Legislature(2019 - 2020)ADAMS ROOM 519
01/23/2020 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Fall 2019 Production Forecast by the Department of Natural Resources | |
| Fall 2019 Revenue Forecast by the Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
HOUSE FINANCE COMMITTEE
January 23, 2020
1:33 p.m.
1:33:17 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:33 p.m.
MEMBERS PRESENT
Representative Neal Foster, Co-Chair
Representative Jennifer Johnston, Co-Chair
Representative Dan Ortiz, Vice-Chair
Representative Andy Josephson
Representative Gary Knopp
Representative Bart LeBon
Representative Kelly Merrick
Representative Colleen Sullivan-Leonard
Representative Cathy Tilton
Representative Adam Wool
MEMBERS ABSENT
None
ALSO PRESENT
Sara Longan, Deputy Commissioner, Department of Natural
Resources; Pascal Umekwe, Petroleum Reservoir Engineer,
Division of Oil and Gas, Department of Natural Resources;
Mike Barnhill, Acting Commissioner, Department of Revenue;
Dan Stickel, Chief Economist, Department of Revenue;
Colleen Glover, Director, Tax Division, Department of
Revenue; Representative Sarah Hannan.
PRESENT VIA TELECONFERENCE
Representative Ben Carpenter
SUMMARY
FALL 2019 PRODUCTION FORECAST BY THE DEPARTMENT OF NATURAL
RESOURCES
FALL 2019 REVENUE FORECAST BY THE DEPARTMENT OF REVENUE
Co-Chair Foster reviewed the agenda for the day. He
indicated Representative Hannan was in the audience. He
asked people to hold their questions until the end of the
presentation and invited testifiers from the Department of
Natural Resources to the table.
^FALL 2019 PRODUCTION FORECAST BY THE DEPARTMENT OF NATURAL
RESOURCES
1:35:15 PM
SARA LONGAN, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, was joined by her colleague Dr. Umekwe. They
would be walking through the PowerPoint Presentation: "Fall
2019 Production Forecast." She recognized and respected
that they had a significant amount of information to cover.
Mr. Stokes was also present as the new director of the
Division of Oil and Gas and the team responsible for
preparing the forecast each year.
Co-Chair Foster queried if Mr. Stokes would be joining Ms.
Longan at the table. Ms. Longan responded that Mr. Stokes
would be available if needed.
Co-Chair Foster indicated Representative Ben Carpenter was
online.
Ms. Longan reviewed the presentation outline on slide 2.
Dr. Umekwe would walk through an overview and highlights on
production including focusing on some North Slope projects
that were currently under production and would be reviewing
their timelines. In the production forecast the department
would review the objectives, provide an overview of
methodology, and share near-term and longer-term results.
Ms. Longan turned to slide 3: "State of Alaska: Oil and Gas
Resource Potential." She would not spend much time on the
slide because members were already familiar with the
information. Alaska was a large state and land ownership
was important. It could drive royalty shares from various
producing leases.
Ms. Logan turned to slide 4 containing a map with greater
detail focusing on the North Slope. She pointed out that
the state's royalty share differs across lands of the
state. She pointed to the left side of the slide that
showed the National Petroleum Reserve Alaska (NPRA) which
was managed by the Bureau of Land Management. Royalty rates
in NPRA were 12.5 or 16.66 percent. The state received half
of the royalties which were distributed through the NPRA
Impact Mitigation Grant Fund. The program was managed
through the Department of Commerce, Community, and Economic
Development (DCCED). Oil production revenues from NPRA were
used to fund planning, construction, or maintenance
projects to help offset the impacts of NPRA development to
the affected communities. If any revenues were left over
after all of the projects were financed, 25 percent of the
remaining funds could be put towards the Permanent Fund,
and other remaining balances could go to the Public-School
Trust Fund or the Power Cost Equalization Fund.
Ms. Logan highlighted the middle of the slide which showed
the state lands (shown in blue) where the major oil fields
existed including Prudhoe Bay and Kuparuk. The royalty rate
was 12.5 or 16.66 percent. The state's share was 83 percent
to 100 percent. The right-hand side of the map represented
the coastal plain of the Arctic National Wildlife Refuge
(ANWAR). The royalty rate in ANWAR was 16.66 percent. She
furthered that when there was a lease sale, the state's
royalty share was 50 percent. She noted the importance of
offshore projects. She explained that the state received
100 percent of royalties for any producing acres from zero
to 3 nautical miles offshore. Alaska's royalty share was 27
percent for any producing acres 3 to 6 miles offshore. The
state did not receive royalties for anything produced
beyond 6 miles offshore. The royalty rate for all of the
federal leases was 16.66 percent.
Representative Merrick asked how much production was
conducted offshore. Ms. Longan responded, "In short, not
much."
Representative Wool clarified that the state percentage was
a percent of the royalty percentage of 12 or 16 percent.
Ms. Longan responded in the affirmative.
Ms. Longan transitioned to the next portion of the
presentation which Dr. Umekwe would be presenting. He would
be walking through the production forecast and production
highlights.
1:40:35 PM
PASCAL UMEKWE, PETROLEUM RESERVOIR ENGINEER, DIVISION OF
OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, reported that
the forecast was the result of an interdepartmental effort
between the Department of Natural Resources (DNR) and the
Department of Revenue (DOR). There was a team within DNR
that worked on the forecast consisting of engineers,
geologists, and commercial analysts. The first part of his
presentation would cover a comparison between the forecast
and actual production as well as highlights on some of the
key projects that supported the production seen on the
North Slope and in the Cook Inlet.
Dr. Umekwe turned to slide 6: "Fall 2019 Production
Forecast: FY 2020 Outlook." The slide compared actual with
forecasted production. He pointed to the left side of the
slide showing actual production. He indicated that for the
previous 5 months of the current fiscal year actual
production had been around 490,000 barrels of oil per day
which fell in the range of the production forecast. He
explained that DNR provided DOR with a range of production
because of the level of uncertainties in all of the fields
that made up production. The department looked at the
reliability of the forecast in terms of the range. The
chart demonstrated that actual production had landed within
the range the department provided. It was about 2 percent
different from the expected mean rate.
