Legislature(2021 - 2022)ADAMS 519
02/22/2021 03:00 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Department of Natural Resources - Production Forecast | |
| Presentation: Department of Revenue – Revenue Forecast | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE
February 22, 2021
3:01 p.m.
3:01:34 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 3:01 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Kelly Merrick, Co-Chair
Representative Dan Ortiz, Vice-Chair
Representative Ben Carpenter
Representative Bryce Edgmon
Representative DeLena Johnson
Representative Andy Josephson
Representative Bart LeBon
Representative Sara Rasmussen
Representative Steve Thompson
Representative Adam Wool
MEMBERS ABSENT
None
PRESENT VIA TELECONFERENCE
Corri Feige, Commissioner, Department of Natural Resources;
Maduabuchi Pascal Umekwe, PhD, Commercial Analyst, Division
of Oil and Gas, Department of Natural Resources; Mike
Barnhill, Deputy Commissioner, Department of Revenue; Dan
Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue; Colleen Glover, Director,
Tax Division, Department of Revenue.
SUMMARY
COMMITTEE ORGANIZATION
PRESENTATION: DEPARTMENT OF NATURAL RESOURCES - PRODUCTION
FORECAST
PRESENTATION: DEPARTMENT OF REVENUE REVENUE FORECAST
Co-Chair Foster welcomed the committee and reviewed the
meeting agenda. He introduced House Finance Committee
staff. He shared his intent to start budget subcommittee
work the following week.
^PRESENTATION: DEPARTMENT OF NATURAL RESOURCES - PRODUCTION
FORECAST
3:04:30 PM
CORRI FEIGE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES
(via teleconference),provided a PowerPoint presentation
titled "Fall 2020 Production Forecast," dated February 22,
2021 (copy on file). She provided opening remarks. She
described the prior year as one of unprecedented
volatility in oil markets and productions levels. She
explained that the events were driven by the Corona virus
pandemic related price collapse and the resulting pro-
rationing of North Slope pipeline throughput and production
curtailment due to low oil prices. Currently, a period of
modest recovery and stability exists, with production
levels at roughly 500 thousand barrels per day and prices
in the sixty dollar range. She believed that the prior year
showed the resilience of Alaskas oil producers. She
related that the silver lining in the COVID cloud was
that production levels remained comparable to prior years
due to aggressive production optimization measures taken
by the producers.
3:07:58 PM
MADUABUCHI PASCAL UMEKWE, PHD, COMMERCIAL ANALYST, DIVISION
OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES (DNR) (via
teleconference),addressed slide 2 titled Outline:
Background
o 2020 Pandemic and North Slope oil production
o FY2020 in review
2020 Production Forecast
o Result highlights
o FY2021 Outlook
o Ten-year outlook
Summary
Mr. Umekwe shared that the forecast was produced by staff
in the Division of Oil and Gas. He provided a brief
background of the events of 2020. He moved to slide 3
titled "2020: Pandemic-Related Production Disruptions." He
summarized the pandemic related forces that shaped 2020 oil
production. The shuttering of economic activity led to a
curtailment or strong reduction in oil usage. He detailed
that the demand destruction was coupled with a decade
long surge in production. The U.S. had contributed about 50
percent of the supply of global oil. The strong supply and
drastically reduced demand shocked the oil market and
collapsed the price in a short period of time. Oil storage
became a problem that caused some production shut-ins.
Inland producers felt the pinch more than areas close to
waterways.
3:12:56 PM
Mr. Umekwe continued that what resources would rebound
post-pandemic preoccupied markets around the world. He
reported that in a positive way the story for Alaska had
been very different. Sometime in July, much of the
production had come back online. The fear that lost
production in aging fields could not handle the rapid
off/on switch in operations did not materialize in Alaska.
He believed that the rebound was a testament to the rocks
in Alaska and the excellence the operators brought to bear
in terms of technology and efficiency.
3:14:37 PM
Mr. Umekwe turned to slide 4 titled "Production and the
2020 Pandemic: Medium/Long Term Effects." He pointed to a
graph that depicted the North Slope production contribution
by drilling year.
Every year of drilling contributes to long term rates.
Production from new wells helps to mitigate overall NS
production decline. For example, some past years of
drilling contribute on average 3% to 8% of annual NS
production for almost a decade.
Laydown of drilling rigs in the FY2020/FY2021 is
expected to impact NS production decline in the short
term as well as the long term. FY2020/FY2021 undrilled
wells constitute a set of 'Missing Wells' that would
typically mitigate decline for periods beyond the year
the wells are drilled.
'Compensatory' production enhancement activities could
mitigate this 'lost development drilling' impact in
the short term.
Mr. Umekwe spoke to the benefit of drilling wells and noted
that effort was greatly reduced in 2020. He delineated that
much of the drilling that would normally happen in a year
did not take place. The wells that were not drilled, called
missing wells would impact production in the near to
long-term. He pointed out that wells drilled currently
impact future production. However, producers could engage
in optimizing activities that could compensate for the
missing wells in the short term.
3:17:07 PM
Mr. Umekwe moved to slide 5 titled "Overall Perspective:
North Slope:"
On average, modest decline in production over
the last 5 Fiscal Years:
o FY16 to FY20 on average annual ~1% decline in
production
Recent Major Changes in Production
o Prudhoe Bay Unit: Change of operatorship;
strong ongoing production optimization efforts
o Kuparuk Unit: Natural decline; pandemic related
production disruption /interrupted rig activity
o Colville River Unit: Natural decline; pandemic
related production disruption /interrupted rig
activity
o Milne Point: ~28% growth (FY19 to FY 20)-M, L,
I pad drilling
o PTU: Progressively improved facility
reliability
Future Projects coming in:
o Near future:
Fiord West Development, GMT2, Raven Pad in
Milne Point
Unit, CD5 Expansion
o Farther out:
Pikka: FEED 2021
Willow: FEED; FID YE 2021
Mr. Umekwe turned to the chart on the top right of the
slide that portrayed an average annual 1 percent decline in
production since 2016. He characterized the decline as
phenomenal considering the typical 4 percent to 6 percent
long term decline on the North Slope. He contributed the
lower rate of decline to prior production enhancement and
development activities.
