Legislature(2019 - 2020)BARNES 124
03/20/2019 01:00 PM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| Presentation(s): Spring Revenue Forecast and Production Forecast Update | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
March 20, 2019
1:10 p.m.
MEMBERS PRESENT
Representative John Lincoln, Co-Chair
Representative Geran Tarr, Co-Chair
Representative Grier Hopkins, Vice Chair
Representative Sara Hannan
Representative Ivy Spohnholz
Representative Dave Talerico
Representative George Rauscher
Representative Sara Rasmussen
MEMBERS ABSENT
Representative Chris Tuck
COMMITTEE CALENDAR
PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION
FORECAST UPDATE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
PASCAL UMEKWE, PhD, Commercial Analyst
Division of Oil and Gas
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Spring 2019 Production Forecast," dated 3/20/19, and
answered questions.
BRUCE TANGEMAN, Commissioner Designee
Department of Revenue
Juneau, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation
entitled, "Spring 2019 Revenue Forecast Update," dated 3/20/19,
and answered questions.
DAN STICKEL, Chief Economist
Tax Division
Department of Revenue
Juneau, Alaska
POSITION STATEMENT: Answered questions during the presentation
entitled, "Spring 2019 Revenue Forecast Update."
ED KING, Chief Economist
Office of the Governor
Juneau, Alaska
POSITION STATEMENT: Answered questions during the presentation
entitled, "Spring 2019 Revenue Forecast Update."
ACTION NARRATIVE
1:10:59 PM
CO-CHAIR GERAN TARR called the House Resources Standing
Committee meeting to order at 1:10 p.m. Representatives Hannan,
Talerico, Spohnholz, Rauscher, Rasmussen, Hopkins, Lincoln, and
Tarr were present at the call to order.
^PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION
FORECAST UPDATE
PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION
FORECAST UPDATE
1:11:39 PM
CO-CHAIR TARR announced the only order of business would be
presentations on spring production and revenue forecasts by the
Department of Natural Resources and the Department of Revenue.
1:12:03 PM
MADUABUCHI PASCAL UMEKWE, PhD, Commercial Analyst, Division of
Oil and Gas, Department of Natural Resources, provided a
PowerPoint presentation entitled, "Spring 2019 Production
Forecast."
The committee took a brief at-ease.
DR. UMEKWE explained the presentation is an update from the Fall
2018 Forecast. The Division of Oil and Gas (DOG) has been
providing production forecasts since 2016 to support the work of
the Department of Revenue (DOR) that generates the revenue
forecast. Slide 2 was an outline of the presentation and he
noted there are no significant long-term differences between the
fall and spring forecasts. Slide 3 illustrated that actual
daily production was less than predicted for the first six
months of fiscal year 2019 (FY 19).
1:16:07 PM
DR. UMEKWE continued to slide 4 which listed contributing
factors for lower than expected production: warmer winter thus
lower production; operational differences such as slower well
work repairs and underperformance from one well in the Greater
Mooses Tooth 1 field.
REPRESENTATIVE SPOHNHOLZ asked how warmer winter weather
contributes to lower production.
DR. UMEKWE explained on most of the North Slope fields, high
volumes of gas are used for gas injection, and for gas lifting,
to facilitate production. In colder temperatures the gas is
denser thus it is significantly easier for compressors to
handle, inject, and move gas.
REPRESENTATIVE SPOHNHOLZ asked whether compressors overheat in
summer.
DR. UMEKWE further explained the compressors do not achieve
their nameplate [rated maximum] capacity in warmer months due to
the density of the gas; in winter months the gas is denser, and
it is easier to compress the gas and move the gas to the wells.
1:21:01 PM
REPRESENTATIVE RASMUSSEN inquired as to the timeline of the
aforementioned production.
DR. UMEKWE clarified said production was over the period from
July through December [2018].
REPRESENTATIVE RASMUSSEN restated her question:
The production process, like from where the oil is to,
does it go to [the Trans-Alaska Pipeline System
(TAPS)] in this projection, or how far along is it
going in the process?