Dr. Umekwe moved to slide 7 which showed an overall
perspective of the North Slope. He pointed to the top
right-hand side of the chart which showed production for
the previous 5 years. Production had been somewhat flat in
the first 2 or 3 years. For the prior 2 years, FY 18 and
FY 19, there was a slight drop in production. The drop
averaged to about 2 percent. There had been a 2 percent
decline over FY 18 through FY 19. The drop of 2 percent
compared well with historical decline rates seen on the
North Slope. The data showed a decline of about 4 to 5
percent on the North Slope. However, for the prior 2 years
it had remained at 2 percent. He suggested it spoke to the
amount of work that producers had done to keep production
at its current levels.
Dr. Umekwe indicated that the left side of the slide
highlighted some of the fields that supported production.
He noted modest production decline in Prudhoe Bay, about 2
percent in the prior year. He mentioned other fields that
had also experienced a modest decline of 2 percent in the
previous fiscal year including Kuparuk, Colville River, and
Nikaitchuq. There was growth in some of the other units
including NorthStar, Milne Point, and Point Thompson over
the same period. Some of the fields were shown on the
bottom right of the slide. All the bars above zero
represented fields that had experienced growth. The bars
below zero represented fields that had seen decline.
1:44:18 PM
Dr. Umekwe advanced to slide 8 showing a status update on a
few of the projects mentioned in the department's last
presentation. He pointed to the second expansion of the CD5
pad within the Colville River Unit. Next on the list was
the GMT Unit within the federally managed Moose's Tooth
Unit. Other projects included Pikka, Willow, and Liberty.
He pointed to the right column listing rates tied to the
projects. The department obtained most of the rates from
public sources. The first rate was an internal estimate
based on the number of wells that the producer intended to
drill. The other rates were based on announced peak rates.
Dr. Umekwe highlighted that often times the estimates
changed based on new information from the operators. More
details on the specifics of any of the rates seen on the
slide could be addressed directly with the operators. He
also noted the public numbers. He specified the number for
GMT2 was about $1.4 billion; Pikka was about $5 billion;
and Willow was between $4 billion to $6 billion. Overall,
about $20 billion in spending was needed to bring the
projects online. The projects were part of the companies'
plans. However, all of the plans could be reviewed based on
several factors including oil prices, the fiscal system,
costs, and other factors. He noted that the projects
competed for capital in the portfolio of each operator.
Depending on how the projects competed, capital could be
moved.
Dr. Umekwe pointed to some changes in dates from the
column, "January 2019" to the column, "January 2020." He
explained that often times a project might be scheduled to
come online in 2020 or 2021, but because of many factors a
project might go dormant. The information contributed to
the department's approach in developing a forecast. Instead
of the dates being fixed, the department considered the
dates as flexible and reflected the flexibility in the
forecast.
Dr. Umekwe continued to slide 9 showing the long-term
production outlook for the North Slope. The slide reflected
the mean estimate with a high case and a low case. He
pointed to the currently producing (CP) fields [represented
in blue] such as Prudhoe Bay, Kuparuk, Alpine, and other
popular fields. The red portion of the chart showed
production expected to come from projects that would be
done in the next 12 months (within the fiscal year). The
brown/tan color denoted projects that were further out,
between 2 years to 10 years. Looking at the rates, it was
difficult to sum up the peak rates (the rates companies
announced). The slide showed the peak rates combined with
risks and uncertainties tied to the projects. He also
pointed out that current production declined overtime. It
was a natural progression. New projects were an addition to
a declining base production. Adding the new project rates
to the current production rate of 500,000 barrels per day
to reach 700,000 would not happen quickly, as the projects
would come in at different times. The impact of all the
projects was more tamed.
1:49:17 PM
Dr. Umekwe indicated he would be addressing the second
portion of the presentation which spoke to the method or
approach the department used to generate the forecast.
1:49:32 PM
Dr. Umekwe reviewed the Fall 2019 forecast objectives on
slide 11. His team's main objective was to produce a
production forecast that could be used by DOR for
generating the state's revenue forecast. The department
also tried to apply methods that looked at both the short
term and the long term. The department tried to provide a
forecast that was reliable in the short-term helping
legislators plan for the current fiscal year and the
following year while also providing a forecast that yielded
a realistic picture of future production.
Dr. Umekwe defined the three production categories on
slide 12 used to generate the production forecast. Current
Production (CP) was the first category and included
production from fields like Prudhoe Bay, Kuparuk, and some
of the other fields online. The second category was Under
Development (UD) projects expected to come online in the
current fiscal year. The third category was Under
Evaluation (UE) projects that were further out such as
Willow, Pikka, and GMT2.
1:51:05 PM
Dr. Umekwe continued to slide 13 which focused on the level
of uncertainty his team observed in the three different
buckets of production. Most of the currently producing
fields had been online for a long time, and their outlooks
were easier to estimate. The outlook for currently
producing fields could not be taken for granted. The
production depended on spending levels the producer
incurred in fixing wells and ensuring they continued to
deliver. There were many other factors including the
performance of a reservoir itself. As a result, there was
still uncertainty around production already online. The
remaining two buckets had to do with future production:
under development and under evaluation. The commonality of
the two buckets was that the projects were not online.
There might be a level of certainty as to whether a project
would happen at a specific time. Overall, if a well was not
drilled, there was still uncertainty irrespective of how
much confidence there was in its data. Ultimately, the goal
was to see a project produce and to evaluate whether it
compared closely to the expected production. He continued
that projects under development would be wells he expected
to be drilled in the current fiscal year, FY 20. Projects
under evaluation were projects he expected to yield
production beyond FY 20.
Dr. Umekwe explained that the last bucket, projects under
evaluation, were very important because there were so many
categories of uncertainty that applied. There were
subsurface uncertainties such as brining up a field that
did not produce as much as expected or exceeded
expectations. He spoke of CD5 and the first phase of the
project exceeding the operator's forecast. He indicated
that the GMT1 project had not met the operator's expected
rate. One thing was certain, actual production did not
exactly equal expected production.
Dr. Umekwe spoke of the importance of continued focus on
short and long-term planning on slide 14. The department
tried to provide one product that served the purpose of
guiding short-term planning as well as long-term planning.