3:20:48 PM
Mr. Umekwe turned to slide 6 titled "Status Update of Key
Future Projects: North Slope." He reported that the chart
was a time capsule of activity for six projects from
January 2020 through January 2021. He listed the projects:
Moose Pad Development, CD5 second Expansion, GMT2, Pikka,
Willow, and Liberty.
3:22:55 PM
Mr. Umekwe moved to slide 8 titled "Fall 2020 Production
Forecast: FY 2021 Outlook:"
For the first 5 months of FY2021 (July 2020 to Nov
2020), on average, daily production has come in within
the range forecasted by the DNR.
Difference between average daily production and mean
forecasted statewide production is ~40,000 bbl;
related to operational and production ramp-up timing
decisions
Mr. Umekwe pointed to the graph on the slide that depicted
production from July 2020 through November 2020 (North
Slope and Statewide). He explained that the blue bars
portrayed the range of the departments forecast from low,
mean, and high. He emphasized that operational decisions
made by the producers would affect production and
therefore, the forecast.
3:25:25 PM
Mr. Umekwe advanced to slide 9 titled "FY2021: Production
Variance July - Nov 2020:"
Deferred/forestalled summer turnaround maintenance
(TAR) benefits summer oil and NGL production
Ongoing production optimization efforts improve
facility efficiency, as well as facility and well
uptimes.
Mr. Umekwe noted that the graph at the bottom of the slide
shows the highs and lows in production related to the
producers operational decisions. He conveyed that typical
of the North Slope, winter production levels were strong
due to the absence of maintenance work in the winter
months. The summer was the optimal time to perform
maintenance. In addition, temperature impacted the use of
gas. Every summer DNR typically expected work that would
take fields offline leading to slightly lower production.
He pointed out that in the summer of 2020, there was not a
dip in production because the operator deferred summer
work, which resulted in strong numbers in the summer.
3:27:59 PM
Mr. Umekwe turned to slide 10 titled "Comparing Long-Term
Projections:"
• DNR forecasts FY2021 average annual production at
470MBOPD and a range of 413MBOPD and 526 MBOPD
• DNR's forecast is a snapshot in time, reflecting
current information on all projects considered,
as well as operators' current plans.
• Operators' long-term outlook falls within DNR's
long term forecast range
• DNR's mean case falls below sum of the aggregate
of operators' submitted case forecasts, for most
of outlook period, reflecting differences in long
term development case assumptions between DNR and
operators.
Mr. Umekwe illuminated that the gray bar on the graph
depicted DNRs high prediction and the orange bar
represented the operators outlook. The faded bar portrayed
DNRs low side forecast. He informed the committee that DNR
employed an independent method to formulate its forecast
than the producers method that used different assumptions
and standards. Despite the two different forecasting
approaches, the DNR forecast covered a range that included
the operators outlook and the departments mean forecast.
3:30:04 PM
Mr. Umekwe moved to slide 11 titled "Long Term Production
Outlook: Production Categories:"
Currently producing (CP) fields remain the backbone
of state oil production in near and medium term. Near-
term projects under development (UD), often within
existing fields, impact 12-month outlook.
Future fields (UE), which are currently being
evaluated by operators, begin to play a more
significant role in farther out in outlook period.
All new production/projects add to a declining base
production
Mr. Umekwe highlighted that the dark red portion of the
graph represented projects under development. The blue
field portrayed currently producing fields and the brown
portion showed future fields. He underlined that the
current production trend generally declined.
3:32:32 PM
Mr. Umekwe moved to slide 12 titled "Increasing Uncertainty
as New Fields/Projects Come Online:"
Graph above shows seasonal variation in monthly
production as well as widening uncertainty for the
outlook period through 2030.
New fields, currently in appraisal and under
evaluation, are major drivers for medium/long term
uncertainty in overall outlook
Mr. Umekwe offered that uncertainty increased in longer-
term forecasts. Often, the expected production was never
what actually happened - production could exceed or be
below projected.
3:34:03 PM
Mr. Umekwe turned to slide 13 titled "Projects Under
Evaluation Medium to Long Term." Mr. Umekwe explained that
the map depicted the location of the projects located on
the North Slope.
3:35:00 PM
Mr. Umekwe advanced to slide 14 titled "New Projects Under
Development/Evaluation: Adding to a Declining Base
Production:"
• New projects add to a declining base production.
In the absence of new projects, decline of
existing fields expected to exceed the 4% to 5%
historical decline of the North Slope
• In scope and estimated ultimate volumes, new
projects compare closely with historical PBU/KRU
satellites, as well as some standalone
developments such as CRU-Alpine.
• Inclusion of further risks and timing of new
projects is reflected in rates lower than
operator-announced estimates.
• Actual outcome and timing of these projects
remain critical in maintaining North Slope
historical 4% to 5% historical decline or the
possibility of flattening or growth in
production.
Mr. Umekwe described the graph as a portfolio of all
projects anticipated to begin production in years two to
ten of the forecast. The prediction is risk weighted. He
underlined that the graph demonstrated the challenge to
maintain flat production; new projects and increased
investment in existing fields stem the decline.
3:37:27 PM
Mr. Umekwe spoke to the Summary on slide 15:
DNR forecast continues to use the best information
available to DNR/DOR, to generate independent
production outlook for oil fields within the state,
with a focus on generating accurate near-term and
realistic long-term forecasts for planning purposes.
Production from projects under evaluation within the
10-year outlook period reflects uncertainty in
operator plans towards return to drilling activity,
specific project uncertainties, depressed oil prices
and commercial risks, as well as project scope and
timing risks.
DNR forecasts assume steady-state development on
currently producing fields, similar to past history
for all the fields.
While considering a wide range of drivers for
different fields and potential projects and excluding
specific exogenous production shocks such as
production curtailments, prorations, or the full range
of options available to operators in daily operations,
the DNR forecast has so far provided a reliable range
to guide fiscal planning for the State.
