakota, which was much better protected on the low
end. He believed there was a substantial danger related to
how the minimum tax worked and whether it should be
hardened, increased, or other.
9:32:37 AM
Mr. Mayer believed there was a difference between the
debate on hardening the floor and increasing the rate
(slide 18). He believed hardening the floor would create
problems for numerous people and would run a danger of
impact on investment. However, he believed the danger of
increasing the rate from 4 percent to 5 percent in a year
when times were bad was that companies would wonder what
would happen in the next year. He encouraged members to
think about how the changes appeared from the perspective
of long-term fiscal regime stability. He cautioned against
creating anxiety about what unforeseen changes the state
may implement in future years.
9:33:54 AM
AT EASE
9:41:23 AM
RECONVENED
Co-Chair Thompson noted that the 10:00 a.m. meeting would
be delayed.
Mr. Mayer addressed slide 19 related to how HB 247 would
impact new field development. Slide 19 included a lifecycle
model of a hypothetical new development, which helped
represent some of the actual development on the North
Slope. The model included an 80 million barrel field with
production of about 20,000 barrels per day, which would
require about $1.3 billion in capital and drilling costs.
The model included an individual drilling profile with a
look at how many wells were drilled annually. He looked at
the chart on the left that showed initial capital costs in
dark blue and government take in red. Government take was
negative in the early years; the NOL credit contributed
some of the capital costs; therefore, the cash flow was not
as low as the total capital being spent. Later years began
to generate some government take and a significant amount
of revenue once costs declined.
9:43:05 AM
Mr. Mayer turned to slide 20 titled "Refund Limits Boost
Capital Needs and Lower IRR." The slide addressed the
current impact of proposed refund limits on new developers.
The range of possible effects is quite significant,
depending on whether it was the only asset a company owned
or if they had existing assets that were also claiming an
NOL; it was a proposed per company limit of $25 million,
not a per asset limit. The NOL credit essentially brought
forward a deduction that a company would otherwise have
later in the cycle to substantially reduce the amount of
capital it needed to build a project. The chart on the left
showed cumulative cash flow and how much total capital a
company needed to develop a project. He explained that if a
company wanted to develop a project it would not need the
full $1.3 billion because at some point the project would
become self-financing and self-sustaining. He continued
that at some point costs would be incurred while oil was
being produced and the revenues could go towards financing
the additional drilling. He estimated that a company would
need around $350 million to develop the project on slide 20
under the current 35 percent refundable NOL credits. He
pointed to the solid black line on the chart on the left,
which represented SB 21 GVR with a refundable NOL - from
that point onwards the project would become self-
sustaining. The chart showed that by 2022 or 2023 the
company would have recovered all of its initial investments
and would be bringing in revenue.
Mr. Mayer explained that by reducing the refundability of
the NOL the amount of capital required to develop a project
would increase substantially. The dotted line at the bottom
of the charge depicted what would occur if the credit was
non-refundable and had to be claimed out of future tax
liabilities. He pointed out that by 2027, the lines on the
chart merged and became the same thing; however, the dotted
line was substantially lower for the previous years. He
explained that the scenario required substantially more
upfront capital of over $500 million (due to the absence of
the 35 percent refundable NOL credit); however, after 2027
the company would pay less in taxes and would recoup its
investment at that point.
9:46:14 AM
Mr. Mayer continued to address the chart on the left of
slide 20. He explained that a dollar per company limit
scenario fell somewhere between the black and dotted lines.
For example, if there was a $25 million limit for a company
with only one asset, the project may only slightly increase
capital needs (e.g. from $350 million up to $400 million or
$450 million). He added that the amount would depend on
other assets a company owned and whether it was claiming
NOL on any of them. In general, as the limit increased, the
impact it had for a company was substantially less. He
explained that if it was a $75 million limit for a single
asset, it probably would not have an effect; however, if a
company had another project that was eligible for an NOL,
even a $75 million limit would have some impact. He
explained that DOR would have to provide some precise
numbers on how many companies would be impacted by what
exact limit. He noted that one could say that the $200
million limit proposed in the CS should be a binding limit
for no one currently on the North Slope. He expounded that
numbers in above or below $100 million had some impact on
some people, but the precise impact would vary
substantially from company to company.
Mr. Mayer continued that there were two large impacts of
any binding limit on the amount that could be refunded: the
amount of capital required to develop a project and the
corresponding internal rate of return (IRR). He pointed to
a chart on the right of slide 20, which showed that non-
refundable credit meant a company needed $5 to $10 dollars
higher in oil price to get the same IRR as it could get
under the refundable credit. He explained that if the bill
implemented a $25 million limit in mid-2016, it would mean
companies currently undertaking developments could need 50
percent more capital than they anticipated. He explained
that it would be a very difficult position for companies to
be in. Additionally, if companies needed to raise
additional capital they would need to do it in an
environment that did not require going back to investors
for additional capital because all of the IRRs were much
lower than anticipated due to the change. He highlighted
several issues including when the limit would apply, who it
would apply to, and whether there were ways of
grandfathering in existing investment (if the limit was
strict). He noted that if the limit were high it was
unlikely to be such a problem because it was likely to have
less of an impact on current investment. Possibly the
largest concern was not about the current refunded NOL
credit, but about what may happen if there was a major new
investment (e.g. development of a new Kuparuk-sized field).
He stated that it could easily be a total of $2 billion in
NOL credits in the first couple of years of development. He
thought anyone should think about that figure and have
concern about what it would mean for state finances and
whether the state could afford the amount. He reasoned that
over time a large field discovery would be wonderful in
terms of all of the future revenues it would bring, but it
could be a severe strain on the state finances in the
short-term. The hope was that a large project would be
economic regardless of the timing and he believed it was
reasonable to put a limit in place to limit the potential
downside exposure of the state. He questioned the right
level at which to set a company limit.
9:50:43 AM
Mr. Mayer addressed slide 21 titled "Changes Make
Regressive System Even More So." He continued speaking to
new development. He explained that the biggest impacts came
through the higher floor. The idea of making the gross
minimum floor binding for new oil meant going from
effective tax rates of zero at current prices to gross
minimum taxes of 5 percent at a time when there was no
profit to be taxed. The charts on slide 21 provided a look
across a wide range of prices and how the structure of
government take was impacted. The slide used a hypothetical
asset of $1.3 billion in capital investment and considered
what portion went to the state and what portion came from
different components of the system. The chart on the left
represented SB 21 GVR for the new asset; it was a system
designed to create a level of government take between 60 to
65 percent across a wide range of prices. He noted that
production tax was something that was levied when oil
prices were $70/bbl and above. He explained that across the
price environments, production tax made a positive
contribution to the state's overall take from the asset. He
detailed that in the early years production tax through the
NOL credit would be negative, but in the later years the
state would receive tax revenue from the asset. As long as
the oil price was $60/bbl to $70/bbl or higher, over time
the revenues would exceed the credits the state spent.
Mr. Mayer continued to address the left chart on slide 21.
At lower prices the credits would exceed revenues. He
expounded that oil prices at $40 to $60/bbl for the 20
years of the project's life would not be a good investment
and the tax credits paid in the early years would be
greater than the recovered revenues. He noted that it was
only one piece of the picture. There was also the
regressive royalty that took a large share of any available
profits in low price environments. He continued even though
production taxes were negative for the state if low prices
were assumed for the lifecycle of the asset, the royalty
was high enough that government take did not go down
(dotted black line) until prices below $60/bbl; negative
production tax brought government take down. Government
take was still regressive because the impact of the
regressive royalty was greater than the impact of negative
production tax (because the value of the credits was
greater than the value of the taxes). At $40/bbl the state
would receive close to 100 percent government take despite
the fact that the credits were contributing to the company
and not the state.