Dr. Umekwe continued to slide 15: "Forecast Accuracy: Near-
Term." He noted that the most important take-away from the
slide was that in the near-term maintenance work and some
of the operational changes that operators made in trying to
get fields to produce became important to forecasting. For
instance, if there was a change in scheduling activity like
an operator planned major maintenance in a given month and
was shifted across several months, it would affect the
accuracy of DNR's forecast in the short-term. He reported
that DNR engaged with operators with the help of DOR to
understand some of their processes and their planned
changes and to incorporate them into the forecast.
1:55:18 PM
Dr. Umekwe discussed the accuracy of the statewide forecast
in the near-term on slide 16. The Department of Natural
Resources generated the forecast in November [2019] using
data as up to date as June [2019] from the Alaska Oil and
Gas Conservation Commission (AOGCC). He indicated the graph
showed how the forecast performed. There was 5 months of
history to test the forecast the department generated. He
highlighted the black dots that represented actual
production. The bowed lines represented the mean or
expected production and the broken lines represented the
range. The department's goal was to ensure that actual
production came within the range provided. He noted that in
the last 5 months of the current fiscal year production had
aligned well within the DNR range and followed closely with
DNR's mean.
Dr. Umekwe moved to slide 17, "Realistic Long-Term
Projection." He would be discussing the long-term forecast.
He mentioned earlier that one of DNR's objectives was to
develop a product that served in the short-term and in the
long-term. In the long-term the department looked at the
behavior of fields, the long-term development plans. It
also applied engineering judgement in terms of the outlook
for fields. The department was also looking closely at the
project characteristics announced by the operators for the
fields that were yet to produce. All of the information was
considered to provide the state a robust medium-term to
long-term outlook for all of the fields.
Dr. Umekwe continued to slide 18, "Comparing Long-term
Projections". He explained that one way to test the outlook
DNR had in the long-term was to see an aggregated view of
the operators' numbers. The chart showed DNR's mean
forecast represented in red. The blue bar represented an
aggregation of submissions from operators. He noted that
DNR's confidence in its forecast was based on whether the
operators' outlook fell within the range DNR provided. The
chart confirmed that the operators' outlook fell within
DNR's forecasted range. The operators' forecast fell within
the high case forecast, shown in brown, and the low case
forecast, shown in hashed brown.
Dr. Umekwe indicated that DNR's goal was not to replicate
what the operators provided because there were some
inconsistencies in the way each operator might decide to
present an outlook. In order to generate a production
forecast product, the department used the information that
was provided publicly and applied a consistent methodology
across all projects. It took into consideration the risks
and uncertainties around each project including performance
risks, start times, and commercial risks.
Dr. Umekwe moved to slide 19: "Increasing Uncertainty as
New Fields/Projects Come Online" which showed DNR's outlook
and noted that the range of uncertainty was included at
each time in the outlook period. He highlighted that less
was known in the out years. In the distant future there
were more projects coming online. Some of them had
conceptual plans that could potentially change, and others
were still in the permitting process. He suggested that
when incorporating all of the possible risks, like a
project not starting on time or being rescoped, the outlook
showed uncertainty father out.
Dr. Umekwe turned to slide 20 related to projects under
evaluation in the medium to long-term. He pointed to the
left of the map which showed federally-owned lands. On the
right was ANWR, also federally managed (lands in which the
federal government owned mineral interests). The pink
sections of the chart showed Native land, and the blue
sections of the map showed state managed lands. All of the
projects reflected in the forecast numbers were shown on
the map. Some projects spanned the entire map. He concluded
the presentation and was glad to take questions.
2:00:59 PM
Co-Chair Foster recognized that Representative Tilton had
joined the meeting earlier. He commented that the committee
was building the budget and needed to know what the revenue
would be. A good portion of the revenue would be determined
by the price and production of oil. He referenced slide 7
and suggested that DNR's forecast for the first 5 months of
FY 21 was 506,000 barrels per day, slightly down from the
prior year of 520,000. He asked if he was correct.
Dr. Umekwe answered that slide 7 showed actual production
as observed in FY 19, the most recent fiscal year, compared
to the more distant past. Production for the first 5 months
of the current fiscal year was shown on slide 6. He relayed
that the forecasted average production for FY 20 was
506,000 barrels of oil per day. The department predicted
that production would stay relatively flat from what it was
in FY 19.
Co-Chair Foster confirmed that slide 6 showed the forecast
of 506,000 barrels per day for the first 5 months of FY 21.
Dr. Umekwe relayed that the forecast was 500,000 barrels
per day for the first 5 months.
Representative Josephson addressed a question to Ms. Longan
pertaining to slide 4. She had noted the royalties belonged
to the federal government except for a federal law that
provided for direct impact aid. She discussed how, for
example, if the borough could not represent that it needed
all of the royalty monies, some of it would make its way to
Juneau. However, there was no history to report. He asked
if he was accurate. Ms. Longan replied that he was
accurate. She reported that from FY 87 through FY 19 the
royalty amount that went through the impact grant fund was
$209 million.
2:04:30 PM
Representative Josephson asked what Dr. Umekwe could tell
the committee about production at Port Thompson. He queried
if it had reached 10,000 barrels. Dr. Umekwe responded that
there had been months where production had reached nearly
10,000 barrels. However, on an analyzed basis it had not
reached 10,000 barrels.
Representative Josephson thought that falling production
would be reflected in the later slides. He concluded that
although there was some good news, in the out years
production would decline. He suggested it would be lucky if
production stayed in the 500,000 to 600,000 barrel range.
Dr. Umekwe thought Representative Josephson had made a fair
statement based on the risks and uncertainties around the
projects as seen presently. He elaborated that because the
numbers DNR provided had incorporated risk, when the actual
projects came online, the numbers would be different. In
most cases, the numbers would exceed what was shown.
Representative Wool mentioned the previous day's
presentation from the Legislative Finance Division (LFD)
which showed the projection for 10 years out. Oil
production appeared flat with a slight decline. He wondered
how close the predictions made 10 years prior were to
current production.
Dr. Umekwe responded that DNR could provide information on
how accurate a specific year's forecast was compared to
present day numbers. In the past, there was a systematic
bias in the forecasts. In most cases, forecasts were higher
than actual production. However, there was a change in
activity levels across time. Currently, it was one of the
busiest periods in the state. The difficulties of
forecasting production changed across time based on the
number of projects in play and the level of advanced
planning. He concluded that in comparing most of the
forecasts in the past, the majority shot above actual
production numbers.