Mr. Umekwe summarized that the goal was to have a forecast
using the best information available to DNR. The 10-year
outlook period reflected uncertainty in operator plans.
3:38:59 PM
Co-Chair Foster acknowledged that Representative Ken
McCarty was in the audience.
Vice-Chair Ortiz referred to the passage of SB 21 Oil and
Gas Production Tax [CHAPTER 10 SLA 13, 05/21/2013] that he
described as the latest major piece of oil tax legislation
in 2013. He remembered that due to the bill's passage, the
industry reported it would be producing about twice as much
oil, roughly 1 million barrels per day in a short amount of
time. He asked why production had never come close to 1
million barrels per day (bbl/d) rather than remaining at
the approximate 500 thousand (bbl/d).
Commissioner Feige did not recall an assertion of adding
500,000 new barrels under SB 21. She offered to follow up.
She observed that there had been a flattening of the
decline curve since the passage of SB 21 the decline had
remained at about 1 percent per year for some time. In
addition, an invigoration of exploration work commenced
in approximately 2014 in Pikka and Willow. She noted a
roughly 90 percent discovery rate in a 5-year period, which
represented new barrels of oil from new reservoirs and
would come into production in approximately 2025. She
concluded that the discoveries she described were the
impacts of the passage of SB 21.
3:42:23 PM
Representative Johnson looked at the key projects listed on
page 6. She identified three wells located on state land
she thought were important: Pikka, CD5, and the Moose Pad
Development. She asked for a summary of what needed to
happen to get to the production stage and what DNR could do
to remove obstacles that stood in the way of production.
Commissioner Feige reported that Moose Pad was in the Milne
Point Unit and was operated by Hilcorp, which was
aggressively expanding and had increased production by 28
percent or. She elaborated that there was some production
in the unit that was subject to net profit share lease
terms; the leases were economically distressed. There was
currently legislation [HB 81-Oil/Gas Lease:DNR Modify Net
Profit Share] that would unstrand the resources within the
Milne Point Unit. She elaborated that the CD5 area
expansion included ongoing drilling and was in an area of
leases jointly managed by the state and Arctic Slope
Regional Corporation (ASRC). CD5s development depended on
access through the deployment of ConocoPhillips new large
extended reach drilling rigs. The rigs drilled out from
existing pads for 5 to 6 miles without having to build
additional roads or gravel pads. She reported that the
Pikka Project had been moved into the Front End Engineering
Design (FEED) stage. She indicated that due to the low oil
price environment the operators, Oil Search and Repsol, had
taken another look at the development plan and were
starting a phased development that could initially produce
80 thousand bbl./d. She declared that DNR continued to
support the projects in addition to Willow, Liberty, and
those within the Natural Petroleum Reserve-Alaska (NPRA) by
staying engaged with federal partners and ensuring projects
that had been through the National Environmental Policy Act
(NEPA) process be allowed to continue.
3:46:52 PM
Representative Johnson wanted to confirm that DNR was doing
everything it could from the states perspective to keep
the projects moving forward. Commissioner Feige answered in
the affirmative.
Representative Wool asked how long the rationing had taken
place on the pipeline, that affected production during
COVID. Commissioner Feige answered there had been
prorationing events that began in April and extended
through May. She elucidated that there was a prorationing
and curtailment event in the Kuparuk unit of 60,000 bbl./d.
In addition, Colevile River decreased by 40 thousand
bbl./d, Badami oil field shut in 1, 500 bbl./d from May
through October. In addition, two fields in Cook Inlet,
West McArthur River and Redoubt Fields in total shut out
approximately 1,900 barrels per day in May and had not come
back online yet. The prorationaing on the Trans-Alaska
Pipeline System (TAPS) ceased by the end of May when
storage capacity in refineries on the west coast of the
mainland opened up.
Representative Wool asked if the prorationing had been due
to storage. He recalled that for a time, the oil price was
negative and it had cost money to move oil through the
pipeline. He deduced that it was not a supply problem that
caused rationing, but the price of oil. He asked if the
issue had been foreseen by anyone. He wondered if the oil
was not economical to sell it could create problems
sustaining the pipeline. Commissioner Feige answered that
when there was a low price shock such as took place in
April [2020] and caused negative prices it was due to the
pandemic related massive contraction in the global
consumption market. She elucidated that global consumption
had been decreased by 20 million barrels per day, which was
the equivalent of total United States (US) production. The
price and demand collapse had occurred so rapidly that
there was not time to respond quickly enough to stop
producing. She explained that it was necessary to back a
well out of production, it could not be quickly shut off or
damage to the foundation could occur. The negative price
was a result of the collapse taking place so quickly
causing the lack of storage. She delineated that any time
the storage at Valdez reached between 60 and 70 percent
capacity a notice of proration was issued. The oil vessels
were sequenced to open up more storage and the whole system
was managed upstream from Pump Station 1. Low throughput in
very cold level temperatures was the greatest operational
and structural challenge for TAPS.
3:51:59 PM
Representative Wool cited slide 11 that showed the
production curve remaining relatively flat through 2030
with all the projects coming online to offset natural
decline. He deduced that the best case scenario would be
flat production over the next 10 years. He wondered whether
investors deciding not to invest in Arctic drilling,
corporations like General Motors that had decided to not
make gasoline powered cars by a certain date, and other
global factors considered in the projections. Commissioner
Feige deferred to Mr. Umekwe.
Mr. Umekwe answered that there was uncertainty factored in
projections based on several things: price, technological
effects, and supply and demand. He delineated that in terms
of single projects, the division did not try to calculate
in every single factor that may impact the production but
focused on the larger factors that might affect production.
He noted that on slide 11 the numbers represented the mean
case. He pointed to slide 12 and indicated the graph
illustrated the full range of predictions, which included
the best case scenario. The high case was approximately 700
thousand bbl./d. The mean case included much of the
uncertainty that was recently discussed.
3:55:25 PM
Representative Wool spoke about oil at $60 per barrel. He
wondered whether the price was currently stable. He
remarked that he had not seen a prediction for the price of
oil. Commissioner Feige deferred to the Department of
Revenue for the forecasted price of oil. She acknowledged
the price of oil was modestly stable and vacillated
according to geopolitical and climate events.