9:54:25 AM
Mr. Mayer addressed the chart on the right of slide 21,
which accounted for changes proposed under HB 247. A
binding floor meant that gross tax had to be paid even for
new oil.
Representative Gattis asked Mr. Mayer to repeat his
previous point. She believed it was very important.
Mr. Mayer agreed that it was an important point. He
repeated that at lower prices (particularly below $50/bbl)
despite whether the prices were assumed to remain at that
level for the life of an asset, the credits paid out at the
start of development were greater than the production tax
revenues received in later years, which was a negative to
the state in net. However, the royalty was so regressive
that when all things were factored in - government take was
regressive and going up at the low price levels of around
$40/bbl - it was close to 100 percent.
Representative Wilson spoke about tax credits, which
represented the state investing in a project (just as it
would buy shares of stock). She furthered that the state
hoped the investment would become profitable, where the
state would still contribute to its part and the company
would pay more, until a point was reached when the state
was no longer investing, but it was receiving money. She
asked for the accuracy of her statement.
Mr. Mayer answered she was correct in relation to the
overall workings of the tax structure. He elaborated that
the state contributed 35 percent of the upfront costs and
received up to 35 percent of the cash flows that came as a
result (in addition to royalties, taxes, and other).
Representative Wilson reasoned that if a new field was
discovered, it may not be the right time for the state to
make a $2 billion investment. She surmised that it was not
necessarily a bad investment and it could bring the state
more money for years.
Mr. Mayer agreed. He stated that it was all about the
timing of cash flows as opposed to the actual amounts.
Unlike previous years and the situation in Cook Inlet, the
only real credit on the North Slope was the NOL credit; it
was clear when looking at the overall economics that it was
providing the same benefit that existing producers had
through the tax system and was an investment in the future
of production. The only changes under contemplation changed
the timing of when the investment was made - whether the
state was paying its share of the capital upfront like
other investors or later by taking less cash flows; in net
the two strategies were the same. The question was whether
the state could afford the upfront investment or not and
understanding that it provided a substantial benefit to the
developers.
Representative Wilson surmised that the state must be a
pretty good investor thus far because 90 to 95 percent of
what it took to fund government had come from the oil
investments. She asked whether the Department of Natural
Resources (DNR) made the determination that the state may
want to invest in a project because its profitability was
verifiable. Alternatively, she wondered if someone could
come in and drill a hole merely to get the tax credits in
the hope that the state would not conduct due diligence.
9:59:07 AM
Mr. Mayer answered the state did not have the control of a
direct equity investor. He elaborated that unless
particular things were put in place to address the issue,
the due diligence was all conducted by the companies
themselves, which were acting in their economic self-
interest to make profitable investments. The state was not
making an assessment on its view.
Representative Wilson wondered what was broken. She
reasoned that tax credits were really an investment and she
did not believe the state was giving companies anything
without something in return. She highlighted that the goal
of SB 21 was to get more oil, which she believed was
working. She wondered what the administration hoped to gain
from the passage of HB 247.
Mr. Mayer replied that when he looked at how SB 21 was
working on the North Slope, he did not believe anything was
broken. He opined that overall the system worked fairly
well. He elaborated that the bill made changes in other
areas like the GVR and NOL that he believed were legitimate
issues raised by the administration. He thought the
question of what the state could afford in terms of timing
of cash flows was also a very legitimate question to be
raising. Particularly, if a $2 billion investment arose, he
believed it was right to be concerned about what it could
mean for the state's ability to manage those cash flows
over a period of years and to think about what the state
could put in place to mitigate against the situation.
However, broadly speaking in terms of the overall regime of
taxes and credits on the North Slope, he did not see
something as broken, but as something that had worked quite
well.
10:01:05 AM
Representative Wilson asked for verification that Mr. Mayer
would not do anything to change SB 21 at the current point
in time as it pertained to the North Slope.
Mr. Mayer agreed.
Representative Gattis asked if Mr. Mayer would make changes
to Cook Inlet.
Mr. Mayer returned to slide 6 titled "Big Difference
between North Slope and Cook Inlet." He did not believe
anyone could think the Cook Inlet credit structure was
sustainable.
Representative Gara remarked that he did not know the
utility of asking someone who consulted to help build SB 21
whether there was anything wrong with SB 21. He asked for
verification that there were other jurisdictions in the
world that produce oil very well that did not offer cash
payments in terms of tax credits.
Mr. Mayer answered in the affirmative. He reasoned that
Alaska was probably rare in structuring things the way it
did. He referred to Australia, which had a similar system,
it carried expenses forward with interest and deducted them
against future taxes to try to maintain the time value of
money. He explained that Australia used the method
precisely because it was concerned about managing cash
flows.
Representative Gara referred to Representative Wilson's
point that the state had no control as to whether it was
putting tax credits into fields that had no good prospects
or really great projects and anywhere in between. He
reasoned that unless someone from the state was in a
company board room, it would not know whether the tax
credit payments given to a company were what led to the
production or other.
Mr. Mayer replied in the affirmative. He did not think it
was appropriate to think about the NOL credit as an
incentive to create new production; it was simply the same
benefit that would happen later through the tax system.
10:03:59 AM
Mr. Mayer moved to slide 23 titled "Activity has Responded
in Recent Years" related to Cook Inlet. He relayed that the
presentation appendix included an analysis enalytica had
done for the House Resources Committee on Cook Inlet and
the nature of what had happened there. He expressed intent
to provide highlights of the analysis. He discussed that
Cook Inlet had gone through several cycles since the 1950s.
He pointed to a chart on the left of the slide that showed
exploratory wells spudded; the chart on the right showed
development wells by year of first oil/gas they produced.
He noted that in both cases there had been a substantial
uptick since 2010. Recent exploration activity was on par
with some of the previous peaks; development drilling had
been relatively more stable over years, but the recent
growth was some of the highest growth in production
drilling in Alaska's history.
10:05:10 AM
Mr. Mayer turned to slide 24 related to Cook Inlet oil and
gas production. He explained that when it came to the Cook
Inlet turnaround that was frequently referred to, it was
important to distinguish between oil and gas. He detailed
that there had been peak production of oil in the 1970s of
more than 200,000 barrels per day, a steep decline into the
1980s, reaching a low of 7,500 in 2009, and a marked
increase in the past 6 or so years; current production was
about 18,000 barrels per day. He explained that gas
production was a very different picture, which had
experienced a long plateau in the 1970s and 1980s. The
chart on the right showed three lines: the red line
represented gross production of gas from the well, the
green line represented gas reinjected into fields
(particularly into the Swanson River field), and the orange
line represented production net of reinjection and
withdrawal. The actual gross production from the fields
started to decline substantially in the mid-1990s and would
have led to substantial falls in total gas production in
Cook Inlet, but the blowdown at Swanson River meant that a
lower plateau was achieved for several years; the full
impact of decline had not occurred until the blowdown had
ceased in the middle of the last decade, at which point
decline began again. Gas had declined to around 150,000
million cubic feet (mmcf) per day in the latter part of the
previous decade; however, there had been some stability in
the last several years. Turnaround in oil production had
more than doubled over the last five years, whereas gas
production had plateaued. One of the key reasons for the
difference, was that unlike oil, gas was constrained by
physical demand.
10:07:34 AM
Mr. Mayer addressed a summary of what had happened to oil
and gas production and activity in Cook Inlet in recent
years (slide 25). There had been stable gas production and
oil production had more than doubled. He relayed that the
gas market had experienced a major transition in everything
from supply, demand, prices, competition, and expectation.