2:08:38 PM
Vice-Chair Ortiz asked, that when DNR was forecasting
production into the future beyond 5 years or 6 years, he
wondered how much was factored in when considering changes
in conditions in the Lower 48, production costs around the
world, or worldwide demand. He wondered how they influenced
the likelihood of projects coming online. He asked if
things like lowering costs of production in the Basin were
factors.
Dr. Umekwe responded that the price mechanism was the
clearest way the market saw the interplay between demand
and supply which drove the overall portfolio of production.
Costs became important when considering things such as
technology and its impact on reducing costs. There was a
correlation that many people could agree on which was that
when prices were low, they affected the costs operators
were willing to spend to bring projects online.
Dr. Umekwe spoke to the relationship between the numbers
DNR provided and potential changes that could occur. The
relationship was captured in price. The price numbers
received from DOR reflected the market's best understanding
of potential future prices. He continued that to the extent
that future prices affected the economic viability of a
given project on the North Slope, the projects were
reflected in the forecast. Projects that were significantly
challenged, such as projects in the far-flung areas of the
North Slope where the costs of bringing them online could
be around $100 to $150 per barrel, would reflect poorly on
the numbers DNR presented.
2:11:34 PM
Representative Sullivan-Leonard mentioned Pikka, Willow,
and Liberty fields. The peak rate had a potential total of
340,000 barrels. She thought it was a promising prosect
when the number was added to the current average of about
500,000 barrels. She asked if there was a reliable amount
of certainty regarding the development and success of the
projects anticipated to come online.
Dr. Umekwe indicated that projects such as Pikka and Willow
were bright spots on the horizon. The department continued
to monitor their progress. However, projects and timelines
could change. If prices fell drastically, it would be a
guess as to how fast the projects would progress. He
indicated that DNR steered away from including the rates
expected from future production projects into the current
production rate. The present day's production was
declining. He suggested that by the time the projects came
online, production might be less than the current rate. He
reiterated that there was significant uncertainty.
2:14:26 PM
Ms. Longan agreed that uncertainty always had to be
considered. She shared some level of excitement about the
three projects Representative Sullivan-Leonard mentioned
along with others. For example, the operators of Pikka,
Willow, and Liberty had contributed a tremendous amount of
capital expenditures to-date. The other part of the
responsibility of DNR was working on regulatory
authorizations. For each of the 3 aforementioned projects,
they had made huge milestones. She confirmed there were
projects that were bright spots in future development.
Representative Knopp asked about the Liberty project. He
queried if the prospect was in federal waters and whether
it was tied up in litigation. Ms. Longan indicated
Representative Knopp was correct that the Liberty Project
was in litigation and did not have significant certainty
concerning the timeline. As proposed, there was an
artificial gravel island planned 6 miles offshore. There
was a sub-c connection onshore and onshore facilities that
would bring state and local revenue taxes. There were
opportunities with the project.
Representative Knopp asked if she was referring to
production taxes bringing in revenue resulting from the
Liberty Project. Ms. Longan responded, "Yes, through
taxes." She elaborated that because the production, as
proposed, was 6 miles offshore, the state would not be
receiving royalties.
Co-Chair Foster thanked the presenters and indicated the
committee would move to the topic of the Fall 2019 Revenue
Forecast.
^FALL 2019 REVENUE FORECAST BY THE DEPARTMENT OF REVENUE
2:17:13 PM
MIKE BARNHILL, ACTING COMMISSIONER, DEPARTMENT OF REVENUE,
was joined at the table with Dan Stickle and Collen Glover.
The majority of the presentation would be presented by Mr.
Stickel and Ms. Glover. He was available to answer any
questions that might arise regarding tax, revenue, and
administration policy.
DAN STICKEL, CHIEF ECONOMIST, DEPARTMENT OF REVENUE,
reported the goal of the presentation was to provide a
high-level overview of the current state revenue forecast
which underlaid the governor's budget proposal. He would
touch on the major drivers of the oil revenue forecast in
particular because it was one of the key revenue sources.
He noted there were two elements to the Department of
Revenue's (DOR) presentation: the core presentation and
eleven addendum slides prepared in response to requests
from the other body. If there was time, he would be happy
to delve into them. He wanted to make sure the committee
had all of the information provided to the other body.
Otherwise, he could leave the slides with the committee and
answer questions later if they arose.
Mr. Stickel began with the chart on slide 3 which showed
total revenue for FY 19 and the forecast for FY 20 and
FY 21. In terms of total state revenue, the department
expected it to be relatively stable at around $11 billion
per year. The department presented revenue in the
presentation and in the Revenue Sources Book in four broad
categories consistent with the budget definitions.
Mr. Stickel elaborated that the primary category of focus
was unrestricted general fund (UGF) revenue available for
appropriation for any purpose. In FY 19 UGF revenue totaled
$5.4 billion. The Department of Revenue was forecasting
about $5 billion per year in FY 20 and FY 21. He reported
three other categories of revenue in the forecast. The
first was designated general fund (DGF) revenue which was
technically available for appropriation but customarily
appropriated for specific purposes. An example was a
portion of the alcohol tax revenue which went to the
alcohol and drug abuse treatment and prevention fund by a
customary appropriation. The second category was other
restricted revenue which was significantly more restrictive
in how it could be used. There were usually debt covenants,
constitutional prohibitions, or other solid restrictions on
how revenue could be appropriated. The third category was
federal revenue which brought in a little over $3 billion
in the previous fiscal year. All federal revenues came with
provisions on how they could be used.
2:21:16 PM
Mr. Stickel indicated that slide showed a visual depiction
of how the $11 billion total state revenue was broken out.
The largest sources were investment earnings, federal
earnings, and petroleum revenue. Investment earnings,
primarily with the Permanent Fund (PF), were currently the
state's largest single source of revenue. He continued that
beginning with FY 19, DOR was considering a portion of the
PF earnings stream to be UGF revenue. Federal revenue made
up about one third of total revenue and was entirely
restricted in how it could be used. Finally, oil and gas
made up about one quarter of state revenue. He suggested
that while other industries and revenue sources were
important to the constituents they impacted in terms of
employment and jobs, they only accounted for 10 percent of
state revenue.