3:56:37 PM
Representative Carpenter asked what the current and maximum
capacity was for TAPS. He asked if the capacities changed
over time. Commissioner Feige answered that the figure was
just over 500,000 per day for the last seven days. The
pipeline saw a peak of 2 million per day at its peak, but
acknowledged that the optimum peak operating range was 1.5
million bbl./d. She shared that Alyeska Pipeline Services
had well managed the pipeline and performed effective
maintenance and modernization work over the years; the
assest was in very good condition. She added that very cold
weather events and lower volumes of oil, especially
traversing Atigun Pass were the choke points. Aleyeska
has added heat to the pipeline under those conditions to
maintain the integrity of the flow of oil.
Representative Carpenter asked if slide 8 referred to the
spring 2020 forecast. Mr. Umekwe answered that the slide
showed a five month comparison from July 2020 to November
2020 of what happened versus what was forecasted.
3:59:17 PM
Representative Carpenter was trying to determine whether
the numbers were based on the spring forecast. Mr. Umekwe
clarified that it was based on the fall 2020 forecast.
Representative Johnson asked if there were obstacles that
DNR could remove to get state land projects moving along.
Commissioner Feige answered in the negative. She detailed
that the projects were in a period of routine permitting.
Representative Johnson spoke to the states commitment to
getting production into the pipeline. She asked whether DNR
was doing everything necessary to the goal of increased
throughput. Commissioner Feige replied, "Absolutely." She
elaborated it was in no way in the state's best interest to
slow down the process of new production.
Co-Chair Foster thanked the presenters.
4:02:01 PM
AT EASE
4:11:59 PM
REONVENED
^PRESENTATION: DEPARTMENT OF REVENUE REVENUE FORECAST
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE (via teleconference),
introduced a PowerPoint titled "Fall 2020 Forecast
Presentation," dated February 22, 2021 (copy on file)
beginning on slide 2:
Agenda
1. Forecast Background and Key Assumptions
2. Fall 2020 Revenue Forecast
Total State Revenue
Unrestricted Revenue
3. Petroleum Forecast Assumptions Detail
Oil Price
Oil Production
Oil and Gas Lease Expenditures
Oil and Gas Credits
Mr. Stickel moved to slide 4 titled Background: Revenue
Sources Book:
1. Historical, current, and estimated future state
revenue.
2. Discussion and information about major revenue
sources.
3. Prepared in accordance with AS 37.07.060 (b)(4),
and supports long term plan under AS 37.07.020.
4. Official revenue forecast used for Governor's
budget proposal; updated in spring.
5. Located at tax.alaska.gov
Mr. Stickel related that the Revenue Sources Book (RSB) was
published every December and contained the fall forecast.
The division gather data from the tax revenue management
system, state accounting system, and various state agencies
to report actual revenue for the most recent fiscal year to
provide a 10-year revenue forecast.
Mr. Stickel turned to slide 5 titled "Key Alaska Economic
Indicators."
1. Real State GDP: $50.9 billion in Q3 2020
• Up 7.2% from Q2 2020, still down 4.9% from
Q3 2019
•
2. Employment: 290,400 in December 2020
• Down 24,100 (-7.7%) compared to December 2019;
heaviest impacts in leisure/hospitality,
transportation/warehousing, and oil/gas
industries
3 Wages & Salaries (seasonally adjusted): $21.8
billion in Q3 2020
• Up 5.2% from Q2 2020 and flat from Q3 2019
4. Alaska Bankruptcies: 313 for calendar year 2020,
19 for January 2021
• Compared to 400 for all of 2019, 38 for January
2020
5. Foreclosures: 98 in Q3 2020, 303 for calendar
year 2020
• Compared to 197 in Q3 2019 and 729 for calendar
year 2019
6. Housing Starts: 1,494 for calendar year 2020
• Compared to 1,689 for calendar year 2019
Mr. Stickel indicated that in the third quarter of 2020
state Gross Domestic Product (GDP) significantly increased
by 32.2 percent of the annual rate after two quarters of
major losses. The value of the economy was improving but
was not back to pre-recession levels. Employment in the
state was still down by nearly 8 percent compared to one
year earlier.
4:16:46 PM
Mr. Stickel turned to slide 6 titled "Fall Forecast
Assumptions:"
The economic impacts of COVID-19 are uncertain;
DOR has developed a plausible scenario to
forecast these impacts.
Key Assumptions:
o Investments: Stable growth in investment
markets, 6.75% Permanent Fund returns.
o Federal: Some CARES Act funds shown in FY
2021, no additional stimulus in FY 2022+.
• Petroleum: Alaska North Slope oil price
of $45.32 per barrel for FY 2021 and
$48.00 per barrel for FY 2022. No
further oil production curtailments.
o Non-Petroleum: Most economic activity will
return to baseline levels by FY 2022, except
tourism full recovery by summer 2023.
Mr. Stickel emphasized that the elephant in the room was
Covid-19, which remained a large source of uncertainty in
the forecast.
4:19:08 PM
Mr. Stickel advanced to slide 7 titled "Relative
Contributions to Total State Revenue: FY 2020." He
explained that the slide depicted the relative importance
of the different sources of revenue to total state revenue.
He noted that federal revenue [48.2 percent], investment
earnings [20.8 percent], and petroleum [19.7 percent] were
the largest sources of total revenue. All other sources of
revenue amounted to roughly 12 percent of total revenue.
He advanced to slide 9 titled Total Revenue Forecast: FY
2020 to FY 2022 Totals and Percent Change from FY 2020. He
detailed that the states revenue was broken into four
categories of restriction including unrestricted general
funds (UGF), designated general funds (DGF), other
restricted revenue, and federal revenue. All categories had
specific provisions around how the funding was used and was
considered restricted revenue. He added that DGF, other
restricted revenue, and federal revenue was often
collectively referred to as restricted revenue. He
elaborated that in FY 20 total state revenue was
approximately $8.7 billion and forecasted total state
revenue at $10.8 billion in FY 21 and $10.3 billion in FY
22. The unrestricted portion was $4.5 billion in FY 20 and
the forecasted amount was $4.3 billion in FY 21 and FY 22.
