Legislature(2023 - 2024)SENATE FINANCE 532
03/23/2023 09:00 AM Senate FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Willow Project Update | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 23, 2023
9:00 a.m.
9:00:29 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:00 a.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Donny Olson, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Click Bishop
Senator Jesse Kiehl
Senator Kelly Merrick
Senator David Wilson
MEMBERS ABSENT
None
ALSO PRESENT
Senator Cathy Giessel; John Crowther, Deputy Commissioner,
Department of Natural Resources; Dan Stickel, Chief
Economist, Economic Research Group, Tax Division,
Department of Revenue; Owen Stephens, Commercial Analyst,
Tax Division, Department of Revenue.
SUMMARY
PRESENTATION: WILLOW PROJECT UPDATE
DEPARTMENT OF NATURAL RESOURCES
DEPARTMENT OF REVENUE
Co-Chair Stedman discussed the agenda. He relayed that the
committee would hear a briefing on the fiscal impacts of
the Willow Project on the North Slope. He mentioned the
timing of expenditures and production and the importance of
cash flow. He recounted that the committee had discussed
altering the timing of cash flows to enhance or constrain
viability of a project. He commented that the committee did
not concern itself with the federal share.
Co-Chair Stedman continued that the presentation would
address the oil and gas tax structure. He commented on the
complexity of the state's tax structure, which he
considered to be one of the most complex on the planet. He
mentioned many new members and staff that would be new to
the terms and structure of the topic.
Co-Chair Stedman commented on the importance of the Willow
Project for the future of the oil basin, state employment,
and revenues. He mentioned the previous day's presentation
that had addressed a reduction in oil price and the
resultant implications. He noted that the following day the
Legislative Finance Division (LFD) would present on the
fiscal position of the state.
^PRESENTATION: WILLOW PROJECT UPDATE
DEPARTMENT OF NATURAL RESOURCES
DEPARTMENT OF REVENUE
9:04:42 AM
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, introduced himself and relayed that he would
discuss some contextual information about the Willow
Project, including a recently issued record of decision.
Mr. Crowther discussed a PowerPoint presentation entitled
"Willow Project Update" (copy on file). He made the
preliminary point that the Willow Project represented a new
era in the state. He commented that the project was
significant in terms of production, employment, and
investment. The project was a maturation of trend, along
with the Pikka Project. The projects that were full-scale
new developments with a new era of potential for the state.
He emphasized the scope and size of the investments.
Mr. Crowther added that the projects were not assured, and
thought it would be fair to say that the projects were
fragile. He noted there was ongoing litigation against the
project. He noted that the final investment decision (FID)
had not been made by ConocoPhillips. He mentioned
logistics, timelines, and costs, which were all elements
for a multi-year project such as the Willow Project.
Mr. Crowther looked at slide 2, "INTRODUCTION AND OUTLINE":
1. North Slope Units Willow Project Location
2. Ownership/Royalty Interest on the North Slope
3. ConocoPhillips Slope-Wide Activity
4. Willow Approved Development Plan and Infrastructure
5. Willow History, Timeline, and Outlook
Mr. Crowther spoke to slide 3, "WILLOW PROJECT LOCATION,"
which was an overview map of the North Slope. He noted that
the state units were in yellow. The other colors of the
units indicated ownership. The gold or orange were state
and federal leases. The green denoted fully federal leases.
The pink and purple were affected by a 1991 settlement
agreement by the Arctic Slope Regional Corporation (ASRC)
and the state that provided some shared ownership interest
in some of the leases. He noted that the red circle
represented the Willow Project, which was in the Bear Tooth
Unit, which was a federal unit in the Natural Petroleum
Reserve-Alaska (NPRA).
9:08:49 AM
Mr. Crowther referenced slide 4, "OWNERSHIP/ROYALTY
INTEREST," which showed a map with overlays. The read
outline showed the coastal plain of the Alaska National
Wildlife Refuge (ANWR), which was federally owned and had a
50-50 split of royalties between the state and federal
government. He pointed out the red circle showing the
Willow Project on the western side of the North Slope. He
highlighted the outer continental shelf, which was
federally managed, had no active leases, and from which the
state received royalties. The gold band was near-shore
federal land, which had a 12.5 percent royalty rate for
leases and was managed by the federal government, and
Through the Outer Continental Shelf Lands Act (OCSLA) the
state received 27 percent of any revenue generated.
Mr. Crowther noted that the blue band was state-owned
offshore areas with 100 percent state royalties and were
managed and leased by the state. Similarly the center of
the map showed state-owned land subject to 100 percent
royalty share.
Mr. Crowther pointed out that there were a variety of
royalty rates in the NPRA Willow project, and a 50 percent
royalty share dedicated to the Impact Mitigation Fund.
9:11:23 AM
Mr. Crowther turned to slide 5, "CONOCOPHILLIPS SLOPE-WIDE
ACTIVITY," which showed a map to illustrate that
ConocoPhillips, the proprietor and developer of the Willow
Project, had undertaken a significant amount of activity in
the state. He pointed out ConocoPhillips locations.
Senator Bishop asked about the Bear 1 exploration well
shown on the map on slide 5. He asked if the well was back
on state land in the same formation.
Mr. Crowther did not believe there was much public
statement about the project and thought it was targeting a
formation in the Horseshoe Unit.
Mr. Crowther considered slide 6, which showed a map of the
project approval and record of decision included in the
recently issued U.S. Department of Interior document. The
map showed three pads that were approved for the Bear Tooth
Unit, the infrastructure associated with the approval to
include an airstrip, operations center and the processing
facilities approved for the Willow Project. The map showed
pipelines tying into the central facilities and the ice
road that would be used to complete project construction,
which was shown in a dashed blue line.
Mr. Crowther displayed slide 7, "WILLOW HISTORY, TIMELINE,
and OUTLOOK," and discussed the permitting history of the
Willow Project. He recounted that the Integrated Activity
Plan (IAP), the federal land management plan for the area,
was approved in 2013. The Willow Project design under the
IAP and the initial environmental impact statement (EIS)
was completed in 2020. Contemporaneously, the EIS had
addressed community concerns, which ConocoPhillips sought
to meet by modifying the project. He mentioned the 2023
record of decision, which involved completion of a second
EIS as mandated by district court remand in Alaska.