Mr. Stickel moved to slide 5 which focused on unrestricted
petroleum revenue. The total amount of unrestricted
petroleum revenue was $2 billion in FY 19 and was expected
to be $1.6 billion in FY 20 and $1,4 billion in FY 21. The
primary components of revenue included: the state's share
of property tax which contributed about $120 million in the
most recent year; corporate income tax which contributed a
little over $200 million; and oil and gas production tax
which contributed $595 million in FY 19. He noted that the
production tax revenues would decline to the $300 million
to $400 million range. The reason for the decline was a
slightly lower price forecast, a slightly lower production
forecast, and higher spending by the oil companies. A
combination of the factors placed the production tax regime
into the minimum tax regime. He would touch on what it
entailed further into the presentation.
Mr. Stickel continued that all of the taxes were dwarfed by
the revenues that royalties brought in. State royalties
generated $1.1 billion in FY 19. The amount was projected
to decrease in FY 20 and FY 21 due to three factors. First
was the lower price in production the state would receive
a royalty on a lower value of oil. The second was a growing
share of incoming production coming from non-state land.
For example, the state was not receiving the unrestricted
royalty on NPRA development. The third factor had to do
with a provision around PF sharing. In FY 19, 25 percent of
royalties were deposited into the PF which was required by
the constitution. In FY 20, a higher amount averaging 50
percent for certain leases, but 30 percent of total
royalties, was deposited to the PF. It had to do with a
statutory provision that allowed for a higher deposit into
the PF of royalties for certain leases. The forecast
assumed the higher statutory deposit in FY 21 and beyond.
2:25:05 PM
Mr. Stickel turned to slide 6 which highlighted some of the
key changes to the unrestricted revenue forecast compared
to the spring forecast released the previous March. He
indicated that for FY 19 the Alaska North Slope (ANS) oil
prices came in $.56 per barrel above the department's
spring forecast. However, unrestricted revenue was about
$50 million below the spring revenue forecast. The primary
reason for the shortfall had to do with production tax
which came in $140 million below DOR's forecast. There were
higher than expected refunds for the 2018 tax year that the
state paid out as well as attributing some production tax
payments for the constitutional budget reserve (CBR) fund
at the end of the year reducing the general fund portion of
the production tax.
Mr. Stickel reported that for FY 20 and FY 21 the
department reduced the price forecast for both years by
$2.46 for FY 20 and by $7.00 for FY 21. The department was
currently forecasting $59 per barrel in FY 21. The
reduction in price forecast was the primary reason for the
reduction in the revenue forecast for both years.
Mr. Stickel advanced to slide 7: "Total Percent of Market
Value (POMV) Transfer Forecast." He included the slide
since the PF was the largest source of unrestricted
revenue. He highlighted the FY 19 transfer to the general
fund of about $2.7 billion as well as the 10-year forecast
reaching $3.8 billion by FY 29. The amount of the transfer
was available for dividends and/or general government
spending as the legislature saw fit. The transfer forecast
was based on the POMV of the fund. He reported that for
FY 19 through FY 21 the transfer was 5.25 percent of the
average market value of the first 5 of the last 6 fiscal
years. He indicated that for FY 22 and beyond the transfer
was 5 percent of the market value. The forecast for the
POMV was dependent on investment returns and oil
production. The forecast assumed a 7 percent annual average
return on the fund as well as ongoing mineral deposits that
brought hundreds of millions of dollars into the fund per
year.
Representative Ortiz referred to the 7 percent rate of
return. He thought the Alaska Permanent Fund Corporation
(APFC) had reported the average return rate to be 6.5
percent.
Mr. Stickel responded that the 6.55 percent was the
expected rate of return when DOR prepared the spring
forecast. However, 7 percent was the new rate of return
from APFC and was reflected in the fall forecast.
Mr. Stickel advanced to slide 9 and the department's price
forecast. He relayed that the department made a change to
the price forecast methodology. He explained that
previously the oil price forecast was based on a survey
approach where DOR brought a group of state employees and
experts together for a day-long session in the month of
October. The group studied oil market trends and ultimately
came up with the oil price forecast. There were various
issues with the survey-based approach. It was very time
intensive, not exceedingly transparent to the public, and
by the time the forecast was released in December the
information was stale. Frequently, the department ended up
adjusting the forecast at the last minute not using the
results of the day-long meeting.
Mr. Stickel conveyed that in the current year the
department developed a methodology that used price
forecasts from the futures market for the following 2
years. The department was able to compile the price
forecast on Monday, December 2, 2019, and release the
entire revenue forecast on the following Friday, December
6, 2019. The result was a timely price forecast. The
forecast relied on the Brent futures prices as of Monday,
December 2nd and was fully documented. Therefore, anyone
could replicate how the department determined its price
forecast. One issue that arose in preparing the forecast
was that historically, Alaska North Slope (ANS) crude oil
and Brent crude oil traded very closely (trading in
parody). However, currently ANS crude oil was trading at a
$2 premium to Brent crude oil for a variety of reasons. The
department acknowledged the information in the forecast. He
furthered that the $2 premium was incorporated currently
and assumed that it would phase out throughout FY 20
returning to parody by FY 21.
2:30:21 PM
Mr. Stickel drew attention to the chart on slide 10 which
showed 4 years of historical oil prices and 4 years of
projections from various forecast sources. The prices were
for Brent crude oil and were in real terms, so they
excluded the impacts of inflation. He highlighted the
department's Fall 2019 forecast remained fairly in line
with the futures market over the near term. It was actually
slightly higher than the futures market over the long term
due to DOR's decision to hold prices constant beyond the
budget year in real terms. The department's price forecast
was slightly below what the average oil market analyst was
saying and several dollars per barrel below what the
Federal Energy Information Agency was projecting. The take-
away from the slide was there was a range of forecasts from
the mid $50 to the mid $60 per barrel. The department's
forecast looked to be within the range, possible slightly
more conservative. However, DOR knew its price forecast
would be inaccurate.
Mr. Stickel advanced to slide 11 which provided a
sensitivity analysis showing how revenue would change based
on certain oil prices. He highlighted that for FY 21 the
official forecast was $59 per barrel which generated just
under $2 billion of UGF revenue excluding the POMV transfer
from the PF. Around current prices each $1 change in the
ANS price would result in a change of about $30 million to
$35 million UGF revenue.