Cook Inlet was becoming a steadily less material asset and
interest in reinvesting capital was waning for legacy
producers like Chevron and Marathon. Additionally, there
had been suppressed prices that had been far below Henry
Hub, which had been seen as a very high price that "we were
not sure we were willing to pay," and a long period of
under investment occurred as a result. He explained that
there had been changes in all of those things. He detailed
that Hilcorp was a new entrant and mandated high pricing
under its consent decree; it was focused on workovers and
turning the basin around and credits were part of the
incentive to help the work along. He expounded that the
changes happened in all mature basins - older, mature
players became less interested and were replaced by new
ones. He believed there were probably particular challenges
in Alaska that made the process slower, meaning there had
been fewer new entrants interested in investing. Throughout
that process, credits probably made it more attractive to
companies like Hilcorp and in enabling much smaller players
to undertake activity that may not have been possible
without the credits.
Mr. Mayer addressed how sensitive the outlook in Cook Inlet
was to changes in the fiscal system (slide 25). He
addressed DNR estimates of about 1.2 billion cubic feet
(bcf) in remaining reserves in the mature fields and
estimated an additional 400 bcf in Bluecrest's Cosmopolitan
project and Furie's Kitchen Lights project. He stated that
it was not reasonable to divide the 1.2 bcf in existing
developed fields by annual production and assume that there
was 10 years of production, because production happened to
decline. Strong reinvestment may continue plateau
production for another five years or more; however, it was
hard to look at the resource base alone and think that
decline would not occur again in five to six years. Unless
the resource estimate was significantly on the low side, it
was hard to imagine that even with substantial ongoing
reinvestment in mature fields that decline would not occur
again at some point in the future. He furthered that at
some point there would be an incremental wedge of new unmet
demand that would need to be met from somewhere.
Fortunately, Furie had brought new reserves online at
Kitchen Lights - how much the reserves were remained
unknown. The biggest question centered on the policy aim of
the substantial subsidy that went into Cook Inlet through
the tax credit regime. He believed the biggest thing needed
was to ensure that new development on new projects could
occur, if the aim was primarily about security of gas
supply to Southcentral Alaska.
10:11:52 AM
Mr. Mayer continued to address slide 25. He communicated
that at current gas price levels, brownfield investment in
old fields should be profitable with or without credits. He
would address modelling to illustrate the point later in
the presentation. By in large, credits were much more
important when it came to developing new resources; it was
especially the case because of the demand constraints.
There was only a very small incremental amount of unmet
demand and trying to develop a new field with nothing other
than that demand was very difficult to make the economics
work. At the moment there was significant uncertainty over
the future of the fiscal regime in Cook Inlet. He
elaborated that the past year there had been a discussion
about potential caps on how much was paid out and sudden
panic over the impact on financing that occurred around
credits. He believed that when looking at the cash coming
in and going out, it was hard to see the regime as
sustainable. Combined with the fact that the regime was set
to sunset over the next several years, it created
significant uncertainty about what the system actually
looked like. He noted that - as many people at the House
Finance Committee had testified - there was nothing worse
than that uncertainty when trying to run economics and
decide whether or not to invest. It was important to think
about the aim of the fiscal system regime, the most
efficient way to provide support for the security of gas
supply to Southcentral Alaska, and if there was a way of
doing those things as part of an overall review and setting
a long-term stable fiscal regime for Cook Inlet (rather
than making one incremental tweak in the current year with
uncertainty about what the future looked like).
10:13:55 AM
Mr. Mayer moved to slide 26 and provided an analysis
backing up the claims about brownfield investment being
economic even without credits versus what was required for
new development. The slide looked at a hypothetical new gas
development in Cook Inlet. He qualified that some of the
costs shown may be on the high side - they were based on
the most recent new development in Cook Inlet, which had
occurred during a time of some of the highest costs seen.
He believed there was solid reason to think that the costs
could come down. The scenario looked at building a project
scaled to produce more than 100 to 145 mmcf/day with
investment of hundreds of millions of dollars in new
facility capital costs (e.g. platform, pipelines, and
other). The problem was that currently there was
constrained demand; demand was well met by existing mature
fields. He furthered that if demand increased slightly and
mature fields declined slightly over the next five to ten
years, it was not feasible to have a full development that
produced the desired project size. He elaborated that a
company may only have the ability to drill two or three
wells over the next several years. He discussed a
production profile that built slowly from 15,000 mmcf/day
to a peak of 40,000 mmcf/day in a decade's time. He
explained that the economics of that type of project looked
very difficult, particularly if a company had to spend
anything like the aforementioned costs on facilities. He
believed the costs were representative of recent activity,
but it could drop substantially in future years. He
furthered that there was a major capital outlay in the
early years with not much revenue following because
production would never reach the capacity the project aimed
to develop. He believed the scenario represented the
current reality of new gas development in Cook Inlet.
10:16:35 AM
Mr. Mayer addressed six bar charts including a number of
metrics for the hypothetical gas project under a
constrained market (slide 27). The top three charts looked
at the split of total net present value (NPV) of the
project, discounted at a 10 percent rate. The red line
represented the NPV of all of the credits, royalties, and
other things received by the state; the green line
represented the company's NPV; and the blue line
represented the federal government's NPV. He explained that
if a project was heavy in capital requirements but never
received significant revenue, the scenario was nothing
other than a complete subsidy by the state. At high prices,
the project was potentially very marginally economic;
however, returns would still be very low.
Mr. Mayer addressed the bottom three charts on slide 27,
which showed the investor IRR in red and government take in
blue. The charts indicated that it was a very generous
fiscal regime with less than or slightly over 40 percent
government take; even in the very low rate of government
take and a huge government subsidy, the IRR went from less
than 10 percent to the mid-teens under the highest prices.
At realistic gas prices, the investment was not highly
attractive for anyone - particularly anyone with a high
cost of capital. He added that the companies were mostly
reliant on private equity and people who required high
rates of return to be willing to invest. Unless the upfront
capital costs could be reduced substantially, even with the
effect of 65 percent subsidy, the project remained
challenged. The project became substantially more
challenged under the proposed HB 247. He summarized his
earlier testimony that there were currently three credits
in Cook Inlet: the 25 percent NOL credit, 20 percent
qualified capital expenditure credit, and a 40 percent well
lease expenditure credit. He detailed that the 25 percent
credit was stackable with either of the other credits
depending on the nature of the capital work; therefore,
credits were between 45 and 65 percent for a new
developer's total capital spending.
Mr. Mayer explained that under HB 247 the credits were
reduced to the 25 percent NOL credit (both capital credits
were taken away), IRR rates would be lower, and the outlook
for the state looked substantially better - at high oil
prices it could be breakeven or slightly positive for the
state. He noted that constrained new investment looked
substantially more challenged for the new investor. The CS
fell in a middle ground between the status quo and original
HB 247 scenarios. He expounded that in addition to the NOL
credit it maintained the 20 percent capital credit. He
detailed that it would provide 30 percent state support for
the hypothetical project, but the NOL credit would only
apply to new developers without a production tax liability.
He explained that the support also applied to established
companies through the 20 percent capital credit in a way
that would not happen through the governor's original bill.
How the approaches were balanced depended entirely on the
desired outcome.
10:20:58 AM
Mr. Mayer turned to slide 28 and addressed the second
hypothetical project the presentation considered, which
took place in an unconstrained market environment. The
scenario assumed the same capital expenses for facilities
(several hundred million dollars for platforms, pipelines,
and other), but factored in an optimal development market.
The project assumed three wells per year for the first
three years of development and another well every year for
a decade. The project could then achieve 140 mmcf/day in
gas production and maintain a steady plateau at that rate
for several years. The project became a solid economic
development under the unconstrained market environment -
the only thing that was changed was the number of wells
drilled and the amount of production achieved. He relayed
that the project looked much more like a cash flow profile
of a health investment. He explained that the scenario did
not represent the current development reality in Cook Inlet
- demand was currently severely constrained. He reasoned
that without the constraint there could probably be healthy
developments without substantial credits. However, it would
require a change in the existing demand dynamic, either in
terms of a substantial export consumer or something else.