Mr. Crowther discussed the development timeline going
forward and noted that initialized construction and project
activities were underway, and a lawsuit had been filed
against the approval. The state was intervening in the
matter and was in opposition to the preliminary injunction
to pause project activity while litigation proceeded. The
project permitting continued with state pipeline rights-of-
way and other authorizations. He reiterated that the FID
had not occurred yet, and ConocoPhillips announcement of
the FID was subject to its corporate policies and
practices. Potential construction, pending disposition of
preliminary injunction matters in the court, was expected
to begin as soon as the current year and continue for a
period of five to seven years.
Co-Chair Stedman mentioned the upcoming slides from the
Department of Revenue (DOR).
9:15:34 AM
AT EASE
9:16:26 AM
RECONVENED
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, introduced himself.
OWEN STEPHENS, COMMERCIAL ANALYST, TAX DIVISION, DEPARTMENT
OF REVENUE, introduced himself.
Mr. Stickel discussed a PowerPoint presentation entitled
"Willow Fiscal Analysis" (copy on file). He explained that
the presentation was broken into two parts. He would
address the first portion, which was intended to provide
foundational information to understand the background of
the state's fiscal system and some of the nuance of the
production tax calculation. He considered that
understanding the production tax nuance was foundational to
understanding some of the Willow Project impacts and how
the lease expenditures and operator investments could
potentially impact the state treasury.
Mr. Stickel continued that the second part of the
presentation would be addressed by Mr. Stephens and would
provide a detailed fiscal analysis of the Willow Project.
He referenced a white paper issued in late February, and
noted that there had been refinements to the analysis in
terms of assumptions of how lease expenditures would apply.
The analysis had also incorporated the spring forecast.
Mr. Stickel looked at slide 2, "Acronyms
ANS Alaska North Slope
Bbl Barrel
CBRF Constitutional Budget Reserve Fund
CIT Corporate Income Tax
DNR Department of Natural
Resources
DOR Department of Revenue
FY Fiscal Year
GVPP Gross Value at Point of Production
GVR Gross Value Reduction
NPR-A National Petroleum Reserve Alaska
NSB North Slope Borough
PTV Production Tax Value
SB21 Senate Bill 21, passed in 2013
SEIS Supplemental Environmental
Impact Statement
TAPS Trans Alaska Pipeline System
Ths - Thousands
Mr. Stickel spoke to slide 3, "Disclaimer":
• Alaska's severance tax is one of the most complex in
the world and portions are subject to interpretation
and dispute.
• These numbers are rough approximations based on
public data, as presented in the Spring 2023 Revenue
Sources Book and other revenue forecasts.
• This presentation is solely for illustrative general
purposes.
• Not an official statement as to any particular tax
liability, interpretation, or treatment.
• Not tax advice or guidance.
• Some numbers may differ due to rounding.
Mr. Stickel relayed that the presentation distilled a
complex system with many past changes into an easily
understood analysis, and noted that some assumptions had
been made. He shared that when going through the
introductory information as well as Willow Project
analysis, he had used aggregated data and had avoided
presenting any company-specific confidential information.
Mr. Stickel referenced slide 4, "Foundational Discussion
• Order of Operations Refresher
• Increased Investment Example
• Gross Value Reduction (GVR) Discussion and Mechanics
• Lease Expenditure Deductions
Mr. Stickel relayed that the Order of Operations
presentation had been updated since he previously discussed
the topic in earlier weeks.
9:20:09 AM
Mr. Stickel turned to slide 5, "Oil and Gas Revenue
Sources
• Royalty based on gross value of production
o Plus bonuses, rents, and interest
o Paid to Owner of the land: State, Federal, or
Private
o Usually 12.5% or 16.67% in Alaska, but rates
vary
• Corporate Income Tax based on net income
o Paid to State (9.4% top rate)
o Paid to Federal (21% top rate)
o Only C-Corporations* pay this tax
• Property Tax based on value of oil & gas property
o Paid to State (2% of assessed value or "20
mills")
o Paid to Municipalities credit offsets state
tax paid
• Production Tax based on "production tax value"
o Paid to State calculation to follow
* C-Corporation is a business term that is used to
distinguish the type of business entity, as defined
under subchapter C of the federal Internal Revenue
Code.
Mr. Stickel noted that corporate income tax was complicated
to estimate due to being based on world-wide net income
portioned to Alaska with the company's share of production,
sales, and property.
Mr. Stickel considered slide 6, "Fiscal System: Overall
Order of Operations":
Royalties (State, Federal, or Private)
Property Tax
Production Tax
State Corporate Income Tax
Federal Corporate Income Tax
Mr. Stickel explained that the worldwide income for a
company was after deducting royalties, production, and
property tax. The federal corporate income tax allowed the
state corporate income tax as a deduction.
Mr. Stickel displayed slide 7, "Production Tax "Order of
Operations": FY 2024," which showed a table with an
illustration of the production tax calculation in aggregate
for North Slope oil. He noted that the slide was similar to
what was included in Appendix B of the Revenue Sources Book
(RSB). The slide had been updated with the spring forecast
that had been released earlier in the week. He used FY 24
as an example and considered the $73/bbl oil price
forecast, the daily production estimate of 496,000 bpd, and
the $36 million in oil that was being produced each day on
the North Slope. The quantity equated to about $13 billion
over the course of the year, and the table contemplated how
the amount was taxed and split between the different cost
and profit centers.
Mr. Stickel highlighted slide 8, "Production Tax "Order of
Operations": FY 2024," which showed a table with royalty
and taxable barrels highlighted. The first step in the
calculation was subtracting royalty to arrive at the
taxable barrels amount. For FY 24, DOR estimated a little
under 24,000 bpd of royalty barrels that went to the
various owners of the resource, which was primarily the
state but included federal and private ownership. There was
about 158 million barrels of taxable production in the
year, with a value of about $11.5 billion.
9:24:57 AM
Mr. Stickel looked at slide 9, "Production Tax "Order of
Operations": FY 2024," which showed a table with Gross
Value at Point of Production (GVPP). He described that
companies subtracted transportation costs (including
tankers, pipelines) from the taxable value for a deduction
of a little under $10/bbl for a GVPP of about $63.39/bbl,
which equated to about a $10 billion gross value slope-wide
for FY 24.
Mr. Stickel addressed slide 10, "Production Tax "Order of
Operations": FY 2024," which showed a table with North
Slope lease expenditures highlighted. He noted that the
production tax was essentially a modified net profits tax.