Mr. Stickel indicated there were a couple of slides that
touched on the production forecast which the committee just
heard about from DNR. Slide 13 was a reminder of some key
provisions. The Department of Revenue worked closely with
DNR to produce the production forecast and represented a
most likely value within a range of potential outcomes.
Mr. Stickel turned to slide 14 that showed the official
production forecast for the following 10 years as well as
high-case and low-case sideboards. He mentioned that there
was a slight difference in DOR's production numbers and the
numbers presented by DNR. The difference had to do with how
DOR treated natural gas liquids used in enhanced oil
recovery barrels produced at Prudhoe Bay, shipped to
Kuparuk, and reinjected into the Kuparuk reservoir to
support enhanced oil recovery there. The department
excluded an assumption of 10,000 barrels per day of natural
gas liquid shipments from the production numbers that DOR
reported in the Revenue Sources Book. The reason for the
exclusion was because the numbers did not go into the Trans
Alaska Pipeline (TAPS) and were not considered produced for
tax purposes. However, DNR considered the barrels for
royalty purposes.
Mr. Stickel moved to the cost forecast on slide 16. He
reported that the cost of production was tracked closely
for 2 reasons. First, the cost of production was a
barometer of company investment in the state which
ultimately led to future production and supported current
production. Secondly, production costs were an integral
part of the production tax calculation. Companies were
allowed to deduct most costs of production in calculating
their production tax liability which included ongoing
operational costs and capital expenditures with no
depreciation requirement.
2:34:16 PM
Mr. Stickel relayed that slide 17 showed a 10-year history
and forecast of allowable lease expenditures for the North
Slope. The department used several different sources to
develop its forecast. The most valuable source was
information obtained directly from the operators every 6
months. They provided a detailed expectation for spending
for each unit in the state. The department also looked at a
variety of public information about ongoing developments
and future developments as well as historical spending
companies reported in their tax returns. The department
applied a risk factor to costs expected for any new units
that were in accordance with the risk factors used on the
production side. There was some agreement between the lease
expenditure forecast and the production forecast.
Mr. Stickel continued that in looking at the chart both
operating and capital expenditures peaked in FY 15 and
declined for several years as oil prices fell. In FY 19
allowable operating expenditures were $2.9 billion. The
department expected them to decline slightly to $2.7
billion in FY 21 before climbing to $3 billion by FY 24 and
remaining level. He indicated that the information was
based on declining production over the near-term and new
fields coming online later in the decade.
Mr. Stickel thought capital expenditures told a more
interesting story. In FY 19 capital expenditures were $2.2
billion which was the first increase after 3 consecutive
years of declines in capital spending on the North Slope.
The Department of Revenue was expecting the increase to
continue with $3.6 billion of North Slope capital spending
in FY 22. The information was based on spending for large
new developments like Pikka and Willow. The department had
a forecast of capital spending tapering off later in the
decade. However, as additional new developments became
identified or more likely, there was a potential upside to
the forecast.
Mr. Stickel moved to slide 18 which looked at
transportation costs with a 10-year history and forecast.
They were costs associated with pipelines including TAPS as
well as marine transportation costs for getting the oil
from the North Slope to market on the West Coast. The costs
were important because they were deducted against the gross
value calculation for both tax and royalty purposes. In
general, what the department observed was as volume went
down, transportation costs on a per barrel basis went up.
Additional production in the pipeline had the potential to
reduce transportation costs. He also noted there was a
decline in costs in FY 19, as there was a change in how
TAPS tariffs were calculated which contributed to the
decline. He turned the presentation over to Ms. Glover.
2:37:39 PM
COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF
REVENUE, would discuss a subset of the tax credits - only
those available for purchase by the state. She turned to
the graph on slide 20, a representation of the balance of
those outstanding credits at the time that the Revenue
Sources Book (RSB) was generated. The balance was estimated
to be approximately $740 million which was represented by
the blue bar in the 2020 column. The gray bars showed the
amount the department estimated that the state would
purchase according to the formula in statute. The graph
showed when the purchases would occur. There was the
potential for the tax credit bonding program to proceed and
the gray bars would be used in the calculation for the
discount values if it occurred.
Ms. Glover turned to slide 21: "Tax Credit Bonding Update."
She reported that there was legislation passed in 2018 to
allow the state to issue bonds to pay off the outstanding
tax credits. The legislation was tied up in litigation with
the Alaska Supreme Court. Until a decision was made, the
state would hold off on issuing any bonding packages.
Ms. Glover continued to slide 23 which provided an annual
update regarding oil and gas production tax audits. On the
positive side, the division was working aggressively to
reduce the backlog of production tax audits. All of the
2013 audits were completed in the prior year. Currently,
the division was working on the 2014 audits and
incorporating efficiencies and streamlining the audit
process. The division intended to complete the backlog and
move to a 3-year cycle. The production tax was the only tax
that had a statute of limitations of 6 years for audits,
all the others were 3 years. She spoke to the advantages of
a 3-year audit cycle and getting current.
Ms. Glover continued that another positive improvement was
that currently the division was fully leveraging the tax
revenue management system which was paying large dividends.
She explained that tax returns, starting with 2014, were
filed in the system making data available in the system to
be explored and used for audit papers instead of having to
generate the papers by hand. The team spent a significant
time planning for the change and testing the system to
ensure that the exported data would be accurate. Another
positive improvement in the process was having a documented
audit plan with each taxpayer being audited which
identified communication protocols, scheduled
communications, scope, and deliverables on both sides. The
division met with each taxpayer and agreed to protocols.
The division had received positive feedback about the
engagement meetings. She concluded the presentation.
Co-Chair Foster referred to the addendum section of the
presentation. He wondered if any of them were of particular
interest.
Mr. Stickel pointed out slide 29 which showed a brief
history of North Slope oil employment. He highlighted that,
according to preliminary data from the Department of Labor
and Workforce Development, North Slope oil employment
increased in 2019 for the first year following several
years of declines. He noted that it lined up very closely
with the capital expenditures information which also showed
the first year of increase following several declining
years. The department was forecasting significant increases
in capital expenditures. If the trend held, there was
reason to be optimistic about potential oil employment over
the following several years.