10:22:26 AM
Mr. Mayer moved to slide 29 and addressed six bar charts
including a number of metrics for the hypothetical gas
project under an unconstrained market (slide 27).
Currently, the economics showed healthy IRRs under the
status quo system, an NOL credit-only system, or in a
system with the NOL and capital credits. All cases showed a
substantial reduction in support for the project, but with
fairly solid economics, if it were possible to build such a
project with substantial export support or increase in
demand.
Mr. Mayer addressed a third project 3 scenario on slide 30
that did not require the development of a new field or
spending several hundred million upfront. The slide did not
factor in the NOL credit because by definition an existing
mature field did not receive that credit. With the 20
percent capital credit and 40 percent drilling credit the
project was highly economic. He added that the scenario was
not specifically representative of anyone's actual
economics, but broadly speaking additional ongoing drilling
in mature fields looked economic in a wide range of
scenarios including vastly less credits.
10:24:21 AM
Mr. Mayer moved to slide 31 and addressed 6 bar charts
related to project 3. The scenario showed an IRR of
somewhere between 50 and 100 percent; without credits the
IRR fell substantially, but into a range (20 percent and
higher under HB 247 with no credits) he believed was still
very attractive to many players. He furthered that under
the CS the work would continue to have a 20 percent capital
credit; the heightened rate of the 40 percent well lease
credit would be removed.
Representative Gara referred to discussions over the years
about a shortage of gas available for existing contracts in
Cook Inlet. He reasoned that no one explored for fields
without someone to buy the gas. He discussed that every
time a new contract had come up someone had discovered gas.
He believed that the amount of gas available for the
existing contracts was being measured before someone
vocalized needing a new contract for new gas. He thought
that when a new contract arose and new gas was needed that
people went out and found it. He remarked that Cook Inlet
carried a high premium close to $7 or $8 instead of the
Henry Hub price of $2. He noted that no production taxes
were coming from Cook Inlet and asked what would be wrong
with letting the free market operate. He reasoned that of
course there were dwindling gas supplies on contract
because that was how contracts work. He asked why it was
all needed.
Mr. Mayer believed it was an important debate to have at
present. He remarked that it was hard to view the current
numbers in Cook Inlet as sustainable. The only thing that
he found concerning with the free market response was the
substantial lag of time between existing demand and the
demand being filled. He left exploration and the several
years it took to find gas out of his response. He spoke
about a scenario where there was a known resource that
needed to be evaluated for development and sanctioning -
the process would take several years. For most of those
developments the ones with attractive economics
(particularly without economic support) included
substantial volume of new demand. He believed if the aim
was a security of gas supply it was hard to think that most
of the money would be spent on that rather than on oil
development and other things. He explained that it was hard
to know what credits got spent on (e.g. credits spent on
oil versus gas and new development versus existing fields);
the information was obscured by confidentiality. He
believed that if the aim was security of gas supply, there
was an argument to be made that there could be another four
or five years of plateau if levels of investment in mature
fields persisted, followed by decline. If the scenario was
left to the free market the decline would go on for a
couple of years and after several years of decline and
unmet demand there would be enough of a new incremental
wedge to make a substantial development attractive. He
believed that there were different ways of overcoming the
situation, but a limited and targeted measure of effective
subsidy solely around that aim was not necessarily a
terrible idea. He stated that it was a very different
proposition to widespread credits for a whole range of
activities.
10:29:46 AM
Co-Chair Thompson announced that the 10:00 a.m. meeting was
canceled. He noted the importance of the topic at hand.
Representative Wilson asked how to make the distinction
between companies in the development stage with loans and
economics based on the current tax system. She wondered how
to make the changes without detriment to companies who had
invested based on the current system compared to companies
interested in investing because of great tax credits.
Mr. Mayer believed the question about companies that had
invested in Alaska based on the state's word [current tax
structure] was difficult. On the one hand, particularly
related to mature fields, it was hard to conclude anything
other than that additional drilling was attractive
regardless of credits. It was an obvious area to explore if
the state was trying to scale back on the credit expense
because it could be hard to see why the state needed to
spend the money. On the other hand, it was also true that a
company in particular had invested in the assets based on
the attractive credit structure and the legislature was now
changing the terms. He explained that if he were in the
company's shoes, his biggest concern would not be whether
the credits would exist in the future, but that he had no
idea what the future tax regime in Cook Inlet looked like.
He furthered that when running economics on new investment,
the investor would have to apply all types of penalties
because they did not know what to expect in 2, 4, and 10
years' time. He explained that if credits were removed
substantially for some of the work - which he believed was
not a terrible idea - it needed to go hand-in-hand with
making only one overall change to the system in Cook Inlet
as opposed to making tweaks over time.
10:33:19 AM
Representative Wilson was trying to determine if there was
a way to specify that companies that had come to a certain
point would continue under the current credit system and to
cut back on credits for future investors. She wondered if
it was possible to make changes to avoid devastating
current companies while stopping the state's liability in
the future.
Mr. Mayer answered that the first thing to consider was the
issue of timing. He detailed that it may not be as much
about total levels of credit support as to when a change
was implemented. He referred to a couple of companies with
active development plans, which would be seriously and
adversely impacted if a change was implemented in the
middle of the current year. Whereas, he believed most of
the developments could be undertaken by those companies if
the state maintained the current credits for a year or two.
He added that the issue was separate from ongoing work that
was not new project development, but incremental drilling
in existing fields - almost all of the gas Southcentral
currently depended on, which was largely fairly economic
work to undertake. He addressed the perception of the
companies undertaking the work about the reasons they came
to Alaska to invest. He considered how the state would
convey that changes to the fiscal regime were part of a
process of establishing a long-term stable and durable,
competitive and attractive set of fiscal terms as opposed
to revisiting the issue over and over with no clarity on
what economics would look like.
Representative Wilson asked if the committee would hear
from any gas companies only undertaking exploration. She
noted there was a large distinction between what was done
for developers versus exploration.
10:36:36 AM
Representative Gattis referred to Mr. Mayer's testimony and
surmised that in relation to credits in Cook Inlet, the
state was looking to keep companies in the queue when
Southcentral looked for gas and wanted to keep continuous
gas. She believed it was important to consider not pulling
the rug out under companies when thinking about potential
rolling brownouts and other. Anchorage depended on the
state's source of gas. She believed part of the
consideration should be about what companies could produce
moving forward.
Mr. Mayer agreed with much Representative Gattis's
statements, but made a couple of distinctions. He addressed
exploration versus development of known, but not completely
proven undeveloped resources. There was a substantial
resource currently known that needed to be developed to
bring security for the next decade or more. He expounded
that from an investor's perspective it was much lower risk
work than exploration. To the extent that credits were
being used to fund exploration (the precise numbers were
not public due to taxpayer confidentiality) there was a
legitimate question about what sort of work credits should
be supporting. He believed it was reasonable to conclude
that currently the highest priority was development of
known resources. Additionally, he considered how much the
current gas supply from mature, declining fields required
the support from the state and if changes were made to the
fiscal system, how to ensure it was part of the context of
long-term stability.
10:39:39 AM
AT EASE
10:50:02 AM
RECONVENED
Mr. Mayer noted that the next section of the presentation
was a wrap up. He asked if there were any other questions
about the Cook Inlet tax credits.
Representative Wilson asked what specifically needed to be
done with Cook Inlet to level things out and have money for
the state.
Mr. Mayer answered that the state could not afford to spend
what it was currently spending on tax credits. He believed
there were difficult decisions to be made about how much to
cut back and how much to target specific activities versus
being more broadly based. He noted that the changes
required having a consensus about the aim of the program.
If the aim of the program was only about the security of
the Southcentral gas supply he believed two things were
necessary: setting a timeframe (the next year or year
after) and how tightly to constrain the activities.
Representative Wilson believed the current gas under
production would last for 10 years. She wondered if the
changes made in the House Resources Committee were
sufficient or whether the changes did not go far enough.