DR. UMEKWE said what is projected is produced from the wells,
which is a combination of oil production and [natural gas
liquids (NGLs)]. In further response to Representative
Rasmussen, he said the projection reflects what goes to TAPS
with the exception of NGLs that are moved from one field to
another.
REPRESENTATIVE RASMUSSEN questioned whether the flow of oil
through TAPS is also affected by temperature.
DR. UMEKWE advised warmer fluids generally reduce impediments to
the flow.
REPRESENTATIVE HANNAN returned attention to slide 3 that
indicated a variance [between actual production and forecast
production] of 1.25 percent and surmised predictions are rarely
without a range of variance.
DR. UMEKWE recalled in the last decade on a one-year basis, the
state's forecast variance has been 1-2 percent, and on a monthly
basis, could be as high as 4-5 percent.
1:24:01 PM
REPRESENTATIVE HANNAN returned attention to slide 4 and asked
whether industry provides the data related to the expected
production from a specific well or field.
DR. UMEKWE said companies provide forecasts for the wells they
drill and announcements describing the actual production from
wells and fields; DOG generates an inhouse forecast and an
estimate for each new well, based on a range of production from
similar wells, and creates forecasts for each well.
CO-CHAIR TARR questioned whether changing climate data is
compiled and integrated into DOG forecasting.
1:26:52 PM
DR. UMEKWE said no, DOG does not forecast changes in
temperatures; however, DOG looks at several months which can
reveal a trend over a long period of time. He confirmed that
historical data for temperature exists and data on heating
degree days can be compared as one part of the equation of
impacts to production.
1:28:23 PM
CO-CHAIR TARR expressed her interest in reviewing and
understanding temperature analysis because there may be impacts
to ice roads from shorter winter seasons; further, she asked Dr.
Umekwe to provide specific analysis of year-to-year production
on a monthly basis.
1:29:14 PM
DR. UMEKWE continued to slide 5 which showed a comparison of
Fall 2018 and Spring 2019 forecasts. He pointed out there is a
downward revision of approximately 8,000 barrels of oil for
total state production in FY 19, despite a slight upward
revision for Cook Inlet production. Slide 6 illustrated that
the long-term production forecast is essentially unchanged.
Slide 7 was a summary: for the near term, there is a slight
downward revision; for the long term, the outlook is unchanged
based on information from industry and field observations.
CO-CHAIR TARR returned attention to slide 6 and DOG's long-term
production forecast.
DR. UMEKWE explained slides 9 and 10 are informational. Slide 9
indicated the land ownership and location of projects on the
North Slope. Projects illustrated have been evaluated;
forecasts for the projects 5-6 years from production are
unchanged.
REPRESENTATIVE HOPKINS asked for the timeframe for the Smith Bay
development.
1:33:59 PM
DR. UMEKWE was unsure and could not recall announcements by the
explorers as to a specific date. He described slide 10 as
follows:
So the next slide just shows all these projects that I
just showed you in the previous slide, rolled up
together, including the different risk, or layers of
risk, that we applied to those projects and the
essence of that is just to ensure that for planning
purposes, the state is not, DOR is not providing the
state with a revenue outlook that is overly
optimistic. ... So, what you see here is not a
summation of the promised rates for each of these
projects, all you see is a product generated from
applying the appropriate - what we think [are] the
appropriate - levels of risk to each of the projects.
And these volumes will be adding to, you know, legacy
production, and we know that legacy production
generally declines over time.
CO-CHAIR TARR asked whether slide 10 included the effect of less
oil production on the North Slope if gas were diverted to the
ALASKA LNG gas pipeline project.
DR. UMEKWE said no. In response to Representative Rasmussen, he
confirmed the production shown on slide 10 is in addition to
existing oil production.
1:37:10 PM
The committee took an at-ease from 1:38 p.m. to 1:42 p.m.
CO-CHAIR TARR invited Commissioner Designee Tangeman to continue
the presentation.