He pointed to the chart containing the percent changes
between the fiscal years. He reported that overall, the
fiscal year 2022 forecast for UGF was roughly 6 percent
lower than fiscal year 20 levels and about 1.4 percent
lower than fiscal year 21 levels. In FY 22, total state
revenue was forecasted at 19.1 percent higher than FY 20
levels and 5 percent lower than FY 21 levels.
4:22:46 PM
Mr. Stickel turned to slide 10 titled Unrestricted Revenue
Forecast: FY 2020 to FY 2022 Totals and discussed
unrestricted revenue. He expounded that investment revenue
was the largest source of unrestricted revenue to the
state. In FY 20, the total was nearly $3 billion and was
predicted to be roughly $3.1 billion in both FY 21 and FY
22. The Percent of Market Value (POMV) transfer comprised
most of the investment revenue. He furthered that oil
revenue totaled a little over $1 billion in FY 20 and was
predicted to total over $800 million in both FY 21 and FY
22. Non- Petroleum revenue contributed roughly $400 million
in FY 21 and was forecast to remain that amount in the next
two fiscal years.
4:23:50 PM
Mr. Stickel advanced to slide 11 titled "Unrestricted
Revenue Forecast: FY 2020 and Changes to Two-Year Outlook."
He reported that the chart detailed each component of
unrestricted revenue and included a comparison of the
Spring 2020 forecast and the Fall 2020 forecast. He pointed
to the Alaska North Slope oil price. The forecasted price
increased by $8.32 bbl. between the Fall 2020 and Spring
2020 prediction totaling $45.32 bbl. and increased $7.00
bbl. to $48.00 bbl. in FY 22. The reason was stabilization
and recovery in oil markets from the pandemic. The current
futures market predicted a price of $60 bbl. in 2022. He
noted the increase of $21.3 million for the FY 22 forecast
between the spring and fall forecasts due to stronger than
expected market returns for the last several months of FY
20, which affected the calculation for FY 22. He concluded
that the FY 20 actual total investment revenue was in line
with expectations. The FY 21 forecast was $87.5 million
higher than the fall forecast and FY 22 decreased by $58.3
million. He indicated that one of the largest contributors
to the FY 22 change was due to reductions in corporate
income tax.
4:26:01 PM
Mr. Stickel moved to slide 12 titled Unrestricted
Investment Revenue: FY 2020 to FY 2022 Totals. He
discussed that investments were now the state's largest
source of UGF. He spoke to the importance of the Permanent
Fund transfer that was expected to contribute over two-
thirds of the states unrestricted revenue every year over
the next ten years. The scenario represented the reality of
living in a climate low oil prices and production decline.
He mentioned that there was a small amount of other UGF
that represented earnings from cash balances.
Mr. Stickel spoke to slide 13 titled Unrestricted
Investment Revenue: Percent of Market Value (POMV)
Forecast:
The statutory POMV rate changes to 5% beginning
FY 2022.
For FY 2019 FY 2021 this rate was 5.25%.
Forecast assumes Permanent Fund's long-term total
return expectation of 6.75%.
Differing Permanent Fund returns and petroleum
deposits could significantly alter actual POMV.
Mr. Stickel pointed to the graph that depicted the POMV
transfer at over $3 billion each year rising to $3.7
billion by FY 2030. He disclosed that the forecast was a
baseline and did not factor in any unanticipated draws from
the Earnings Reserve Account (ERA) beyond the POMV draw.
Mr. Stickel highlighted slide 14 titled Unrestricted
Petroleum Revenue: FY 2020 to FY 2022 Totals. He explained
that there were four main sources of unrestricted oil
revenues: Petroleum Property Tax, Petroleum Corporate
Income Tax, Oil and Gas Production Tax, and Royalties.
Petroleum property taxes were stable and contributed over
$100 million each year. The corporate income tax was zero
in FY 2020 and was predicted at $5 million in FY 21 and
negative $20 million in FY 22. The negative amount
reflected net tax refunds. He offered that the oil
production tax or severance tax for the North Slope was
comprised of a net profits tax with a gross minimum tax
floor. The current forecast prices for the next two years
was expected to bring in a little under $200 million. He
added that royalties were the largest source of
unrestricted petroleum revenue totaling $675 million in FY
20 and forecasted at over $500 million in the next two
fiscal years. He noted that in addition to the unrestricted
royalties a portion of royalty revenue was deposited into
the Permanent Fund and was much higher than unrestricted
royalties.
Mr. Stickel examined slide 15 Unrestricted Non-Petroleum
Revenue: FY 2020 to FY 2022 Totals. He related that Non-
Petroleum corporate income tax was the largest source of
unrestricted non-petroleum tax revenue and generated $102
million in FY 20 and was predicted to decrease to $30
million in FY 21 and $25 million in FY 22. Other
significant taxes included Mining License Tax, Insurance
Premium Tax, and Fisheries Taxes. The total unrestricted
non-petroleum tax revenue was predicted to generate $216
million in FY 21 and $228 million in FY 22. The total
unrestricted non-petroleum revenue was expected to be $363
million in FY 21 and $372 million in FY 22. He presented
slide 16 titled Unrestricted Revenue Forecast: Non-Oil and
Gas Corporate Income Tax (CIT). He shared that forecasting
the corporate income tax was challenging. He briefly
described the methodology he used to predict the income tax
revenue. He conveyed the two major unusual impacts to
income tax revenue: the recession, and the impact from the
Coronavirus Aid, Relief, and Economic Security Act (CARES
Act.) He explained that the CARES Act provisions allowed
corporations to carry back any net operating losses from
2018 to 2020 up to five years and receive refunds for
previous taxed paid. In addition, another provision allowed
companies to accelerate certain alternative minimum tax
refunds into 2019. The CARES Act provisions were
automatically applied to Alaskas tax via state statute,
unless the legislature chose to decouple or modify the
provisions. He elucidated that for general corporate income
tax, the department was expecting lower revenue from the
pandemic related recession and the Cares Act impact further
reduced the expected FY 21 revenue by $20 million totaling
$30 million for FY 21 and $72 million in CARES Act related
refunds in FY 22 reducing the net revenue for FY 22 to $25
million. The department forecasted that the revenue would
rebound to $130 million in FY 23.