She understood that they should not wait until 2022 when
most of the credits went away.
Mr. Mayer agreed that broadly speaking when considering the
gas in the ground, 10 years' of gas was accurate. However,
there was an important distinction to be drawn between
existing mature fields, which may have that in total, but
are unable to produce at the current plateau rate to meet
the full demand for the full 10 years; the fields were
likely to go into decline at some point. Therefore, it
would be important to ensure there was incremental
additional production. He detailed that some of the
incremental production had already occurred in Furie's
Kitchen Lights field - but the exact capacity was currently
unknown. He surmised that perhaps there could be 5 to 10
years in supply.
Representative Wilson reiterated her question about action
taken by the House Resources Committee.
Mr. Mayer answered that it came down to a judgement call
based on priorities. The initial CS focused on maintaining
the NOL credit. He believed the reason the committee had
made that decision was because the NOL credit applied only
to new developers or explorers. He detailed that the
original bill aimed for support to go to new developers and
not mature fields; however, the CS factored in that a
particular company invested in Alaska due to the current
tax regime (the company represented the bulk of the gas
supply for Southcentral at present) and aimed at not
pulling the rug out. He remarked that it was a much more
expensive decision to make in terms of impact. The House
Resources Committee bill version maintained only the NOL
credit and restricted it to significantly fewer players on
a limited basis. However, a similar level of support
(provided under the CS) through the capital credit was
applicable to much broader work including work that was
probably economic without it. The question was about how to
weigh the different things in making the decision.
10:55:11 AM
Representative Wilson asked how much more money they were
talking about in the latter years. Mr. Mayer replied that
the question related to the cash impact to the state could
only be answered by the Department of Revenue; the details
needed for the calculation required confidential taxpayer
information.
Representative Pruitt stated that Cook Inlet was a
different discussion than the North Slope. He believed
interchanging the two systems and the intent of the two
systems made the issue difficult. He surmised that from the
state's perspective, the intent of the North Slope was to
generate revenue for the state; whereas, the intent behind
Cook Inlet was to provide gas for the economic stability of
Southcentral. He believed they ended up skewing the two
different systems and the purposes behind them. He referred
to discussions within the legislature about whether it
could allow Cook Inlet to go back to a free market system.
He thought that a free market scenario had existed prior to
the passage of the Cook Inlet Recovery Act by the state
legislature in 2010. He detailed that the state had offered
incredible incentives including no tax, royalty changes
depending on production, and other; however, it did not
increase investment by companies. He asked how reverting to
a free market system would impact the state. He wondered if
they would find themselves back in the same situation that
had not worked before.
Mr. Mayer replied that it was unknowable what would
actually happen due to the numerous variables. He clarified
that the credits were not the only thing that changed in
the period of declining production and rolling brownouts; a
significant number of changes had occurred during that
time. The single biggest change during the period was the
natural evolution in the life of any basin where the
investment became steadily less material over time, the
investor became less interested in doing the intensive
workover work required to maintain the asset, and they
eventually divested from the asset, at which point a new
company came in. He explained that the scenario happened in
all mature basins worldwide. He believed the transition
occurred in Cook Inlet at a particular time and was aided
and abetted by a couple of things including low gas prices.
With the transition of ownership came the following: a
change in the way the Regulatory Commission of Alaska (RCA)
had to approach gas pricing decisions; the consent decree;
and a multitude of things that changed the pricing picture.
He mentioned development of storage and what the seasonal
nature of demand meant for how gas could be delivered. All
of the items had been key building blocks in creating a
more stable gas supply. He concluded that credits had been
important but were not the only thing that had changed.
Given those things and if it was true that drilling in
mature fields was economic in a wide range of environments,
he considered whether it required the credit to continue at
the current level or if it could be changed to a past
level. He believed many things had changed since a time
when the system should have been economic, but companies
were not lining up to invest.
Mr. Mayer discussed that the impact of a substantial move
towards a more free market approach was unknowable in many
ways. He furthered that it was hard to look at the numbers
on slide 31 and think (particularly related to mature
fields) that there was not still substantial incentive for
an existing investor to continue. More than anything else,
for an existing investor to want to continue the work, it
required certainty about the stability of the future of the
system as much as anything. He elaborated that the question
of developing new resources went back to the issue of
constrained demand; there may be some role for more
targeted support to enable the new development to occur,
understanding that it was effectively a state investment in
spare capacity that was not currently needed; however, it
would be needed in the future in order to avoid a
disruptive transition.
11:01:11 AM
NIKOS TSAFOS, PRESIDENT AND CHIEF ANALYST, ENALYTICA (via
teleconference), agreed with Mr. Mayer's statements. He
spoke about free market that included a certain amount of
instability and uncertainty, which resulted from depending
on the market. The question really was whether or not
policy makers, the public, and the market participants were
comfortable with the uncertainty. For example, there was a
large boom in shale gas production in the Lower 48 but gas
price had also gone to $12 at which point "everyone came
out of the woodwork to start producing more shale." He
furthered the way the market worked meant there may be
periods of time where there were very high prices in order
to incentivize the desired type of behavior. In a mature
basin there was a natural transition from long-term
contracts to shorter-term contracts; in many ways the
scarcity of gas in the Cook Inlet was really a perception
of scarcity. He elaborated on the idea that companies had
previously been able to get 10 to 20-year contracts with
all the desired flexibility and were now only able to get 2
to 4-year contracts. He expounded that it was not
necessarily that they were not able to get gas, but it was
necessary to adjust to a completely different mindset in
terms of how the resource was managed. He addressed slide
44 titled "Gas Prices have Risen Considerably Post 2004."
He discussed that the slide at the beginning of the meeting
put about $400 million of credits into Cook Inlet. He
explained that Cook Inlet had produced about 100 bcf in the
previous year; at the prevailing gas price of $6.00, Cook
Inlet brought in about $600 million - the state had
provided support for $400 million. He explained that that
the state was also supporting oil in addition to gas and
new development in addition to existing resources. He
clarified that it was not that there was a $600 million
market and the state supported $400 million, but the
figures provided a sense of the magnitude. It was clearly a
market that did not function quite properly.
Mr. Tsafos detailed that in relation to that market there
were three levers that could be pulled. The first lever was
fiscal (e.g. credits and other) and the second lever was
price. He referred to an image of the prevailing value of
gas in the Cook Inlet (slide 44) and noted that the price
went up briefly around 2008, but overall since about 2007
the price had been fairly flat. He questioned whether the
price really reflected the scarcity of gas in the Cook
Inlet. He elaborated that it was hard to look at the price
and believe that it captured all of the nuances of the
scarcity of supply and demand. The third lever was
regulatory - regulatory options that countries around the
world had used to create stronger markets and strengthen
competition. He referred back to the $400 million to $600
million comparison and surmised that based on the three
levers, the system was weighted heavily towards fiscal. The
relevant question was not so much about how to change the
fiscal lever, but how to think more generally about
rebalancing the policy toolkit in order to make the market
function better. He emphasized that it was important to
think about options outside of the fiscal lever because
there were other things a sovereign could do to increase
the functionality of the market. At the end of the day,
there was potential supply, but there was not really
demand; therefore, it was important to think about how to
use fiscal policy to develop a better market.
11:06:06 AM
Representative Pruitt thought it was appropriate to define
the situation as a constrained market. He believed it was
probably appropriate to put Cook Inlet in the constrained
market category. He reasoned that the market was
constrained for reasons beyond the fiscal consideration. He
elaborated that in the past when there had been a free
market, the market had been determined because most of it
had been utilized in a utility scenario. He opined that the
market had not truly been free - the customer had not been
paying the price the companies were willing to sell the
product for. Alternatively the Regulatory Commission of
Alaska had determined the price. In essence a certain
limitation had been placed on what the state felt the price
would be - it did not allow the free flow of the market and
eventually found itself having to pay additional amounts
because no one was making the investment. He referred to
the current conversation about the fiscal reality, which he
believed was a determination of whether or not the state
wanted to see a direct payment by the people utilizing the
gas to cover whatever it cost and whatever agreement could
come forward between the producer and individuals; or
whether or not it was a statewide priority to incentivize
through fiscal scenarios (i.e. credits or royalty
reductions) to ensure that gas supply remained available at
a reasonable rate for Southcentral customers. He asked for
the accuracy of his remarks.