He described the deduction of lease expenditures, which
were subtracted in the tax calculation. A company was
allowed to deduct operating and capital expenditures, with
a 100 percent deduction of capital expenditures in the year
incurred. He described allowable lease expenditures, which
were any costs directly associated with producing oil in
the unit. Deductible lease expenditures described the share
of allowable lease expenditures that could be applied
against gross value in the year incurred. In the example
provided, there was $4.6 billion of deductible lease
expenditures, and an additional $913 million in lease
expenditures that were not able to be deducted, which
represented investments by companies that were involved in
exploration and development of new fields and not
production.
Mr. Stickel advanced to slide 11, "Production Tax "Order of
Operations": FY 2024," which showed a table with production
tax value (PTV) highlighted. He described that the PTV was
essentially the net profits of the slope and was the tax
base for the tax calculation. After subtracting the
deductible lease expenditures, there was a production tax
value estimate of $5.4 billion in FY 24.
Mr. Stickel looked at slide 12, "Production Tax "Order of
Operations": FY 2024," which showed a table with the gross
minimum tax floor highlighted in yellow. He noted that
there were two tax calculations that happened side by side,
including the net profits tax and the gross minimum tax
floor. The gross minimum tax floor was not a true tax levy
but functioned like one. The minimum tax floor when oil
prices averaged more than $24/bbl in a calendar year was 4
percent of gross value. For FY 24, there was an estimated
$10 billion of GVPP, 4 percent minimum tax floor, which got
to an approximately $400 million tax floor for the fiscal
year.
9:28:53 AM
Mr. Stickel showed slide 13, "Production Tax "Order of
Operations": FY 2024," which showed a table with net
profits tax and GVR highlighted in yellow. He highlighted
the net profits tax, which started with the production tax
value. Companies were also able to subtract the gross value
reduction (GVR), which was an incentive for new
developments that allowed a company to subtract 20 percent
or 30 percent of the gross value of production from
qualifying new fields from production tax when applying the
tax rate. The deduction was for 20 percent for up to 7
years for any qualifying new field. If the field were to
consist entirely of state-issued leases of greater than
12.5 percent royalty, a field could qualify for the 30
percent GVR. With regard to the Willow field, since there
were federally issued leases, the potential qualification
would be for a 20 percent GVR.
Mr. Stickel continued that the GVR was allowed as an offset
to the production tax value before applying the 35 percent
statutory tax rate, which gave a net profits tax (before
credits) estimated at $1.9 billion for FY 24.
Mr. Stickel referenced slide 14, "Production Tax "Order of
Operations": FY 2024," which showed a table with tax
credits against liability highlighted in yellow. He
described the next step as taking the higher of the net tax
before credits and gross minimum tax floor, which would
become the tax before credits. In FY 24, the net tax would
be the higher of the two, and the $1.85 billion would be
the starting point before the company would offset per-
taxable-barrel credits. There was a $5 per-taxable-barrel
credit for any oil that qualified for the GVR, which could
be used to reduce the tax liability below the minimum tax
if the company did not avail itself of any sliding scale
per-taxable barrel credits, which applied to all other oil.
Mr. Stickel continued that currently most of the production
on the slope for the older fields had a sliding scale
between zero and $8 per-taxable-barrel of oil. The $8
credit was available when the gross value per barrel was
less than $80/bbl. In FY 24, since the gross value per
barrel was estimated at $63/bbl, there would be an $8
credit on the sliding scale. The sliding scale credits
could not reduce below the minimum tax. In FY 24 there was
a total impact of about $19 million for the GVR $5/bbl
credits and about $1.1 billion for the sliding scale
credits. A small amount of other credits applied against
liability, which were primarily small producer credits. The
tax after credits was a little over $700 million.
9:33:01 AM
Mr. Stickel turned to slide 15, "Production Tax "Order of
Operations": FY 2024," which showed a table with
adjustments and total tax paid highlighted in yellow. He
mentioned the forecast for production tax included in the
RSB. He explained that adjustments included any prior tax
payments from the previous year, a small tax on private
landowner royalty, tax on North Slope gas, Cook Inlet
taxes, and the nickel per barrel conservation surcharge.
The adjustments added up to about $29 million to get to the
$741.8 million, which represented the production tax
forecast in the RSB.
Mr. Stickel considered slide 16, "Example: Company with
200,000 Barrels Per Day Taxable Production," which showed
the same format as previous slides using a hypothetical
producer to illustrate how increased investments would
impact the tax calculation. There was an assumption of
200,000 bpd of taxable production, which was the same
assumption used in the upcoming Willow Project analysis.
The assumption included average North Slope lease
expenditures. In the example, the company would have $4.6
billion of gross value, $2.1 billion in lease expenditures,
and a production tax value of $2.5 billion. The company
would be able to apply the full value of the per taxable
barrel credits in the year incurred and would realize the
full $5 for the GVR credits and the full $8 for the sliding
scale credits. After applying the credits, the company
would have a tax liability of $287 million.
Mr. Stickel continued to say that since the company was
able to apply all the lease expenditures in the year
incurred, there would be no carry-forwards earned.
9:35:56 AM
Mr. Stickel displayed slide 17, "Example: $200 million
additional Capital Expenditure," which addressed the chart
from the previous slide with the consideration of a nominal
increase in expenditures. For the example, there was an
extra $200 million in expenditures including some capital
improvements in an existing field or some exploration. The
company now had $2.3 billion in lease expenditures and had
production tax value that went down from $2.5 billion to
$2.3 billion. The company was still able to apply the full
value of the per-taxable-barrel credits to reduce tax
liability, and would get a 35 percent benefit from the
additional capital expenditures. He quantified that the
$200 million in extra expenditures reduced the company's
tax liability in the year it was incurred by $70 million,
which was a 35 percent benefit and was the marginal tax
rate.
Mr. Stickel highlighted slide 18, "Example: $1 billion
additional Capital Expenditure," which showed a table
depicting a company that made a more substantial investment
and spent an additional $1 billion. In the example, the
company would have $3.1 billion in lease expenditures,
would reduce the production tax value from $2.5 billion to
$1.5 billion. The tax before credits on the net side was
only $500 million, and the minimum tax floor would limit
the company's ability to apply for taxable barrel credits.
The gross minimum tax floor would be the tax liab8ility for
the year.
Mr. Stickel continued that in the example, the company
would no longer be able to benefit from the $5 per taxable
barrel for a GVR production, and it would only be able to
use $4.73/bbl of the $8 sliding scale credit to reduce tax
liability. Once the company hit the minimum tax floor,
there was no additional benefit for lease expenditures. The
extra $1 billion in spending ended up reducing the
company's taxes by $101 million, which was only a 10
percent benefit for the additional investment. Once a
company was paying under the minimum tax floor, as long as
there was a positive production tax value a producer could
not earn a carry-forward for the lease expenditures and
additional expenditures were of no value in tax
calculation.