2:43:25 PM
Mr. Stickel touched on slide 32 briefly. The department was
asked to address the potential impacts of the International
Maritime Organization (IMO) 2020. He explained that IMO
2020 was a new requirement, effective January 1, 2020 to
use lower sulfur marine fuel in marine transportation
across the world. Refineries had been scrambling to meet
the demand for the new lower sulfur oil. He explained that
while Alaska North Slope crude was not a low sulfur oil, it
was on the lower side of the sulfur content and was easily
blended by refiners to create the low sulfur marine fuels.
The department had seen a premium compared to other
benchmarks such as Brent and the global market. The
provisions related to the IMO 2020 were part of the reason
for the premium. Other reasons for the premium included a
supply crunch on the West Coast market where there had been
lower production for ANS as well as competing crudes from
Iran and Venezuela. He acknowledged that IMO 2020 had had
significant impacts in the refining industry and on ANS
prices the department saw it as a temporary impact.
Mr. Stickel reported that slide 33 had to do with the
crossover point between gross and net tax under the
production tax. He explained that it was the point at which
the 35 percent net tax less per barrel credits began to
exceed the 4 percent gross tax floor. In the spring
forecast DOR estimated a crossover point in the mid $60
based on the spring forecast, production, and spending for
FY 20. In the fall forecast the department was currently
estimating a crossover point near $80 per barrel which was
based on slightly lower production as well as significantly
higher spending for FY 21. The department was expecting to
be in the minimum tax regime given DOR's price forecast
over the time horizon over the following decade. He
indicated that it was a result of a combination of a
slightly lower production forecast and the expected
increase in company spending into the future.
Mr. Stickel reported that slide 36 demonstrated that not
all oil was the same. The chart showed various categories
of land in Alaska and how royalties and taxes applied for
each of the categories of land. He stated that for the tax
pieces, the state's taxes applied to all land in the state
within 3 miles offshore regardless of ownership. Royalties
varied depending on the land ownership. He was available
for questions.
Vice-Chair Ortiz referred to slide 11. He asked if there
was a certain price where the state crossed over from gross
tax to net tax. Mr. Stickel responded the crossover point
was different for each taxpayer. On aggregate under the
fall forecast the crossover was around $80 per barrel.
Acting Commissioner Barnhill directed attention to page 33.
2:47:56 PM
Vice-Chair Ortiz referred to slide 16 about the net taxable
revenues being less than 4 percent. He wondered if the per
barrel credit had been factored. Mr. Stickel responded that
he was correct. He explained that 35 percent of net minus
the taxable per barrel credit had to be compared to the 4
percent gross tax floor.
Representative Ortiz clarified that there should have been
a reference to the per barrel credit on the slide. Acting
Commissioner Barnhill responded that it was encompassed in
the word, "net."
Co-Chair Johnston asked if the Tax Revenue Management
System (TRMS) was online and running presently. Ms. Glover
responded in the affirmative. Co-Chair Johnston wondered if
the documented audit plans were online. Ms. Glover
responded that the audit plans were not public documents.
Co-Chair Johnston clarified that she was wondering if both
were being done within the system. She thought it was a
hopeful improvement. Ms. Glover replied that the system had
made it more efficient for the division to complete audits
more expediently with better access to data. The division
was confident about returning to a 3-year audit cycle in
the near future.
2:50:02 PM
Representative Josephson referred to slide 6. He wondered
about the administration's policy about moving additional
royalty monies beyond the 25 percent to the constitutional
budget reserve (CBR) versus the general fund. He thought it
was the previous administration that changed the policy. He
asked for an explanation of the change and what was in
dispute. He suggested there was a difference of opinion.
Acting Commissioner Barnhill responded that under the
constitution 25 percent of royalties were dedicated to the
PF. The question was related to the PF rather than the CBR.
The constitutional phrase started with the words "At least"
25 percent of royalties were dedicated to the PF. He
continued that by statute, the legislature added another 25
percent to the established 25 percent dedication for new
leases issued on or after 1980. Historically, the statutory
increase for new leases had been viewed as an additional
dedication - instead of 25 percent it was 50 percent. The
court dispute had to do with whether the phrase "at least"
composed a constitutional dedication. The question was
whether the additional 25 percent bypassed legislative
appropriation. He reported that the Department of Law did
not view the additional 25 percent for new leases as a
constitutional dedication. Rather, it required
appropriation. There were other opinions that it was a
constitutional dedication not requiring legislative
appropriation.
Acting Commissioner Barnhill continued that for 2 years the
Walker Administration did not submit the additional 25
percent to the legislature for appropriation, and they were
not appropriated. The additional 25 percent was in the
budget for FY 20 and FY 21. He believed the Division of
Legislative Audit subscribed to the view that the money was
dedicated and should be placed in the principle of the PF.
In the previous year, they proposed a mechanism to do so
which was not embraced. Therefore, the issue and dispute
still existed around not moving the extra 25 percent into
the principle of the fund for 2 years.
Representative Josephson reported there were vetoes of some
efforts to move royalty monies under the statute under
HB 39 [Legislation that passed in 2019 regarding the State
Operating Budget] or HB 2001 [Legislation passed in 2019
regarding appropriations, the Earnings Reserve Account,
operating, funds, and other]. Acting Commissioner Barnhill
did not remember the mechanism by which the money did not
move. He did not recall it being a veto. He could get back
to the committee on the details of how it came to be.
2:54:35 PM
Representative Josephson asked about the carry forward
lease expenditures. They had to be used within a decade or
they would be lost. He wondered if it had influenced the
speed at which explorers worked. He thought it was one of
the main reforms from SB 111 [Legislation introduced in
2019 - Short Title: OIL/GAS LEASE:DNR MODIFY NET PRO]. He
wondered if there had been concern over potentially loosing
capital expenditure dollars.
Mr. Stickel thought the representative made a good point.
He responded that there was a provision regarding carry
forward lease expenditures since the net operating loss
credits had been phased out on the North Slope that if a
company incurred a net operating loss, they could carry
forward the excess lease expenditures in offsetting future
years of tax liability. The value of the lease expenditures
began to degrade following the eighth or eleventh year
after the lease expenditures were earned. He expected that
companies would factor the information into their economics
and their plans. A good question for companies to consider
was whether it was enough to change development and
production decisions.