Mr. Mayer agreed. He believed the point related to the
three fundamental policy levers that could be used to
address the situation. The Cook Inlet Recovery Act did
certain things in terms of the way the RCA made pricing
decisions, but overwhelmingly the weight of the current
policy response was on the fiscal subsidy lever. He
estimated that production was closer to 80 bcf rather than
100 bcf in terms of what was actually consumed in the
state. He continued that $400 million in subsidy was almost
all of the value of the gas. He remarked that it was quite
stunning to think about how much was paid out in credits.
He reasoned if the aim really was about security of gas
supply, it was currently possible to buy almost all of the
gas for the amount currently spent on credits. Whether the
state could instead rely on a better approach to market
pricing (other things could be done on the regulatory
structure of the market) became difficult because one of
the biggest impediments was a lack of competition -
currently the Cook Inlet market had only one major player
and because of the structure of limited demand, there was a
limited ability for new companies to come in. Regulatory
interventions to change the scenario had been utilized in
many other places, but those systems also created winners
and losers by definition. The issues needed to be thought
about very carefully when considering how to create a
structure that could move closer to a free market world and
rely less heavily on overwhelming government support.
11:10:32 AM
Mr. Tsafos agreed that there were options to think about to
create better markets, which was the kind of policy that
created winners and losers in terms of creating demand by
looking at market share or requiring a certain number of
contracts for a diversity in supply. He clarified that he
was not suggesting the strategies necessarily needed to be
undertaken by the state, but there was a question about the
regulatory leg of the policy; thus far it had been heavily
weighted towards the fiscal. There were jurisdictions that
completely ignored both fiscals and regulatory and
basically only manipulated the price. He explained that
Alaska was not unusual for relying one of the levers more
than others, but as part of a well balanced approach he
thought it was important to consider how to reallocate the
emphasis.
Representative Gara referred to the discussion about
winners and losers. He remarked on the state's $4.4 billion
deficit and explained that there were currently many people
on the losing end who could barely handle the burden of the
budget (e.g. individuals with disabilities and other). He
did not know how much the state could afford to just be
nice to the oil and gas industry due to the state's large
deficit. The state had adopted a gas storage credit, which
had benefitted Cook Inlet well. Additionally, the state had
changed the RCA rules so producers could charge more for
their natural gas. He addressed that the system was
currently demand-constrained (people did not need the gas),
which was deterring exploration. He believed that the idea
of adding extra subsidies was operating under the
assumption that companies needing natural gas in the future
were not smart enough to contract with explorers to look
for the next level of supply on their own. He asked if the
state could trust that at some point those needing natural
gas could contract with companies to look for natural gas.
He asked if the tax credits would change the behavior.
Mr. Mayer answered that his focus on the comments was less
on exploration than it was on development of known but
undeveloped resources. He believed there was a pure free
market solution to the problem, given enough time and
willingness to survive market volatility. For example, if
there were rolling brownouts and substantial gas shortage,
it would at some point become economic to develop the gas
phase at Kitchen Lights (a known, undeveloped resource that
would require substantial investment to bring online). The
question then became about what the volatility and
disruption would be if left to the free market and how well
the free market could solve the problem. Alternatively,
from a government policy perspective if the state provided
additional subsidy to enable those things to occur,
compared to the amount of money currently spent on the
credits, how to develop known but undeveloped resources was
a much smaller piece of the current picture. He believed it
was reasonable to ask what amount of support was required
to assist some of the work that may not otherwise occur
(and may not occur without an additional source of demand)
as opposed to providing blanket credit by subsidy for a
very wide range of activities that may have nothing to do
with developing known but undeveloped resources.
Representative Gara appreciated the remarks and hoped it
was the perspective the state moved ahead with. He noted
that every $50 million the state could save in unnecessary
subsidies was something that mattered to the state. He
furthered that the laws [providing subsidies] had been
passed with the idea of encouraging Cook Inlet natural gas
production for local use. He furthered that many of the
subsidies were being spent for oil, which had not been
intended to get the breaks. He noted that the oil was
paying no production tax. He continued that many of the
credits were going to ConocoPhillips for its export
facility to export gas that it made money on and paid no
production tax for. At some point he hoped the advisers
could help the state be as conservative as possible in
deciding which tax subsidies it should pay for under its
current budgetary circumstances. He reasoned that every
dollar going towards something it did not need to go
towards was being taken away from someone else. He asked
the advisers to consider whether the state really needed to
incentivize oil and export facilities that it never
intended to incentivize. He added that there were private
companies that knew when they needed to start contracting
with a company to look for their next round of supply of
gas.
11:17:38 AM
Mr. Mayer agreed that the questions were important. He
replied that it was difficult to get into the specifics
without knowing the precise confidential taxpayer details.
However, it was hard to look at the activity and not think
that a vast amount of the credits were going to support oil
that was being produced with some of the most generous
fiscal terms on the planet. He surmised that there could be
long debates about what was intended when the credits were
established and how much the credits were about providing a
"sweet" deal on oil in order to also get the gas along the
way. He believed that when looking at what the credits had
been at the time the change had been enacted versus what
they were at present and what revenues were and had been,
it had been easy to say that the state was giving some
credits away in Cook Inlet, but when considering how much
the state was making overall, it was a no brainer if it
brought supply security. He explained that it was a very
different calculation at present when looking at how much
the state was receiving and spending in Cook Inlet. He
turned to slide 43 and addressed exports. On the one hand
he believed Representative Gara was right that providing a
subsidy to ensure security of gas supply for Southcentral
was one thing, but providing a subsidy for gas exported to
Japan was a separate and more difficult conversation. He
discussed that Alaska had a seasonal structure of demand,
and supply had become steadily less able to live with the
seasonality. For the vast majority of history, the LNG
facility at Kenai had produced fairly steadily and had not
been particularly seasonal. He pointed to the chart on the
left of the slide: the red line indicated export from
October to March and the green line represented export from
April to September. He explained that the lines had
historically been similar, but had dramatically diverged in
the past couple of years. The data showed that Kenai had
become a seasonal facility and was providing some of the
swing capability that also came from storage - the ability
to moderate the natural seasonality of Alaska's demand.
Mr. Mayer addressed price and believed that one of the
things that would get difficult and put more pressure on
current prices on storage as a solution (rather than Kenai)
was related to the prices Kenai received. He elaborated
that historically the price had been $16/mmbtu; currently
the price was about $6/mmbtu. He stated that when thinking
about the price of gas in Cook Inlet and the costs involved
in liquefying and shipping gas to Japan or elsewhere, it
became much harder to see why anyone would want to keep
doing that at present. He elaborated that it was one thing
when the owner of the facility (a depreciated asset) was
also the owner of the upstream - it was possible to see how
that could work if they did not have to buy the gas.
However, an owner of the upstream facility had to buy the
gas from a producer (e.g. ConocoPhillips was getting out of
its upstream position) or the upstream producer was having
to pay the liquefaction under a toll, the economics became
much more difficult; it was hard to see how export at the
moment would continue to offer the same seasonal flex as it
had in the past couple of years.
11:21:23 AM
Co-Chair Thompson relayed that the meeting would adjourn at
12:00 p.m.