4:34:20 PM
Mr. Stickel moved to slide 17 titled "Unrestricted Revenue
Forecast: Oil and Gas Corporate Income Tax. He indicated
that the oil industry was deeply impacted by COVID and paid
no corporate income tax in FY 20. He was predicting very
low revenue for FY 21 and estimated a net negative for FY
22. In FY 23, the oil and gas corporate income tax was
predicted to rebound to $55 million, which was far lower
than the several hundred million per year generated when
oil prices and profits were higher.
4:35:05 PM
Mr. Stickel advanced to slide 19 titled Petroleum Detail:
Changes to Long-Term Price Forecast. He related that the
graph depicted the fall 2020 forecast in comparison to the
spring 2020 forecast. The fall forecast had been generated
on December 1, 2020 and based on the most recent futures
market projections. The fall forecast was based on the
Alaska North Slope average oil price of $45.32 bbl. and was
$8.32 higher than the spring forecast. The FY 22 forecast
was $48 per barrel, a $7.00 increase over the prior
forecast. He commented that beyond FY 22 it was assumed
the oil price would increase with inflation; prices would
increase by $1 or $2 per year. He reviewed Slide 20 titled
"Petroleum Detail: Nominal Brent Forecasts Comparison as of
January 20, 2021. The graph compared DOR's ANS forecast to
Brent price forecasts from the U.S. Energy Information
Administration (EIA) futures market known as NYMEX and the
average of analyst forecasts. He addressed Slide 21
titled "Petroleum Detail: UGF Relative Price per Barrel
(without POMV): FY 2022. He explained that the graph
showed how unrestricted revenue for FY 22 would change with
different oil prices. The data assumed official forecasted
North Slope production of 439,600 barrels per day. Near the
forecasted ANS price of $48.00, a $1 decrease in price led
to an approximately $15 to $20 million change in UGF
revenue, and a $1 increase led to an approximately $25 to
$30 million change in UGF revenue.
4:38:18 PM
Mr. Stickel turned to slide 22 titled "Petroleum Detail:
North Slope Petroleum Production Forecast. He articulated
that the graph portrayed the forecasted decline of 8
percent in FY 22 to 440 thousand barrels per day. The
decline reflected the lack of drilling due to the pandemic.
Production was expected to stabilize in FY 23 and slightly
increase to 482 barrels per day as new fields began
producing. He highlighted Slide 23 titled "Petroleum
Detail: Changes to North Slope Petroleum Production
Forecast." He indicated that the slide showed the fall 2020
forecast compared to the spring 2020 forecast - the overall
changes were minor; a slight increase was expected in FY 23
through FY 25. He moved to Slide 24 titled "Petroleum
Detail: North Slope Allowable Lease Expenditures. He
elucidated that the graph depicted how allowable lease
expenditures changed over the last decade and forecasted
the expenditures over the next 10 years. The costs were
reported on tax returns. He remarked that company spending
was an important measure of current and planned investment.
In FY 20, North Slope capital expenditures was $2.6 billion
and operating expenditures were $2.9 billion. The amounts
were well below the spending over the last decade. The
division observed dramatic cutbacks in spending in FY 21
with some signs of recovery on the horizon. He anticipated
that total North Slope spending would decrease by $1.6
billion in FY 21. Capital spending was expected to increase
in FY 22 and FY 23 as companies invested in major
investments such as Willow and Pikka. Capital expenditures
were forecasted to stabilize at $2 billion per year. The
division forecasted that many of the operating expenditure
reductions made by companies in the past year would be
permanent.
4:41:39 PM
Mr. Stickel highlighted slide 25 titled "Petroleum Detail:
North Slope Transportation Costs. He offered that looking
at transportation costs was important because it reduced
the value of oil for both tax and royalty purposes. The
transportation costs included all costs of getting oil to
market including feeder pipeline tariffs, Trans Alaska
Pipeline tariffs, and all transportation costs. The
forecast estimated the average transportation cost was $8
in FY 20, $9.21 per barrel for FY 21, and $9.91 for FY 22,
increasing to $11.00 per barrel. Further out the increases
were based on lower production, inflation, and that a
greater proportion of production will be subject to feeder
pipeline tariffs.
4:43:00 PM
Mr. Stickel addressed Slide 26 titled "Petroleum Detail:
Tax Credits for Purchase Detail. He illuminated that the
graph showed a projection of how the outstanding balance of
tax credits, estimated at $760 million, would be reduced
over time if the statutory appropriation were made
beginning in FY 22. He expounded that prior to 2016,
various oil tax credits existed in statute that reduced tax
liability or were turned into tax credit certificates that
the state could purchase at face value. The legislature
imposed sunset laws by 2017 on all new credits and were
currently totally phased out. However, an outstanding
balance from credits issued prior to the sunsets remained.
The statutory annual repayment formula was based on either
10 percent or 15 percent of estimated production tax levied
before credits. The multiplier was 15 percent when the ANS
price forecast was below $60 and 10 percent for prices
above $60 per barrel. He furthered that since FY 07, $3.6
billion had been spent by the state to purchase the full
amount of tax credits. After 2016, less than the full
amount of tax credits had been purchased; FY 20 was the
first year no repayment appropriation was made. The
forecasted scenario assumed a statutory appropriation in FY
22 that increased each year through complete repayment in
FY 31.
4:45:44 PM
COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF
REVENUE (via teleconference), provided an oil and gas
production tax audit update on slide 28. She shared that
the division made significant progress towards maintaining
a three year audit cycle for oil production taxes.
Currently, the statute of limitations for audits was 6
years from the return filing date. The division had adopted
the Tax Revenue Management System (TRMS) that had enabled
the production tax team to work remotely and deliver audits
without any paper. The auditors were working proactively
to request additional data shortly after the return was
filed, which increased the amount of retrievable backup
information the auditors received.