1:42:24 PM
BRUCE TANGEMAN, Commissioner Designee, DOR, provided a
PowerPoint presentation entitled, "Spring 2019 Revenue Forecast
Update," dated 3/20/19, which was an update to the Fall [2018]
Forecast. He pointed out forecasts are based upon information
at hand thus changes in well performance, oil price, and the
"down time" of wells affect forecasts. Currently, DOR is
forecasting about $69 per barrel - approximately $1 higher than
the Fall [2018] Forecast - and about $5 higher than anticipated
last spring. For FY 20, the oil price for the Fall [2018]
Forecast of $64 per barrel has been increased to $66 per barrel.
Commissioner Tangeman outlined the presentation (slide 2); on
slide 4 he pointed out total unrestricted general fund (GF)
revenue is down by $89 million dollars for FY 19, and up by $39
million for FY 20. He said details will be provided but
generally, prices were up, and production was down in FY 19.
Also shown was that fall and spring forecasts for the next
several years are generally unchanged.
CO-CHAIR TARR asked Commissioner Tangeman to review other
sources of unrestricted GF revenues such as corporate income
tax.
1:48:01 PM
DAN STICKEL, Chief Economist, Tax Division, DOR, explained
unrestricted nonpetroleum tax revenue included: corporate
income tax, mining license tax, excise taxes; a variety of
licenses and permits; charges for services, fines, and
forfeitures; nonpetroleum rents and royalties; miscellaneous
revenues.
CO-CHAIR TARR recalled corporation income tax represents the
highest percentage of nonpetroleum tax revenue, followed by sin
taxes, gas tax, and other sources that provide the final
modicum.
MR. STICKEL referred to the Spring Revenue Forecast Update, page
6, that indicated of unrestricted nonpetroleum revenues, the
taxes portion is forecast to be approximately $350 million per
year out of a total of $550 million [document not provided].
REPRESENTATIVE HANNAN clarified that the aforementioned gas tax
is [motor fuel tax, not a production tax on gas].
MR. STICKEL, in response to Representative Hopkins, restated
corporate income tax is estimated to bring in $120 million in FY
19, and $135 million in FY 20, from nonpetroleum companies.
REPRESENTATIVE HOPKINS asked which nonpetroleum revenues are
decreasing.
MR. STICKEL explained the decreases in nonpetroleum income tax
are based on weakness in payments and lower minerals prices
(slide 5).
REPRESENTATIVE HOPKINS questioned whether [the decrease in
nonpetroleum revenue] is related to other extraction industries
or industries that are not related to mineral extraction.
MR. STICKEL said nonpetroleum corporate income tax includes
revenue collected from any corporations that are not oil and
gas; the largest sector contributing to nonpetroleum income tax
revenue is mining and mining-related industries.
REPRESENTATIVE HOPKINS surmised nonpetroleum revenue is expected
to continue to decrease over the next ten years.
MR. STICKEL said DOR is forecasting fairly stable revenue from
nonpetroleum sources. In further response to Representative
Hopkins, he advised DOR has some economic growth built in to the
forecast, along with inflation.
1:52:39 PM
COMMISSIONER TANGEMAN remarked (slide 4):
If you were showing a decreasing revenue stream, you'd
see those numbers getting larger and larger to the
red. As you can tell, they've just kind of reset to a
lower number but they're steady still. So, this is
just a ten-year forecast based on the information that
we currently have, and we currently know. Any policy
changes, or political issues, we don't put into these
forecasts ... so this is purely just what we know that
is in front of us at the time.
REPRESENTATIVE HANNAN questioned whether oil and gas industry
corporate income taxes are not included because oil and gas
companies can use corporate income tax deductions when
calculating the amount of tax owed.
MR. STICKEL explained DOR has two statutes for corporate income
tax: one statute applies specifically to oil and gas extraction
and pipeline companies, and has the same tax rate table, but a
different apportionment factor, and is reported separately. In
further response to Representative Hannan, he said for the
purpose of corporate income tax, petroleum corporations report
worldwide income apportioned to Alaska based on Alaska's share
of their worldwide production, property, sales, and tariffs;
nonpetroleum corporations report their U.S. water's-edge income
apportioned to Alaska based on Alaska's share of their U.S.
property, payroll, and sales.