Mr. Mayer turned to slide 33 and addressed a summary
section of the presentation comparing status quo, the
original HB 247, and the CS. He addressed the North Slope
and discussed the issue of annual versus monthly assessment
of things like the per barrel credit and how it interacted
with minimum tax. The status quo would continue an annual
assessment. The change would require companies to do
something that was close to lodging their annual finished
tax return on a monthly basis; it was the sort of thing
that generated additional revenue in times of volatility -
it would have brought in an additional $100 million.
However, as far as he could see it was really more about
incremental revenue raising than about some pressing change
needing to occur in the structure of the overall system.
Mr. Mayer continued to address slide 33 and spoke to the
GVR and NOL credit. He reiterated his earlier testimony
that for new developments in times of low oil prices there
could be several years where a company could be eligible
for NOL, but producing oil making revenue. He continued
that rather than uniform 35 percent support for everyone
(in some cases a company could get much more than 35
percent support for a loss or an NOL credit when it was not
technically making a loss in certain circumstances), the
bill and CS proposed to change the system so the NOL would
not be calculated taking into account the effect of the
GVR. He observed that the change would have a substantially
negative impact on some companies. He referred to recent
testimony by Caelus Energy LLC that the change would erode
about 13 percent of the NPV of its investment in Nuna [oil
development project]. He believed it was clear that the
intent of SB 21 had been 35 percent support for government
spending across all circumstances and the proposed change
would fix that; it was not a major impact to the treasury,
but was a question about how the system was designed to
work.
Mr. Mayer addressed proposed changes to the gross minimum
tax on slide 33. The bill proposed to harden the floor for
all production, which would mean no longer letting the NOL
credit take producers with a liability below the 4 percent
floor. For new GVR-eligible production, which currently had
no floor other than zero, would also have a hard and
binding floor. Additionally, the rate would increase from 4
percent up to 5 percent. The CS maintained the status quo:
a 4 percent gross floor for legacy production with the
ability for the NOL to take the tax below that amount; and
no effective floor for GVR production. He spoke to NOL
credit reimbursement and had considered that it was really
about a benefit a company would otherwise receive later in
the tax system being brought forward at a time when a new
developer had no liability; however, there was a potential
liability to the state in the event that a major new
Kuparuk-size development was discovered.
11:25:24 AM
Mr. Mayer turned to slide 34 and explained that the
proposed change of HB 247 was a $25 million per company
limit along with restrictions on large companies (with more
than $10 billion in revenues) from being able to claim the
reimbursement credit at all. Whereas, the CS had a much
higher per company limit of $200 million. He addressed the
GVPP calculation and explained that HB 247 specified the
number could not go below zero. There had been a slope-wide
system of deduction of costs (including deduction of costs
for transport prior to calculating revenue), whereas the
change could limit the deductibility of some transportation
costs. He elaborated that the CS would maintain the status
quo. He relayed that the bulk of the refundable credit
outflow went to Cook Inlet tax credits, but only a fraction
of the state's petroleum revenue came from that region.
Cook Inlet also had a 25 percent NOL credit. He clarified
that the NOL credit was very different in Cook Inlet than
on the North Slope because it was not part of a
corresponding profit-based production tax. Additionally,
the 20 percent capital credit established under ACES
continued, but without the ACES-type production tax (only
no tax on oil, a flat gross minimum tax on gas, and a 40
percent well lease expenditure - up to 65 percent
government support for spending). The proposed change under
HB 247 was to repeal the qualified capital expenditure and
well lease expenditure credits (effective July 1, 2016) and
leaving only the 25 percent NOL credit. The focus on the
NOL was a way of specifying the state's desire to
concentrate on the new developers (not mature production)
and for the situation to take care of itself by tapering
out when people actually had production. There had been
discussion that implementing the change on July 1 had major
impacts on companies with existing capital commitments
through the next year. Therefore, the CS would implement a
phased series of changes starting in the middle of the next
year that would go into effect fully by 2018. Additionally,
the CS would continue some level of support for the ongoing
work in the mature fields - the NOL would be reduced to 10
percent, maintain a 20 percent capital credit, and
effectively phase out the well lease expenditure credit.
11:28:40 AM
Representative Gara remarked that much of the changes
largely effected small producers and explorers. He
discussed that at about $76/barrel companies paid a profits
tax of about 10 percent, which slowly rose to 35 percent at
$155/barrel); however, at prices below the 35 percent mark,
the big three companies received a 35 percent deduction of
operating and capital costs. He remarked that the deduction
was not classified as a credit, but he believed that was
what it is. He noted that small companies received a cash
payment or NOL, but he believed it was fair to say that the
big companies were getting the deduction. He asked if his
statements were accurate.
Mr. Mayer agreed. He elaborated the structure existed
because in most circumstances the companies were paying an
effective 35 percent marginal rate (the amount varied
slightly depending on price) and not an average rate. Slide
34 provided a picture of the overall system for a new field
with GVR. Legacy production had a similar amount of
government take at the $50 to $70 range, which increased by
about 5 percent at higher prices. Overall, it was still a
system that was designed to deliver between 60 and 70
percent government take; there was not an enormous giveaway
at those price levels. The purpose of the declining tax
rate at those price levels was precisely the place where
the royalty became a steadily greater share of the total.
The only way to achieve government take in that range was
to reduce the production tax within that price range in
order to compensate for the increasing royalty.
Representative Gara noted that they needed to consider
overall fairness. He wanted to bring attention to the fact
that they [the large producers] were essentially receiving
a 35 percent tax credit even though it was much higher than
the tax rate they paid at those prices.
Representative Pruitt asked if in light of the current oil
prices, there were other jurisdictions that were increasing
taxes on oil and gas.
Mr. Mayer answered that other regimes were contemplating
both increases and decreases [in taxes]. He elaborated that
jurisdictions with more diversified economies that could
survive economic downturns and were concerned about the
future and wanting to maintain a desirable investment
climate and not kill a mature industry, were looking at
reductions. Alternatively, places that were more dependent
on oil revenues may not want to increase taxes although
they may realize it was not ideal policy. For example, in
the United Kingdom (U.K.), substantial cuts had been made
to taxes in the North Sea; the cuts had been implemented by
the same government that had enacted substantial tax hikes
in 2011. The government had recognized that the hikes they
had put in place had made life difficult and could result
in a boom in decommissioning, given the mature age of the
basin. Consequently there had been very substantial cuts in
profit-based petroleum taxes in the U.K. in the current and
previous year. The purpose of the cuts had been to
communicate that the government knew it was an industry in
peril, particularly at current prices, and they wanted to
do everything possible to maintain it. He provided Columbia
as another example and explained that the government had
reduced tax and contract rates for certain offshore blocks
to try to maintain ongoing exploration despite the low
prices.
Mr. Mayer addressed the two tax increases he was aware of.
Russia had a very regressive fiscal system that took a
large share in taxes. He detailed that Russia had
previously scheduled reductions in the rates, but the
action had been postponed and they were now considering
increasing the taxes. He remarked on a recent New York
Times article, which highlighted that the current slim
profit would be taken away [if taxes were increased] and
there would no longer be capital to reinvest. The author
had specified that the situation reflected the "oil
industry equivalent of eating the seed corn." He remarked
that it was potentially a sacrifice of a significant amount
of long-term interest due to short-term desperation. Brazil
had also increased taxes. He detailed that the increase was
about a dispute between state and federal government. He
explained that royalties went to the state and the
remainder of the tax system revenues went to the federal
government. There was a dispute about the way the royalty
was calculated in Rio de Janeiro where many of the large
deep water pre-salt projects were located - the state
claimed the pricing formula used to determine the royalty
was unfair and undervalued the resource and if the federal
government would not increase the amount, the state would
levy its own state-based tax. The federal government would
not change the way it was calculated; therefore, because
the state is highly resource-dependent it had implemented
an additional tax that substantially increased the
breakeven price for the large, expensive, offshore pre-salt
fields.