9:39:00 AM
Mr. Stickel looked at slide 19, "Example: $2 billion
additional Capital Expenditure." He commented that the peak
spending year in the Willow analysis was a little over $2
billion. He described that the company in the example had
$4.1 billion of lease expenditures and a production tax
value of only $516 million for the year. The company would
be at the minimum tax floor before application of any tax
credits and would not use any sliding scale tax credits. In
the example, since sliding scale tax credits could not be
used, it was possible to use the $5/bbl tax credits for the
GVR-eligible production to go below the minimum tax floor.
He noted that the $26 million in credits came back into the
calculation for a total tax after credits of $160 million,
which was slightly below the minimum tax floor. He noted
that the additional $2 billion in additional spending
reduced taxes by a total of $127 million for a 6 percent
benefit.
Co-Chair Stedman asked about the benefit percent.
Mr. Stickel answered that there was a 6 percent benefit,
which was very different than the 35 percent benefit from a
smaller capital investment.
Mr. Stickel addressed slide 20, "Example: $3 billion
additional Capital Expenditure," which considered the same
scenario as previously slides with additional spending. He
noted that a similar concept would apply if oil prices were
to come in a little bit lower. The PTV was being lowered,
either by a decrease in price versus forecast, or an
increase in expenditure. In the example, the company had
$5.1 billion of lease expenditures, which would completely
offset the gross value of oil produced in the year and
would reduce the PTV to zero with $484 million of lease
expenditures remaining. The $484 million would become a
carry-forward, which could be used to offset taxes in a
future year. The $484 million would be ring-fenced by lease
or property, and could not be used unless the lease or
property was into production in the future.
Mr. Stickel continued that the minimum tax floor in the
example did apply, so the company would not be able to use
any sliding scale tax credits but would be able to use the
$5/bbl tax credits for GVR-eligible production to offset
the minimum tax. The company would pay the same $160
million tax after credits in the prior example. The $3
billion in additional expenditures would reduce the taxes
by $127 million for a 4 percent reduction in taxes paid
from the $3 billion in investment. The company would also
earn a carry-forward for the $484 million loss, which could
potentially add up to a 10 percent benefit for the
additional spending.
9:43:06 AM
Senator Kiehl asked about Mr. Stickel's assertion that the
carry-forward would be ring-fenced. He thought the fence
might be bigger.
Mr. Stickel explained that when looking at the North Slope
for tax calculation purposes, there was a slope-wide ring
fence. A company would calculate its North Slope taxes
based on all its production and spending on the slope. A
smaller ring fence on the North Slope was when there was a
carry-forward annual loss. The losses were ring-fenced by
lease or property. The carry forward was tracked by each
individual lease or property and could not be used until
the lease or property was in production.
Senator Kiehl asked if what was being described was or was
not a carry-forward annual loss.
Mr. Stickel explained that the example was that the company
spent $3 billion of additional capital beyond what was
planned. The capital expenditures were incorporated into
lease expenditure deductions in calculating PTV until it
hit zero. Once a company had applied as much as it could
deduct, if there were additional lease expenditures it
would become a carry-forward.
Senator Kiehl asked if the ring-fencing in the example was
for the unit or for the slope.
Mr. Stickel explained that if a carry-forward was earned,
it was ring-fenced by lease or property, which was
essentially by unit.
Co-Chair Stedman asked the ring-fence would apply to the
project if the example happened to be Willow or another new
prospect, and there was $3 billion in additional
expenditures.
Mr. Stickel answered affirmatively. He qualified that there
would be no ring-fencing as long as a company had a
positive production tax value. He continued that if a
company had a zero PTV and had additional lease
expenditures or oil prices turned down for a net operating
loss (NOL), the additional lease expenditures beyond PTV
would be ring-fenced by lease or property.
9:46:14 AM
Co-Chair Stedman asked about aggregated values in the RSB.
He assumed that DOR had to look at each field and do
multiple analyses to provide a comingled data set. He asked
how the legislature would know if the state was going
forward or backwards and wondered how to determine what
situations were taking place. He pondered how to make
accurate policy conclusions with aggregated data.
Mr. Stickel relayed that speaking to the revenue forecast
qualitatively, there were some NOLs that had been
generated, in particular in 2020 when there were some very
low oil prices. He considered the carry-forwards that
currently existed, which were almost entirely due to
companies making investments in new production and were not
current taxpayers. He explained that the department was
tracking the data by company and by project and assumed
that companies would apply the carry-forwards when it
benefit them to do so. The fiscal impact of carry-forwards
was baked into the forecast and much of it was towards the
end of the 10-year forecast period and beyond.
Mr. Stickel advanced to slide 21, "Lease Expenditures
Example: Takeaways":
• If company is above minimum tax floor, modest
increases in investment benefit at 35% marginal tax
rate.
• Once company reaches minimum tax floor, the benefit
of increased investment is much lower.
• Once company reaches a net operating loss, some
benefit of increased investment returns, in the form
of a carried-forward loss.
• Benefit of spending will also vary based on oil
prices.
• A low oil price scenario is very similar to a
high investment scenario.
• The changing benefits are a source of uncertainty to
company making investment decisions, and to state
revenue forecasting.
• This analysis is relevant to discussions of Willow
because the field would require massive additional
investment.
Mr. Stickel described that there was a situation that he
termed a "donut hole," in which a company benefitted from
spending above the minimum floor, and it benefited from
being in a NOL situation but did not benefit from
incremental spending while paying the minimum tax. He
commented that the difference in how spending was treated
for tax purposes made it difficult to model and forecast
for projects like Willow. It also made it difficult to
assess the impact to the state treasury, and created
uncertainty for a company in understanding the benefits of
the investments it was making.
9:49:53 AM
Mr. Stickel looked at slide 22, "Gross Value Reduction":
• Gross Value Reduction (GVR) is an incentive program
for new fields.
• Available for the first seven years of production
and ends early if ANS prices average over $70 per
barrel for any three years.
• Allows companies to exclude 20% or 30% of the gross
value from the net production tax calculation.
• In lieu of sliding scale Non-GVR Per-Taxable Barrel
Credit, qualifying production receives a flat $5 GVR
Per-Taxable-Barrel Credit.
• The $5 GVR Per-Taxable-Barrel Credit can be applied
to reduce tax liability below the minimum tax floor,
assuming that the producer does not apply any sliding
scale Non-GVR Per-Taxable Barrel Credits.