Audit Completion and Catchup Plan:
o 2014 Audits completed 4Q 2020
o 2015-2017 audits complete by 3Q 2021
o 2018-2019 audits complete by 1Q 2023
o Reach and maintain three-year audit cycle by 1Q
2023
? Improvements to Reach Goal
o Automated processes vs manual processes
o Ability for taxpayers to use customer portal
o Stability of workforce
o Effective two-way communications
4:48:49 PM
Representative Josephson looked at slide 13 that showed a
substantial increase in POMV transfers. He noted that DNRs
production forecast predicted sustained production at
500,000 barrels per day. He surmised that it was important
to guard the 5 percent POMV draw because it was what
sustained the government. Mr. Stickel answered that it was
an astute observation. He reiterated that the POMV was
forecast to represent more than two-thirds of the state's
unrestricted revenue stream over the next decade and
beyond. Representative Josephson looked at the oil and gas
production tax of $163 million on slide 14. He recalled
that production tax had been in the billions in the 2000s
and on. Currently, it was substantially less than royalty.
He asked whether his assessment was correct. Mr. Stickel
replied in the affirmative. He remarked that when oil
prices and company profits had been higher the production
tax had been higher and brought more revenue to the state.
4:51:31 PM
Representative Josephson looked at slide 26 and the payment
of the oil and gas tax credits. He believed that beginning
in FY 16 the state had paid less than the statutory
formula. Most recently, the state was not paying anything.
He asked for the accuracy of his statements. Mr. Stickel
answered that prior to FY 16, the state had paid higher
than the statutory formula in full. Since FY 20, no
appropriations had been made to repay tax credit
certificates. Representative Josephson looked at the $50
million payment on slide 26. He asked if it was reflected
in the governor's proposed operating budget for FY 22. Mr.
Stickel deferred the question.
MIKE BARNHILL, DEPUTY COMMISSIONER, DEPARTMENT OF REVENUE
(via teleconference), asked Representative Josephson to
restate the question.
Representative Josephson reiterated his question. Mr.
Barnhill answered that the budget included $60 million for
tax credit repayments.
4:53:51 PM
Vice-Chair Ortiz followed up on a question by
Representative Josephson regarding the importance of the
POMV for state revenue on slide 13. He asked how the line
on the graph would change if the state made an additional
$3.2 billion draw beyond the 5 percent POMV draw. Mr.
Stickel answered that there would be a significant increase
in the near-term and later the line would decrease. He
would have to follow up with detailed numbers. Vice-Chair
Ortiz asked if the slope would be significantly less steep
over the long-term. Mr. Stickel agreed that the slope would
be lower if more was drawn from the fund, and it would
increase if more was put into the fund.
Vice-Chair Ortiz referred to slide 11 related to the
Permanent Fund transfers to the POMV and wanted
clarification. He noted that the FY 20 transfer amounted to
roughly $2.9 billion and was significantly more revenue
than generated from oil taxes. He cited slide 7 that
pertained to FY 20 total state revenue. He pointed out that
investment earnings only made up 20.8 percent of the
states revenue and petroleum accounted for 19.7 percent.
He thought there would be a larger difference the two
sources of revenue based on the data on slide 11.
4:57:10 PM
Mr. Stickel answered that slide 10 looked at FY 20 actual
state revenue. He offered that earnings for the Permanent
Fund had been well below 6.75 percent in FY 20. However,
the long-term return estimate was 6.75 percent annually.
Representative LeBon referred to slide 5 and commented on
key Alaska economic indicators. He suggested that banks had
been working with secondary mortgage borrowers to keep
Alaskans in their homes through loan modifications or other
means. He remarked that borrowers took advantage of the low
interest rate environment and purchased homes. He commented
that foreclosures and bankruptcies had been down and that
the banks were working with the borrowing community to
help make successes.
4:59:35 PM
Representative Wool looked at slide 5 and asked what
percent of the $50 billion DGP was oil. Mr. Stickel replied
that he did not have the data on hand. He remarked that oil
and gas was a significant amount of the state's output.
Representative Wool stated that other slides showed oil
revenue at about $1 billion. He asked what it would have
been before the oil crash of 2014. Mr. Stickel referenced
data from FY 2012. He noted that there was an appendix
(Appendix A-3 on page 101) of the 10-year history of oil
revenue in DORs Revenue Sources Book. He reported that
in FY 12 unrestricted oil revenue was $8.9 billion and
restricted oil revenue was an additional $1 billion that
totaled just under $10 billion of total petroleum revenue
in FY 12. The total value of oil and gas had been higher at
that time. Representative Wool ascertained that the states
oil revenue had been reduced to approximately 10 percent of
what it had been in a 10-year period. He asked if he was
correct.
5:01:58 PM
Mr. Stickel answered in the affirmative. Representative
Wool asked if there was a total revenue projection over the
next ten years. He cited slide 19. Mr. Stickel answered
that the fall 2020 forecast was based on the most recent
projections as of December 1, 2020. He detailed that at the
time, the expectation for FY 22 was the ANS forecast of $48
per barrel increasing with inflation. The $60 price was
approximately what the FY 22 outlook might be when looking
at the present futures market. He viewed the forecast as
one source of optimism that oil prices were trending a bit
higher than when the fall forecast had been prepared.
5:04:39 PM
Representative Wool looked at slide 28 related to the oil
and gas production tax audits. He asked whether the state
negotiated a settlement amount with companies that owe
money as a conclusion of an audit. Ms. Glover replied that
when an audit was issued the taxpayer could agree and pay
or appeal. She communicated that there was an informal
appeal process within the division adjudicated by an
appeals team that issued an independent decision. The
taxpayer then had the option to pay or file a formal appeal
with the Office of Administrative Hearings. There was a
final appeal available to the courts. During any time in
the process settlements could be reached via DOR and the
Department of Law. Representative Wool asked whether
settlements had occurred in recent audits. Ms. Glover
replied in the affirmative.