CO-CHAIR TARR recalled past proposed legislation that was
related to the difference [in apportionment] which she
characterized as "a multi-billion-dollar distinction and has
been a significant point of contention in the past."
1:55:48 PM
MR. STICKEL affirmed at one time Alaska utilized separate
accounting for oil and gas.
REPRESENTATIVE RASMUSSEN asked whether mining prospects, such as
Donlin [Gold Project], are included in nonpetroleum revenue.
MR. STICKEL said Donlin or Pebble mine projects are not included
at this time. He continued to slide 5, which listed some of the
reasons for changes in the FY 19/FY 20 unrestricted revenue
forecast. Although oil price has slightly increased, the FY 19
forecast was reduced by $89 million primarily due to a reduction
in the oil and gas production tax of $80 million, and he
elaborated. Also, nonpetroleum corporate income tax was reduced
as previously discussed: royalties increased by $8 million and
a variety of smaller changes accounted for a reduction of $2
million. The FY 20 forecast was increased by $39 million,
primarily due to an increase in production tax, and by an
increase in royalties that was offset by a $15 million reduction
in nonpetroleum corporate income tax [as previously discussed],
and reductions to a wide variety of sources.
2:00:28 PM
CO-CHAIR TARR asked what sources are used by DOR to forecast
prices for mineral commodities.
MR. STICKEL explained DOR references the futures market; at the
time of the fall forecast, the futures market indicated stable
or increasing prices for minerals such as zinc.
CO-CHAIR TARR questioned whether there is a "true-up" of mineral
prices.
MR. STICKEL said not on a regular basis.
COMMISSIONER TANGEMAN directed attention to slide 7 which was a
price forecast summary; the Fall 2018 Forecast was about $68 per
barrel for FY 19, $64 per barrel for FY 20, and $77 per barrel
for FY 28. He recalled a period of fluctuating prices during
the winter of 2018 and cautioned that lawmakers must make budget
decisions based on a responsible revenue forecast. Because of
DOR's work in the fall, he noted the administration and DOR
decided to base its Fall 2018 Forecast on the Spring 2018
Forecast. Commissioner Tangeman stressed the importance of
supporting each forecast with history. Therefore, the Spring
2019 Forecast is based on eight or nine months of actuals, which
year-to-date are around $69 [per barrel], and to align with the
current futures market price from [New York Mercantile Exchange
(NYMEX]). He advised NYMEX has been shown to be one of the
better methods to gauge short-term oil prices; however,
additional sources are included for long-term decisions (slide
8).
2:07:15 PM
REPRESENTATIVE HOPKINS asked how accurate forecasts were from
2009-2019.
COMMISSIONER TANGEMAN said DOR would provide the requested
information.
REPRESENTATIVE HOPKINS returned attention to slide 8 and asked
how Alaska North Slope (ANS) price "tracks" with [Brent Europe
crude oil (Brent)], [West Texas Intermediate (WTI)] and the
refining market for oil from TAPS.
COMMISSIONER TANGEMAN explained ANS tracks fairly well with
Brent [the price for oil that is also transported by tankers]
and has shown a "significant [performance] delta" to WTI for
several years. [Lower WTI oil price] is due primarily to the
amount of oil that is constrained by how the oil must get to the
market, for example, in North Dakota companies were transporting
oil by railcar. However, ANS [oil price] compares fairly
closely to Brent [oil price]. He opined if a pipeline system
opens in the Lower 48, WTI [price] will increase closer to ANS
[price] as opposed to ANS going down to WTI. Another factor is
the amount of shale oil that is currently affecting price
fluctuations; in fact, there are no expectations of $90-$100 oil
price, and the realistic price is expected in the $50-$70 range.
REPRESENTATIVE HOPKINS remarked:
With ANS tracking at Brent, being higher than WTI, we
sell our ANS into the WTI refining market, right? Or
is that wrong? And then how does that price
discrepancy compare to each other when we're trying to
sell our ANS in competition with a lower price oil.