11:36:45 AM
Mr. Mayer continued to answer the question. He believed
when governments that had implemented tax increases looked
at the economics of the long-term investment they did not
necessarily think the policy was ideal; however, they were
struggling with ideal policy versus the short-term needs of
the state.
Representative Pruitt spoke to Russia and its increase. He
stated that Russia still had its own national oil company
Rosneft, which would not see an impact. He wanted to know
what the state should expect if it looked at the increase
to the private sector. He wondered if the private sector in
Russia would maintain its investment or back off if
additional increases occurred. He recognized that Rosneft
did not have that implication and continued to invest
without the other challenges. He referred to a recent
Reuters article specifying that Rosneft benefitted from a
$2 to $3 lifting cost, which was substantially lower than
anything facing Alaska. He asked about the ramifications of
a tax increase. He wondered if Alaska would see a reduction
in production on the North Slope.
Mr. Mayer replied that it varied widely between the
original bill and the CS. Under the original bill depending
on how items like floor hardening, per company limits on
NOL refundability, and when and how they were applied,
could have a substantial negative impact on investment. For
instance, how the per company limit was approached and when
it was put in place in relation to the NOL credit, had a
big impact on whether it was an overwhelming negative for
the economics of smaller producers currently investing.
Related to the hardening of the [tax] floor there were
varying degrees; however, all variations substantially
increased taxes on an industry that did not have profits to
make. He believed all of those things could negatively
impact investment.
11:39:55 AM
Mr. Tsafos agreed with Mr. Mayer's statements. He
elaborated that any investor was looking at both the
current and future tax systems, which was also tied to the
fiscal health of the state. He thought much of it would
come down to what kind of risk premium the state placed on
Alaska. He referred to Mr. Mayer's earlier testimony about
making changes to a tax system in increments [and creating
uncertainty for investors]. Generally, more resource
dependent states tended to have more volatile systems
because they tried to protect themselves due to their
dependency on resource revenues. Whereas, more diversified
economies could withstand some of the ups and downs. He
stated that it should not be considered only as taxes on
oil and gas, but as the overall risk assessment that
prospective investors place on what would happen. He
elaborated that companies considering investment were
taking a 10 to 15-year bet on the broader fiscal health of
the state.
Vice-Chair Saddler asked why it was important for
constituents to understand Alaska's system of oil and gas
tax credits, what it was trying to accomplish, and what the
bill sought to change.
Mr. Mayer replied that it was important because it was
about the long-term sustainability and viability as a
resource-dependent state, about the current state of the
state's finances, and how to balance the two. He elaborated
that the long-term viability of the state required steady
reinvestment (particularly as long as the state was
resource-dependent) predominantly on the North Slope and it
required an investment climate that remained favorable to
do so. He believed that under SB 21 there had been
substantial improvement and reinvestment, which was
starting to show some results in terms of flattened
decline; he noted that the changes became more challenging
to maintain as prices declined. On the other hand, there
were aspects of the current system that created severe
financial strain when oil prices were low. The biggest part
was the sheer amount of credit subsidies in Cook Inlet; it
was hard to think the situation was sustainable. The state
also had a problem related to the timing of cash flows on
the North Slope; it was not about providing money as a
subsidy as much as it was the ordinary operating of the tax
system, but being structured in a way that payments did not
necessarily coincide with revenue.
Mr. Mayer relayed that the current system worked well in
some ways and enabled a level of government take to occur,
which may otherwise be more difficult; it provided a
benefit to companies that would not exist otherwise. The
relevant question was whether the state could maintain
those benefits or create limits in the current constrained
environment. Specifically, he questioned whether the state
would have the ability to pay out hundreds of millions of
dollars (potentially billions of dollars) in any given year
in the event a new large development was discovered.
Alternatively, he questioned whether it was necessary to
put limits in place to constrain that potential. He
believed those were the core questions needing answers at
present. There were other considerations introduced by the
bill related to the minimum [tax] floor and other ways of
raising revenues. He believed the options were a way of
recognizing that although the revenue situation was urgent,
the state may not want to get into incrementally raising
revenue if it could potentially erode investor perception
of the system stability for what was probably a relatively
small gain. He questioned whether the state wanted to
substantially raise taxes on revenue at a time when there
was no actual profit to tax and whether the decision
represented smart policy.
11:45:17 AM
Representative Wilson spoke to exploration credits and
asked if it would make more sense for the state to take on
an investor mindset prior to the start of a project in
order to determine whether it should invest in the project.
She reasoned that much of the state's revenue would go
towards the investment. She referred to the current system
where companies decided whether or not to invest and the
state became a player by default.
Mr. Mayer replied that he would not focus the conversation
on exploration credits, which essentially expired in the
current year in most cases. He noted that exploration
activity could still be supported through the NOL credit.
Where the issue became particularly relevant was in
relation to the state's exposure (predominantly on the
North Slope) through the refundable NOL credit, whether it
should be capped, and how. The bill and the CS proposed a
per-company cap on how much could be refunded. Another
option was to specify that refundability was not the norm
of the tax system, but it was something that had to be
applied for. For example, in the future a producer would
need to ask for special consideration if they could not
afford the full royalty for the first 5 to 10 years of
operation. He elaborated that it would be some type of
process where a company would present the administration
with their economics to request eligibility for the credit.
He believed the issue was a judgement question and that
there would be merit in giving it consideration.
Representative Wilson did not believe the state wanted to
stop investing in things that would provide a future
return. She asked if there were any other regimes that were
involved in deciding whether to invest in a company. She
reasoned that the state should not invest in a company that
was a step away from bankruptcy.
Mr. Mayer answered that he could think of relatively few
tax royalty regimes operating in the way Representative
Wilson suggested. By in large, tax royalty regimes apply in
more hands-off government jurisdictions and also tended to
be more diversified with a wider range of tax base. The
regimes tended to operate through the tax system because
they were interested in setting overall policy, not getting
into the details of particular projects and how to assess
them. The alternative was that many of the most resource-
dependent locations used things like production sharing
contracts and active national oil companies. Often the
contract was negotiated with the national oil company and
not directly negotiated with the government. In that
scenario, there was a very direct conversation between the
international and national oil companies about what the
economics looked like, what the terms would be, who was
investing what, and how the returns would be allocated.
That level of detail and involvement was significantly
easier to facilitate in the environment he had specified,
than through a tax royalty system. He believed the question
was if the goal was increased control over how things
worked, how much it made sense for a tax royalty system. He
reasoned that someone could make an argument to operate
that way, but it would look very different than tax royalty
regimes in many places.
11:49:57 AM
Representative Wilson was struggling with how the state
should decide whether to invest or not invest in something
that would have a huge impact in the future. She believed
it was a different conversation than Cook Inlet at present.
As a representative from the Interior, she wanted resources
to go to her region instead of being exported. She stated
that was more of a subsidy for one area compared to other
parts of the state. She believed it was even more
concerning if the state subsidized for someone else to use
the state's gas.
Representative Guttenberg believed it was appropriate for
the legislature to be considering the situation at any oil
price. He remarked that the presentation was solely on the
North Slope and Cook Inlet. He was concerned about the
Frontier Basins. He reasoned that at present they were not
major players, but at some point in the future that would
change and they would represent a critical part of the
state's economy. He asked how to keep their environment
stable and prevent hindering their explorations and
efforts.
Mr. Mayer believed the comments were very reasonable; if
current arrangements were extended for the situation he
imagined the fiscal impact would not be massive in the
broader scheme of things.
Co-Chair Thompson thanked the presenters for their
presentation. He asked members to provide any written
questions to his office.
HB 247 was HEARD and HELD in committee for further
consideration.
Co-Chair Thompson discussed the agenda for the following
meeting.
ADJOURNMENT
11:53:43 AM
The meeting was adjourned at 11:53 a.m.
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