• GVR is relevant to discussions of Willow because the
field would likely qualify for this benefit in early
years of production.
Mr. Stickel relayed that he had been asked to provide some
information about how GVR worked, and the slide had been
presented in the past. He cited that the GVR was part of SB
21 tax reform that was passed in 2014.
Mr. Stickel spoke to slide 23, "Why Allow Lease Expenditure
Deductions?":
• Oil and gas exploration and development are high-
risk, capital intensive activities. There is no
guarantee of success.
• Cost recovery is critical for company investment
decisions.
• Deductions that allow companies to continue work
even when unsuccessful, make exploration and
development much less risky.
• Alaska's net tax system balances lower state take
early in field life, with higher state take later in
field life.
• Cost recovery is an integral part of a net tax
system.
• Slope-wide "ring fence" encourages reinvestment of
profits in Alaska.
• Lease expenditure deductions and GVR were designed
to help companies recover costs quickly, improving
project economics.
• Gross minimum tax floor ensures a minimum level of
state revenue regardless of investments or oil price.
Mr. Stickel relayed that he had been asked to address why
lease expenditures were allowed to be deductible. He
explained that Alaska's current tax system had several
pieces that actively supported cost recovery.
Mr. Stephens referenced slide 24, "Willow Project
Analysis
• Analysis Updates
• Description and Assumptions
• Revenue Analysis
• Uncertainty
Spring Forecast Comparison
• Conclusions
• Appendix:
1. Sensitivity Analyses
2. Local Cash Flows
9:54:20 AM
Mr. Stephens turned to slide 25, "Typical Oil Field
Development," which showed a flow chart. He emphasized that
finding and developing an oil and gas field was heavily
capital intensive, with very large upfront costs before
receiving any revenue. He noted that reaching production
could take decades. He noted that the monetary amounts
reflected how much could be spent to explore for and
develop an oil field to production for something comparable
to the Willow Project. He identified progress on the
project with the first leases in 1999, exploration around
2016, and potentially reaching major startup development in
2023. He considered a most likely first production date of
2029, which was estimated from public information.
Mr. Stephens considered slide 26, "Analysis Description
Goal is to demonstrate fiscal impact of Willow Field
development.
• Department of Revenue (DOR) Lifecycle Model allows
detailed financial analysis of a single oil
development project.
• Forecasts revenue to state, municipality,
impacted communities, federal government, and
producer
• Results in nominal dollars
• Deterministic analysis, not probabilistic,
using a single set of assumptions
• Uses publicly available data only, no taxpayer
confidential data.
• Willow federal Supplemental Environmental
Impact Statement (SEIS) (February 2023)
• Spring 2023 Forecast by DOR (March 2023)
• Use of confidential data could materially
change analysis results
Mr. Stephens displayed slide 27, "Analysis Updates":
Four component updates from February 2023 analysis:
1. Spring 2023 forecast for oil prices and
transportation costs
• Previously used Fall 2022 forecast
2. Producer receives benefit of lease expenditure
deductions only as far as minimum tax floor
• Previously producer received benefit of all
lease expenditure deductions
3. Zero impact on State Corporate Income Tax prior to
production
• Previously included negative impact on state
corporate income
4. North Slope-wide state benefit from pipeline tariff
now also includes feeder pipelines (Alpine and
Kuparuk)
• Previously only included Trans-Alaska Pipeline
(TAPS)
9:58:05 AM
Co-Chair Stedman asked Mr. Stephens to repeat the
information regarding the Alpine and Kuparuk pipelines.
Mr. Stephens relayed he would address the topic in more
detail later in the presentation and explained that
initially the Department of Natural Resources (DNR) had
modelled decreased costs to producers including only the
Trans-Alaska Pipeline System (TAPS). The new analysis
included the Alpine and Kuparuk feeder pipelines.
Mr. Stephens highlighted slide 28, "Oil Production":
• Unrisked oil production profile for 3-drill pad
development
• Profile supplied by ConocoPhillips for SEIS
• As approved by Record of Decision from US
Department of Interior, Mar 2023
• Assume first oil FY 2029
• 613 million barrels total production to FY
2053
• Peak production 183,000 barrels per day in
FY 2030
• Represents a normal oil field production profile
• High early production, with gradual decline as
reservoir pressure decreases and/or water
production rate increases
• Further drilling during production could reduce
decline, but general shape would remain
Mr. Stephens noted that all years being discussed would be
in fiscal years. He used the example that FY 24 would
extend from July 1, 2023 to the end of June in 2024.
Mr. Stephens looked at slide 29, "Lease Expenditures":
• Composed of capital expenditures and operating
expenditures
• Capital Expenditures estimated from ConocoPhillips
public statements
• $10.3 billion total, timing fitted to expected
employment
• Operating Expenditures from SEIS estimate (by
Northern Economics)
• $6.1 billion total
Mr. Stephens observed the graph showed peak production in
2028.
Mr. Stephens addressed slide 30, "Oil Prices
• Department of Revenue Spring 2023 Oil Price Forecast
• Derived from oil futures market, increasing with
inflation for years where futures unavailable
• Update from February 2023 white paper, which used
Fall 2022 forecast
• Spring 2023 price forecast lower than Fall 2022 by
$5 to $8 per barrel
10:02:12 AM
Mr. Stephens advanced to slide 31, "Transportation
(Netback) Costs
• Increased flow through Trans-Alaska Pipeline (TAPS)
and feeder pipelines (Alpine and Kuparuk) expected to
reduce pipeline tariffs
• Reduced pipeline tariff would benefit all North
Slope fields
• Analysis includes resulting increase in state
production tax and state royalty
• Does not include secondary benefit of lower
costs increasing investment elsewhere on North
Slope
Mr. Stephens noted that DNR had used the spring 2023
forecast for the net-back costs, which was shown by the
green line on the chart. The blue line removed the impact
of the Willow Project, and the red line was what was
expected to come out of using the Willow Project production
profile in the analysis. He noted that the cost to operate
a pipeline was passed on to producers through tariffs, so
the more oil that flowed through the pipeline, the less
that was paid per-barrel. The revised transportation costs
were included in the Willow Project analysis.
Co-Chair Stedman asked about the difficulty of estimating
production numbers in the later years with such high
transportation costs and lower production volume.
Mr. Stephens referred to the production profile.
Mr. Stickel noted that DOR considered a 20-year production
outlook that was provided by DNR. Beyond the outlook there
was an extrapolation of existing decline curves. In
addition to seeing the inflation on transportation costs,
the underlying assumption included inflation on oil prices.