2:11:02 PM
ED KING, Chief Economist, Office of the Governor, further
explained oil produced in Alaska is shipped from Valdez
primarily to Los Angeles, California, and Anacortes, Washington,
for refining. The West Coast refineries only accept oil from
other water-borne sources because there are no pipelines that
cross the Rocky Mountains; thus, WTI oil does not enter the West
Coast market, which explains why ANS is closer in price to
Brent. Recently, the amount of shale oil available has reduced
the volume of imported oil and the WTI market "stands on its
own, so it's not reacting as much to the rest of the world
market." However, when the pipelines open, the WTI market will
move up to the global market for crude. For the most part, the
ANS and WTI markets are separate.
REPRESENTATIVE RAUSCHER asked whether industry agrees with DOR
on its oil price forecast.
COMMISSIONER TANGEMAN declined to speak for industry.
MR. KING related BP, ConocoPhillips Alaska, Inc., and ExxonMobil
Corporation publish an annual outlook of supply and demand
factors from which one can ascertain their expectations;
however, the oil price companies use as a hurdle price to
sanction a project differs from a price prediction. The
Department of Revenue studies the marketplace each day to see
what the actual price is as reflected by NYMEX.
REPRESENTATIVE SPOHNHOLZ returned attention to slide 4 and
pointed out unrestricted GF for nonpetroleum revenue [shown as
$548 million] differs from that of the Revenue Sources Book,
which shows mid-$350 million.
2:15:34 PM
MR. STICKEL explained unrestricted nonpetroleum revenue shown on
slide 4 includes funds for total unrestricted nonpetroleum
revenue, except federal investment of $469 million - forecast
for FY 20 -, of which $344 million is tax revenue; in addition,
the tax division adds unrestricted investment revenue other than
the Permanent Fund draw of $79.6 million.
CO-CHAIR TARR asked whether [unrestricted investment revenue]
accounts for the constitutional budget reserve (CBR) earnings.
MR. STICKEL said no; CBR is designated revenue. The amount in
FY 20 of $79.6 million represents earnings on the general fund
(GF). In further response to Co-Chair Tarr, he clarified the
general fund maintains a balance of approximately $2 billion,
which is invested in liquid investments and earns a small
return.
MR. KING directed attention to slide 9. He said the information
presented was intended show different factors that can influence
oil market prices, such as future demand or a recession. In the
case of a recession, there is a decrease in demand and oil
prices would go down. Currently, prices are depressed because
of the uncertainty about the trade dispute with China. Other
near-term factors include new energy resources and the
production of shale oil. In the long term, factors include more
efficient technology, which reduces demand, increases supply,
and lowers price. Mr. King said, " And then there's the things
that we just don't know, and they're on the radar, but you can't
predict what's going to happen when you're talking about ...
geopolitical factors that are going on - those things disrupt
the market in a very meaningful way ... but you can't predict
when ...." He characterized DOR's forecast as the average of
all the possible futures.
2:20:59 PM
REPRESENTATIVE RASMUSSEN asked whether the projections have a
margin of error.
MR. KING explained forecasts are driven by two types of
uncertainty: (indisc.) risk that cannot be reduced because it
is unknowable; uncertainty that can be reduced by measurement.
He said in the oil, commodities, and stock markets, a portion of
the amount of uncertainty cannot be reduced; in fact, the error
for predicting the price of oil can be 40 percent.
REPRESENTATIVE RASMUSSEN pointed out in 2009, the predicted oil
price for 2019 was $90-$100 per barrel, which was off by about
40 percent.
REPRESENTATIVE HANNAN directed attention to the potential
microeconomic driver of vehicle efficiency and asked how much
petroleum is produced for gasoline and diesel [fuels] (slide 4).