Representative Josephson asked about another reform in
SB 111 regarding an increase in the interest charge for
failure to timely pay what the department thought was owed.
The amount was reduced in SB 111, but there was an increase
overall since SB 21 [Legislation passed in 2013 regarding
oil and gas production tax]. He was concerned whether
better returns had been produced in a timelier fashion.
Ms. Glover replied that the interest really played more
into the audits and the timing of their completion with the
interest clock ticking. She elaborated that the taxpayer
filed monthly returns and annual returns. It was a factor
in the audit timeline and the fact that interest was
occurring until an audit was assessed and even after it was
resolved or paid.
Representative Josephson assumed if the interest rate was
increased, companies would be extra careful, possibly
overpaying to avoid interest penalties. He asked if the
state had seen anything similar.
Ms. Glover replied, "Not typically." She indicated it would
be a concern for the companies regarding the state's timing
of issuing an audit. She had not seen taxpayers overpay to
circumvent additional interest accruing. At the time they
paid their return they did not know the amount of the audit
assessment. She was unaware of additional payments being
made presently.
2:58:40 PM
Acting Commissioner Barnhill readdressed Representative
Josephson's question regarding the veto. He indicated the
proposed solution by the Division of Legislative Audit to
pull money from the ERA and put it into the principle to
pay the 2 years-worth of the addition 25 percent on the new
leases was what had been vetoed by the governor.
Representative Wool referred to slide 3. He queried about
the $563.5 million of petroleum revenue under other
restricted revenue. Mr. Stickel replied that it was the
portion of oil and gas royalties that went to the PF as
well as any settlements from tax and royalty disputes that
went to the CBR fund.
Representative Wool asked for the CBR amount. He was aware
money had to be repaid to the CBR but was unsure who
enforced it. Mr. Stickel responded there were two issues.
First, there was a requirement to pay back money that was
used out of the CBR in the budget process. However, what
was really being discussed on the slide was that any
revenue resulting from tax or royalty disputes with
producers was deposited into the CBR, as stipulated in the
constitution. He reported that for FY 19 the deposits
amounted to $181 million in petroleum revenue. The
department was forecasting $200 million for FY 20 and $75
million for FY 21.
3:01:33 PM
Representative Wool noted the decline from $2 billion in FY
19 to $1.5 billion then down to $1.4 billion. He remarked
about the significance of the reduction over the following
couple of years. He wondered if the cut was based solely on
price because the production forecast was within a slight
margin of error. He wondered if the cut was based on price
and the prediction of price. He thought the cut was
drastic.
Mr. Stickel replied that one thing to keep in mind when
looking at slide 5 was that it represented only the
unrestricted portion of petroleum revenues. The state was
also receiving between $400 million and $600 million of
restricted petroleum revenues. Looking at the unrestricted
petroleum revenues, the price was expected to be lower than
it was in FY 19. Production was expected to be slightly
lower and company spending was expected to be significantly
higher. Slightly lower production and higher company
spending moved the state into a regime where companies were
paying at the gross tax floor instead of the higher net tax
impacting the tax side. The combination of the additional
deposits going to the PF reducing the unrestricted general
fund share of royalties as well as a lower value for oil
affected royalty revenues. As a greater share of oil
production was generated from NPRA and other non-state
lands, the state would end up getting less royalty revenue
overall.
Representative Wool referred to slide 29 that showed
employment which tracked with capital investment. He asked
how closely it tracked with the price of oil.
Mr. Stickel responded that there was a correlation between
all three. The decrease in spending correlated with the
lower oil price which also correlated with a reduction in
employment. Companies were trying to figure out how to
maintain viability of the operations given the lower oil
prices. As prices had recovered, capital spending and
employment started to recover in FY 19.
3:05:24 PM
Representative Wool noted production followed price. He
relayed that the department was predicting lower pricing
over time. He asked if the department had done a 10-year
prediction. He wondered about the previous 10-year
prediction. He asked about biases in previous predictions.
Mr. Stickel responded that one thing the department noticed
in the oil price forecasts was they tended to anchor
heavily to the current price. He suggested that when oil
prices were above $100 per barrel, the department was
forecasting prices above $100 per barrel for a long time.
Depending on which forecast someone looked at, the
department likely missed the mark. He thought there was one
forecast about a decade earlier that forecasted prices
around $59 per barrel to $60 per barrel presently. The
department changed the forecast methodology because it was
putting a significant effort into a fine point on the oil
price forecast which turned out to be inaccurate. After
some analysis, the department found that using the futures
market to generate a forecast was just as accurate with
much less effort.
Acting Commissioner Barnhill added that if the chart was
pushed back a year, the prices were up over $100 per
barrel. Oil prices were extremely volatile and had been for
a long time. He mentioned that the department had observed
over the prior year that volatility seemed to have
decreased. There had been a number of substantial
geopolitical events over the previous few months. In the
past, oil would spike then drop. He suggested that 10 years
prior the markets were fairly reactive to such events but
were less so currently.
Co-Chair Johnston was pleased with how the revenue
forecasts were being done based on the futures market. She
spoke of the price hitting $85 per barrel for one day in
the prior year.
3:09:15 PM
Co-Chair Foster surmised that, looking at UGF revenue, the
state could anticipate fairly flat revenue overall.
Unrestricted general fund revenue was up about $10 million.
Petroleum revenue was down by about $150 million but offset
by non-petroleum revenue as well as the POMV which was up
by about $160 million. He reiterated that revenue was
fairly flat. He asked if the presenters had anything to
add.
Acting Commissioner Barnhill responded that Co-Chair
Foster's observations were correct. For the previous
several years the state had been in the midst of a
fundamental paradigm shift in terms of where the state
revenues came from. The change had led to protractive
discussions within the legislature and across the state.
Co-Chair Foster thanked the presenters and reviewed the
agenda for the following day.
ADJOURNMENT
3:11:05 PM
The meeting was adjourned at 3:11 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| DNR Production Forecast HFIN 1.23.20.pdf |
HFIN 1/23/2020 1:30:00 PM |
|
| Fall 2019 Revenue Fcst Presentation_20200122_1130a.pdf |
HFIN 1/23/2020 1:30:00 PM |
DOR Fall Forecast HFIN |
| DOR Response to House Finance 2020-03-03.pdf |
HFIN 1/23/2020 1:30:00 PM |