Mr. Stephens looked at slide 32, "Fiscal Assumptions":
• Current state and federal tax laws (March 2023)
• Gross Value Reduction (GVR) at 20%, with no
producing area qualifying separately for GVR later in
field life
• State Corporate Income Tax rate 4.25% (typical North
Slope producer)
• Impact only after start of production
• Producer able to deduct lease expenditures incurred
at Willow against production elsewhere on North Slope,
but benefit of those expenditures is limited by the
minimum tax floor, until entering a net operating loss
• Assume producer's North Slope production of
228,000 barrels per day (200,000 barrels per day
after royalty) and at constant level in future
• Assume lease expenditures of $24.50 per barrel
(real) for producer's other fields on North
Slope, based on value for typical North Slope
producer
• Use of taxpayer confidential data could
materially change analysis results
10:06:27 AM
Senator Kiehl asked Mr. Stephens to address why he was not
modeling corporate income tax until production started.
Mr. Stephens deferred the question to Mr. Stickel.
Mr. Stickel spoke to the assumption of a corporate income
tax rate during construction. He explained that the 4.25
percent assumption was based on an average effective rate
for companies that paid corporate income tax, which looked
at producing companies and what was paid during
construction. He noted that during construction, any
spending would be able to offset worldwide taxable income,
and there would be an applicable depreciation schedule. The
expenditures would not offset the worldwide income entirely
in the year earned, and there would also be some impacts on
the statewide apportionment factor. He mentioned some
scenarios and identified that the amount would be closer to
zero than 4.25 percent, so it was removed from the
analysis. He summarized that the amount had a fairly small
overall impact.
Mr. Stephens spoke to slide 33, "Revenue Categories":
• State Revenue
• Production Tax
• State Corporate Income Tax
• State Share of Property Tax
• Pipeline benefit to State
• Impacted Community Revenue
• Royalty share to Impacted Communities (50%)
• North Slope Borough (NSB) Revenue
• NSB Share of Property Tax
• Federal Revenue
• Federal Share of Royalty (50%)
• Federal Corporate Income Tax
• Producer Revenue
• Company Profit
Mr. Stephens reminded that royalties were shared 50-50
between impacted communities and the federal government,
and property tax was shared between the North Slope Borough
and the state, with just over 10 percent going to the
state.
Co-Chair Stedman asked about the 50-50 split for royalty
share. He thought impacted communities had the first call
on royalties.
Mr. Stephens relayed that royalty was initially paid to the
federal government and was returned to the state for
distribution to impacted communities. Impacted communities
could request grants, which were administered by the
Department of Commerce, Community and Economic Development.
Co-Chair Stedman relayed that the legislature appropriated
the funds in the capital budget after requests from the
communities. He noted that some years there was just one
line item in the budget, and some years the amount was
listed by community. He recalled any of the grant requests
came in January or February.
10:10:37 AM
Mr. Stephens referenced slide 34, "Annual Revenue by
Category," which showed a graph of annual revenues. He
focused on the production stage of FY 29 onward. He
highlighted that revenue of all types remained strong from
production startup to the end of the 30-year analysis
period, in particular royalty and production tax. Revenues
gradually declined as production declined. The interaction
between lease expenditures, GVR, and tax credit caused some
big variation in production tax in the state benefit from
pipeline tariffs, much in the which was incremental
increases in production tax.
Co-Chair Stedman asked why the graph was not flat or
another shape.
Mr. Stephens explained that the shape of the graph showed
that upfront there were observable high capital costs of
pre-production, which was impacting the decrease in
revenue. He noted that early on in production, state
revenue was reduced to some extent by deduction of lease
expenditures. State revenue increased as the lease
deductions were decreased. There was a gradual decline due
to the decline in production towards the end of field life
as modelled to 2053. He noted it was possible that
production could extend beyond the point of the model.
Co-Chair Stedman noted that annual revenue followed
production, and asked why the annual revenue was not
horizontal instead of having big hump in the graph.
Mr. Stephens explained that generally speaking, oil
production was high early on and then declined.
Co-Chair Stedman asked "why?
Mr. Stephens explained that there was a gradual decrease in
reservoir pressure, or a gradual increase of water influx
into the wells so each well would produce less on a year by
year basis.
Co-Chair Stedman asked if the change had anything to do
with the time-value of money.
Mr. Stephens thought that generally speaking, the answer
was "no."
Co-Chair Stedman asserted that generally speaking, the
answer was "yes," since the time-value of money was
critical, and one wanted as much production in the
beginning before the economics changed. He mentioned moving
money to make marginal projects positive if possible, and
taking care not to incentivize projects that were already
profitable. He noted that many people in the building had
not seen the information, and that a gas curve looked more
horizontal relative to the graph on the slide. He
emphasized the importance of the time value of money.
Mr. Stephens discussed the drilling of the field and
getting oil as soon as possible.
Co-Chair Stedman stressed the need for explaining
information in a basic way. He thought there would be
questions pertaining to why there was so much production in
the beginning versus the end of an oil field, and why gas
was not taken off in the beginning.
10:15:37 AM
Mr. Stephens turned to slide 35, "State Revenue First Ten
Years," which showed a graph of state revenues before and
just after production started. The columns showed state
revenue from the analysis, and the dashed line showed state
revenue if the producer were to remain above the minimum
tax floor. He noted that the chart indicated that FY 24 was
the pre-production year where lease expenditures were low
enough to stay above minimum tax floor. As the forecast oil
price decreased, there was a point in FY 28 in which the
producer was already at the minimum tax floor with no
benefit from lease deductions. Total preproduction impact
on state revenue was $360 million, less than one-fifth the
amount of if the minimum tax floor was a consideration.
Co-Chair Stedman thought the graph was substantially
different than the initial report. He noted that Mr.
Stephens had mentioned that there had been updates to the
report.
Mr. Stephens agreed. He noted that the previous report from
last month had contained a simplifying assumption that the
producer would see the benefit of all lease expenditures,
which would affect state revenue and was reflected in the
dashed line. He explained that the average of $380 million
per year in pre-production was a larger number and would
have a significant impact in state revenue. The change in
the oil price forecast also affected how much impact was
seen from lease expenditure deductions.
Co-Chair Stedman appreciated the refinement. He noted that
in FY 24, there was a negative $141 million in total state
revenue. He thought Mr. Stickel had factored the change
into the spring forecast.
Mr. Stickel explained that the spring forecast included the
Willow Project on a risked basis, and the impacts on the
spring forecast would be a little lower than shown on the
slide.