2:24:14 PM
MR. KING acknowledged the biggest use of petroleum is for
transportation fuel including vehicle fuels and aviation fuels;
however, the effects of vehicle efficiencies and possible
conversions to electric vehicles may be offset by the
possibility of a growing demand in certain areas of the world,
and both situations are unknown. Mr. King continued to slide
10, which illustrated a range of potential oil prices forecast
by the U.S. Energy Information Administration (EIA). The high
case of prices at $120 and above reflected prices as a result of
a possible catastrophic event. The low case of prices at $40
reflected prices as a result of overcapacity following a
disruption. He said DOR's spring revenue forecast has taken a
weighted average of prices - close to EIA's reference case,
albeit a slightly different interpretation. Referring to
Representative Rasmussen's comment, he pointed out marketplace
indicators such as NYMEX tend to overemphasize the effect of
short-term current events, thus DOR seeks to avoid the effect of
current events and focus on long-term factors.
MR. KING continued to slide 11, which illustrated projections
and forecasts by investment analysts. A group of analysts
forecast a range of oil prices from high to low and the DOR
Spring 2019 forecast falls in the center. Slide 12 illustrated
short-term forecasts by NYMEX, analysts, and EIA Short-term
Energy Outlook, adjusted for inflation.
2:30:54 PM
REPRESENTATIVE HOPKINS noted production projections were off by
1.65 percent and asked whether that is an average
[deviance](slide 14).
COMMISSIONER TANGEMAN deferred to DNR. In response to Co-Chair
Tarr, he confirmed DNR provides DOR production forecast
information.
COMMISSIONER TANGEMAN explained in a net tax structure,
operating costs, capital costs, and transportation costs are
deductible thus it is important to understand the effect of the
range of potential investment. He opined east and west of
Prudhoe Bay, there are resources, but resources away from the
main trunk pipeline are more expensive to explore, produce, and
transport. Alaska's current stable oil tax system has brought
private sector investment to the state to explore and produce
new fields.
MR. STICKEL continued to slide 16 which illustrated ten-year
forecasts of capital expenditures on the North Slope for spring
FY 19 and fall FY 18. For existing production, producers are
maintaining fairly stable capital spending; however, the
spending increase forecast from FY 18-FY 21 is indicated due to
costs associated with several new fields, such as Greater Mooses
Tooth, Pikka, and Willow. He advised the additional production
will require billions of dollars of industry investment; the
change from [the fall forecast to the spring forecast] was after
DOR further examined the producers' reports and tax filings.
Slide 17 illustrated operating expenditures are stable up to FY
23-FY 24, at which time there is an increase.
2:35:54 PM
REPRESENTATIVE HANNAN asked whether all capital expenditure
costs are deductible from a producer's net tax structure.
MR. STICKEL said yes, in the year earned; unlike an income tax
with a depreciation schedule, producers are able to deduct their
entire capital cost in the year earned. If a company does not
have enough offsetting production, it earns a carryforward lease
expenditure.
REPRESENTATIVE HANNAN surmised a well may be expensive to bring
online, but if it underproduces, the state earns nothing.
MR. STICKEL explained production tax on the North Slope is
assessed on a company-wide basis; for example, if a company
drills a new well it would use the cost of developing the new
well to offset against production [taxes] elsewhere.
REPRESENTATIVE HANNAN concluded there is no risk to a producer
[to develop a marginally profitable well] because an existing
producer has other wells that are profitable.
COMMISSIONER TANGEMAN cautioned there is always an investment
risk to a company's return on investment, especially when there
are other opportunities. He said, " ... I don't think anybody's
looking to invest a dollar hoping to break even."
MR. KING pointed out if a company [in the aforementioned
example] doesn't have any other production and it invests a
dollar for a loss, the state doesn't make any money and the
company loses its investment; if the company has other
production in Alaska, the state loses 35 cents and the company
loses 65 cents.