Representative Wool asked about the tax credits offered by
the CARES Act [slide 16] that amounted to $91 million. He
deduced that the net result to the state was ultimately the
same; the state was currently paying the credit instead of
taking less tax in the future.
5:07:20 PM
Mr. Stickel clarified that the CARES Act impacts on slides
16 and 17 were not tax credits. He reiterated that net
operating losses were able to be carried forward and use
the value of the loss against future taxable income. The
CARES Act allowed companies for 2018, 2019, and 2020 to
carry back any net operating loss to reduce taxable incomes
for previous years by refiling and potentially receive a
refund for the lower tax liability. He agreed that it was
the same net operating loss (NOL), the state had an
exposure one way or another. He added that there was the
potential that not all NOLs would be able to be used in
the future, but if so, it would be a net wash for the
state. He characterized it as a timing issue.
Representative Wool surmised that CARES Act impacts were a
credit and not a refund that normally applied to future
earnings. He asked about the loss of state income taxes
from oil companies. He asked if the forecast considered
that BP was being bought by Hilcorp; it did not pay taxes
to the state. Mr. Stickel stated his understanding of the
question. He replied in the affirmative - the transaction
was reflected in the forecast. The forecast assumed that
roughly 70 percent of oil and gas production was attributed
to C corporations.
5:10:43 PM
Representative Wool reiterated that BP was a C corporation
and paid income taxes to the state and Hilcorp was an S
Corporation and did not pay the same income taxes. He asked
for the amount BP had paid in income taxes in the last year
and assumed that Hilcorp would not pay the same amount as
an S corporation. Mr. Stickel answered that the department
could not speak to what a specific taxpayer had paid or was
expected to pay. He could only speak to the aggregate
amount. Representative Wool speculated that about 30
percent was not C type corporations.
5:11:39 PM
Representative Rasmussen looked at slide 5 and felt that
the slide figures painted a misleading picture. She
elucidated that her husband worked as a mortgage originator
and had seen a recent increase in mortgage interest rates.
She guessed that 2020 was a record year for the real estate
industry. She asked if there was a breakdown of the $21.8
billion in wages by industry. She wondered how the
hospitality, transportation, and the oil industry fared in
wages and salaries. She deduced that wages in those
industries would be in decrements. She wondered how a bust
in the real estate boom would impact the economy if the
real estate industry became impacted by the higher interest
rates. Mr. Stickel replied that the wage data came from the
Department of Labor and Workforce Development (DLWD), which
also provided the jobs data. He related that the low
interest rates had been acting as a stimulus to the economy
and anyone borrowing money was benefitting from the current
low interest rate environment. Representative Rasmussen
stated that the real estate industry could see a sharp
decline quickly from the impacts of interest rates
climbing. She reiterated her question regarding how a
decline in the real estate industry would affect the rest
of the economy.
5:15:44 PM
Mr. Stickel agreed that higher interest rates was an area
of concern and merited paying attention to. He determined
that if the higher interest rates were accompanied with a
broader economic recovery, it could offset some of the
impacts. He thought that if the Federal Reserve and lenders
were forced to raise interest rates rapidly it could have a
negative impact. Representative Rasmussen reiterated her
questions. Mr. Stickel rephrased Representative Rasmussens
inquiry. He stated that of the $21.8 billion in wages and
salaries in the third quarter of 2020, how much was
dependent on the real estate industry. He offered that the
best way to approach the question would be to provide a
breakout of the contribution of the key industries to the
number.
Representative Josephson pointed to slide 5 and asked
whether DOR was concerned that the number of bankruptcies
were as low as they were during the Covid-19 crisis because
they were forestalled by artificial means through federal
assistance. He wondered if bankruptcies were anticipated to
be a problem once the COVID relief monies ceased.
5:18:56 PM
Mr. Stickel agreed that bankruptcies were an area of
concern assuming that federal aid would eventually be
withdrawn as the economy recovered.
5:20:12 PM
Vice-Chair Ortiz cited slide 28 regarding the tax audit
update. He wondered whether the division had data regarding
the average amount paid through negotiated settlements
versus the total amount that was owed. He provided the
example of settling for .90 cents on the dollar and
wondered what the impacts from the settlement process was.
Ms. Glover answered that each audit process was different,
and the settlement amount depended on the audit issues.
Vice-Chair Ortiz asked if she meant there were no
parameters on the process. He wondered whether the
settlement could fluctuate between .90 cents on the dollar
to .30 cents on the dollar. Ms. Glover answered that not
every audit resulted in an appeal process. She reiterated
that each audit was different, and the issues were
different.
5:22:36 PM
Mr. Barnhill shared that Mr. Stickel gave a presentation
called order of operations in the Senate Finance Committee.
The point was made that the state's oil and gas tax regime
was the most complex in the world, partly due to changes
that were made frequently. He deduced that due to the
complexity and frequent changes it was difficult to achieve
any consistency in settlement values. He offered that every
tax case was scrutinized by the Department of Law (DOL) via
a settlement committee that advised DOR on the strength and
weaknesses of the case. He assured the committee that there
was a very robust process for reviewing and assessing a
tax settlement case before DOR takes a position on the
case.
Representative LeBon responded to Representative
Josephsons question regarding foreclosures on slide 5. He
voiced that banks reported their financial conditions
quarterly in a document called a call report. The call
report contained several leading economic indicators,
delinquency rates, other owned real estate, and trends of
non-performing loans. He suggested reviewing call reports
18 months before the pandemic began through the present to
gain insight on where the economy is headed.
Co-Chair Foster thanked the presenters and reviewed the
schedule for the following day.
ADJOURNMENT
5:26:21 PM
The meeting was adjourned at 5:26 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Fall 2020 Revenue Fcst Presentation_Final.pdf |
HFIN 2/22/2021 3:00:00 PM |
|
| HFIN DNR Production Forecast 2.22.21.pdf |
HFIN 2/22/2021 3:00:00 PM |
|
| DNR Response to Q HFIN Production Forecast 030921.pdf |
HFIN 2/22/2021 3:00:00 PM |