Co-Chair Stedman asked if the presenters would discuss the
risking methodology. He thought the committee should
discuss the topic.
Mr. Stephens affirmed that he would discuss risking in
later slides.
10:19:54 AM
Senator Kiehl thought the price of oil was so volatile that
it would be good to see how the numbers changed with higher
and lower oil prices than were represented on the slide.
Mr. Stephens relayed that he would address Senator Kiehl's
question at a later slide.
Co-Chair Olson asked to discuss the difference between the
$72 million and the $380 million on the prior analysis from
February. He asked what would happen to the chart if the
price of oil spiked and the numbers moved away from the
minimum tax floor.
Mr. Stephens explained that he would address the second
part of Co-Chair Olson's question when there were slides
pertaining to oil price. He explained that when spending
increased, eventually there was a stage where the producer
could not use the expenses to deduct against taxes.
10:21:44 AM
Mr. Stephens considered slide 36, "Annual and Cumulative
Cash Flow," which showed a graph entitled 'Undiscounted
Cash Flows,' which combined and grouped some of the
revenues by recipient, with the addition of a cumulative
line for each recipient. He spoke to state revenue and
noted that the state hit "break even" in 2030, and under
the current assumptions had a cumulative 30-year revenue of
$6.3 billion. There was also expectation of billions in
cumulative revenue for local communities on the North
Slope, the federal government, and the producer.
Co-Chair Stedman asked when the state would break even with
cash flow, not counting the royalties that did not get to
the treasury.
Mr. Stephens noted that the 2030 number excluded royalties
and only included production tax, property tax, state
corporate income tax, and the state's tariff pipeline
benefits.
Senator Bishop asked if Co-Chair Stedman had indicated 2030
was the "break even" period.
Mr. Stephens affirmed that 2030 was the break-even point.
Co-Chair Stedman thought the previous report had indicated
2040, and commented on the substantial change in the
estimated period in which the state would start to receive
net positive cash flow.
Mr. Stephens displayed slide 37, "Net Present Value":
Net Present Value includes the time value of money
• State revenue 30-year net present value over $1
billion, going NPV positive in FY 2031
Mr. Stephens explained that net present value represented
total revenue but included the time value of money. He
noted that the NPV number gave more importance to the
negative numbers.
Co-Chair Stedman asked if Mr. Stephens was counting
negative cash flow when looking at the state's NPV. He
asked what discount he used for the state.
Mr. Stephens affirmed that DNR used the negative cashflow
as part of the calculation. In order to be consistent, all
of the discount rates were at 10 percent.
Co-Chair Stedman thought normally the state used a rate
substantially lower than 10 percent.
Co-Chair Stedman asked if Mr. Stephens had run any
sensitivity tests. He thought it was obviously positive for
the producer or it would not do the project.
Mr. Stephens affirmed that DNR could run different discount
rates as requested.
10:26:23 AM
Mr. Stephens highlighted slide 38, "Uncertainty":
• Significant uncertainty in assumptions, elevated
above typical levels:
• Project risk and timing environmental groups
currently suing to prevent field development
• Oil and gas industry costs inflation, supply
chain disruption, labor disruption, and
increasing industry development activity
• Oil price higher volatility from Russian
invasion of Ukraine and Covid-19 pandemic,
greater impact on production tax from oil prices
near to $70 (threshold for 3 years or 7 years of
Gross Value Reduction (GVR) eligibility)
• Oil production rates and reserves more
uncertain prior to development
• Available benefit of lease expenditure deductions
depends on oil prices, and on production rates and
producer's lease expenditures elsewhere on the North
Slope
• Additional project uncertainty from producer's
other fields
Co-Chair Stedman understood that the financial industry
wanted to see projects positive at a break-even price
around $60/bbl. He asked about the break-even price for the
Willow Project.
Mr. Stephens noted that there would be a couple of slides
addressing oil price sensitivities.
Co-Chair Stedman asked Mr. Stephens to address the shut-
down price. He referenced the Federal Reserve Board Bank in
Dallas, Texas; and mentioned presentations with break-even
and shut-down prices for different basins.
Mr. Stephens looked at slide 39, "Conclusions":
• Willow project development as modeled would lead to
billions of dollars of revenue to:
• State of Alaska
• Impacted Communities
• North Slope Borough
• Federal Government
• Producer
• Benefit to state of increased employment not modeled
but also expected to be significant and material
Co-Chair Stedman thought it would be advantageous to see
dollar amounts associated with the different revenue areas
listed on the slide.
Mr. Stephens believed that the numbers were not included in
the presentation but offered to provide the numbers
quickly.
Co-Chair Stedman thought it would be good for the public to
be aware of the revenue amounts, which he thought was in
the billions.
Mr. Stephens agreed.
10:31:06 AM
Mr. Stephens looked at slide 42, "Spring Forecast
Comparison":
Spring Production Forecast with Three Cases:
1. Willow (Risked) current Spring 2023 forecast
• Risks chance of occurrence, reducing forecast
production
• Risks project timing, delaying forecast
production
• Peak production lower, and outside 10-year
forecast window
2. Willow (Unrisked)
• Single deterministic case, assuming project as
presented in this analysis
• Peak production of 183,000 barrels per day in
FY 2030
3. No Willow
• Base Production Data from State Forecast
• 2023 to 2032 Official forecast, provided by DNR
• 2033 to 2042 Continued for an additional 10
years by DNR
• 2043 to 2053 Long-term forecast extrapolation
by DOR, for illustrative purposes only
Senator Kiehl asked if Mr. Stephens could discuss the
aggregate reduction in barrels produced in the risked
scenario.
Mr. Stephens relayed that to some extent the slide showed
the information, but he did not have a precise figure to
offer.
Co-Chair Stedman asked Mr. Stephens to get back to the
committee with the information. He discussed the process
for following up with information with the committee.
Mr. Stephens relayed that he had been asked to discuss the
revenue impacts of the Willow Project, which was not
possible in quantitative numbers. He explained that in the
main Willow analysis, one could see less than $400 million
pre-production negative impact to the state, and post-
production a $1.3 billion positive state impact over the
ten-year period. He noted that the graph on the slide
showed that risking reduced and delayed the impact of the
Willow Project on the production forecast. The impact on
the revenue forecast was similar. There was still an
expectation of modest revenue reduction during construction
and a significant positive after, but peak production was
pushed beyond the ten-year window.