2:39:19 PM
CO-CHAIR TARR suggested the oil tax equation should be reviewed
and remarked:
The oil tax equation ... [is] the wellhead price minus
the transportation cost then, minus the capital
expenditures, minus the operating expenditures. The
capital and operating are considered the allowable
lease expenditures. Then the total after that is the
PTV, or production tax value and then you apply the
tax after that you take the PTV times 35 percent. And
then, that remaining value would be the tax that's due
to the state except you apply the per barrel credit
after that, and right now the per barrel credit ... is
$8.00, which once you apply the per barrel credit,
makes that number negative. And so our tax system is
set up so you do [an] either/or, so the alternative is
the minimum tax ... if you do the minimum tax you do
it by that number that comes after transportation, the
wellhead minus transportation is the GVPP, the gross
value at the point of production, and so you do that
number times 4 percent ... that's what our minimum tax
is right now, and so we're mostly paying at the 4
percent ... which is about $2 per barrel in production
tax. ... Slide 16, was, you know, capital lease
expenditures, that's one section of that deduction,
and the next one is operating lease expenditure,
that's another section of that deduction, and then the
third one is transportation costs, that's the other
deductible amount. And one of the challenges is ...
those transportation costs to get from the point of
development into the TAPS line, are going to become
more, right, as the developments are farther away.
CO-CHAIR TARR posited the example of transportation costs for
the Smith Bay development, which is approximately 124 miles from
TAPS.
2:42:11 PM
REPRESENTATIVE HANNAN inquired as to what price per barrel would
cause a change from the minimum 4 percent tax to the production
tax.
MR. STICKEL observed the "crossover point" varies between $60-
$65 per barrel.
COMMISSIONER TANGEMAN continued to slide 20 which illustrated
cashable credits liability and appropriations for payment. The
state is no longer accruing cashable credits as a liability due
to changes in oil and gas tax law. In FY 19, there was a $100
million appropriation to pay tax credits, and for FY 20, DOR
estimates an appropriation of $175-$185 million.
CO-CHAIR TARR recalled there has been a discrepancy in how to
calculate the statutory amount needed to pay tax credits.
Previously the allocation was calculated including the
application of the per barrel credit; however, during former
Governor Bill Walker's administration, the allocation was
calculated without including the per barrel credit, which
changed the overall formula. This change resulted in an
increase in the statutory appropriation from approximately $70
million to $128 million.
2:46:04 PM
COMMISSIONER TANGEMAN returned to slide 21, which described
House Bill 331 [passed in the Thirtieth Alaska State
Legislature]. House Bill 331 established a mechanism to issue
bonds so the state could pay off the tax credit liabilities and
pay the bonds through debt service. In FY 19, $100 million was
appropriated in anticipation of the beginning of the bonding
procedure; however, a pending lawsuit has slowed the procedure
thus the state awaits an Alaska Supreme Court decision. Until
there is a final favorable court decision, DOR will wait to
issue bonds, and therefore has requested $184 million for a
statutory payment in the FY 20 budget.
CO-CHAIR TARR questioned how a favorable decision would affect
the timeline of payments.
COMMISSIONER TANGEMAN anticipates a court decision within 12
months and a return to the bonding schedule this time next year.
CO-CHAIR TARR surmised payments of $100 million in FY 19 and
$184 million in FY 20 would reduce the liability by about one-
third.
COMMISSIONER TANGEMAN said yes, the remaining liability would be
approximately $600 million.
CO-CHAIR TARR recalled the Walker Administration plan was that
[companies that are owed tax credits] would accept a smaller
payment now, rather than wait for a full payment later.
COMMISSIONER TANGEMAN said yes, the state would be held
harmless.
REPRESENTATIVE HANNAN asked if the $184 million appropriation is
in DOR's budget.
COMMISSIONER TANGEMAN said the appropriation is in the operating
budget.
CO-CHAIR TARR asked to be notified if the administration
considers any changes to the current plans on how to address the
tax credit liability.
2:51:51 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 2:51 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES_Spring 2019 Production Forecast_DNR 3.20.19.pdf |
HRES 3/20/2019 1:00:00 PM |
Production Forecast |
| HRES_Spring Revenue Forecast_DOR 3.20.19.pdf |
HRES 3/20/2019 1:00:00 PM |
Revenue Forecast |