10:35:56 AM
Mr. Stephens showed slide 43, "Oil Price Sensitivities,"
which showed two charts addressing four additional
scenarios beyond the spring forecast, and the spring
forecast was also shown on the slide. The scenarios
included $60, $70, $80, and $90 per barrel starting in 2024
and increasing with inflation at 2.5 percent. He noted that
the minimum tax floor materially impacted the analysis
during the construction period.
Mr. Stephens pointed out that the left-hand chart showed
all state revenues combined for the Willow analysis. The
minimum tax floor partly shielded state revenue from the
impact of low oil prices or higher levels of company
investment. The minimum tax floor reduced benefit to
companies making investments, especially at lower oil
prices. Also on the chart it was possible to deduce that
the producer gained more benefit from lease deductions with
higher oil prices. He thought that while it was true, the
deduction could be misleading.
Mr. Stephens addressed the chart on the right-hand side of
slide 43, which focused on production tax but extended the
analysis to a typical producer on the whole of the North
Slope. The main takeaway from the chart was that higher oil
prices were still providing more state revenue despite the
increased lease deductions.
10:39:59 AM
Co-Chair Stedman referenced the chart on the left, and
thought it looked like the $90/bbl line looked similar to
the original presentation. He asked if it was a
coincidence.
Mr. Stephens noted that the $90/oil price was reflected in
the top line on the graph. He explained that when a
producer was at or near the minimum tax in the production
period, you would expect there to be slight differences. In
the 2027 to 2028 period, the spring forecast and the $60,
$70, and $80/bbl lines were very close to each other.
Co-Chair Stedman clarified that he was referring to the
chart on the left, which showed Willow only.
Mr. Stephens affirmed that having a raised oil price would
allow a producer to see the benefit of deducting more lease
expenditures than otherwise. Equally, the right hand chart
showed that the overall benefit from oil price was such
that there was still more oil revenue at $90/bbl in 2028
than one would at a lower price.
Co-Chair Stedman expressed understanding. He thought it
looked like the chart on the left was fairly similar to Mr.
Stephens other report, considering the negative impacts.
Mr. Stephens thought Co-Chair Stedman's comment was fair
and noted that the dashed line on the previous slide was
even more negative than at the $90/bbl price.
Mr. Stickel added that in the February analysis, there had
been a simplifying assumption that the minimum tax would
not limit the ability to deduct lease expenditures. He had
shown in introductory slides that the $90/bbl scenario
assumed that the company was far enough above the minimum
tax in order to apply most of the lease expenditures in
reducing the tax liability. Under the spring forecast in
2028, the company was already assumed to be at the minimum
tax, so in the new analysis, the company received no
benefit for the $2.1 billion in spending made in 2020. It
was also the case for the $60/bbl scenario. In the higher
priced oil scenarios, the companies were higher than the
minimum tax and were able to apply progressively more of
the lease expenditures and getting down to the minimum tax.
He added that in the report released in February (which
would be updated with new assumptions) there was an
assumption that companies could apply all lease
expenditures without bumping up against the minimum tax.
Co-Chair Stedman thought it would be a good idea to reprint
the report and update it, as documents circulated around
the building for years. He thought the report was a good
exercise but thought an updated version would be helpful.
10:43:05 AM
Senator Kiehl thought the chart on the right included all
the assumptions from the chart on the left.
Mr. Stephens answered "yes" and asked Senator Kiehl to bear
in mind that the chart on the left was all state revenues,
and the chart on the right was only production tax.
Senator Kiehl considered risks and benefits and thought
that the optimal situation for the state treasury was
moderate oil prices now and higher oil prices after 2028.
He thought that the reverse would make the analysis look
very different.
Mr. Stephens agreed and offered to model the scenario if it
was of interest.
Mr. Stephens referenced slide 44, "Oil Price
Sensitivities":
• Production Tax and State Corporate Income Tax vary
strongly with oil price
• Property tax and pipeline tariff benefit show less
variation
• Total undiscounted state revenue and Net Present
Value to State remain material at all modeled oil
prices
Mr. Stephens observed that the chart on the right-hand side
of the slide showed the production tax as the biggest
contributor to state revenues at all modeled oil prices.
The other revenue sources were smaller and less varied. He
noted that the table at the bottom of the slide showed how
NPV to the state remained material at all modeled oil
prices ranging from $1.8 billion at $60/bbl up to $3.2
billion at $90/bbl.
Co-Chair Stedman referenced the price of oil being at
$40/bbl, and thought it was good to remind the committee
that things change over time.
Mr. Stephens relayed that DNR could address any alternative
oil price model.
10:45:56 AM
Mr. Stephens showed slide 45, "Appendix: Local Cash Flows."
Mr. Stephens considered slide 46, "Annual and Cumulative
Cash Flow Local Only," which looked at royalty share for
impacted communities, and the property tax received by the
North Slope Borough. Over $3 billion was expected to go to
impacted communities, and over $1 billion to NSB property
taxes, with no negative impact expected.
Mr. Stephens displayed slide 47, "Local Annual and
Cumulative Cash Flow First Ten Years," which showed a
table. He made note of positive financial impact in the
first five years from rents for the impacted communities,
as well as property tax for the borough.
Co-Chair Stedman thanked the testifiers and staff that
assisted in assembling the information for the
presentation. He was glad that the initial report was
simplified, and looked forward to an update. He thought Mr.
Stickel could differentiate the impact of expansion in new
areas when reviewing new year's revenue forecast. He
reiterated his question about the break-even and shut-down
price for the Willow Project.
Mr. Stickel agreed to get back to the committee with the
information.
Co-Chair Stedman referenced the Federal Reserve Board and
cited information on the Permian Basin. He thought the
information on Alaska should be available.
Co-Chair Stedman expressed appreciation for the presenters.
Co-Chair Stedman discussed the agenda for the following
day, which would include a fiscal summary update from the
Legislative Finance Division. The report would include the
current budget, other amendments, and expenditures such as
capital budget items. The presentation would also include
discussion of the Permanent Fund Dividend.
ADJOURNMENT
10:51:12 AM
The meeting was adjourned at 10:51 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 032323 SFIN Willow Fiscal Analysis.pdf |
SFIN 3/23/2023 9:00:00 AM |
|
| 032323 SFIN DNR Willow Update.pdf |
SFIN 3/23/2023 9:00:00 AM |
|
| 032323 Willow Project Fiscal Analysis 2023.04.10 Update.pdf |
SFIN 3/23/2023 9:00:00 AM |
|
| 032323 DOR Response to SFIN Willow Analysis 03.23.23.pdf |
SFIN 3/23/2023 9:00:00 AM |