Legislature(2023 - 2024)ADAMS 519
04/04/2024 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB233 | |
| HB387 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB 223 | TELECONFERENCED | |
| + | HB 387 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
April 4, 2024
1:34 p.m.
1:34:36 PM
CALL TO ORDER
Co-Chair Foster called the House Finance Committee meeting
to order at 1:34 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Neal Foster, Co-Chair
Representative DeLena Johnson, Co-Chair
Representative Julie Coulombe
Representative Mike Cronk
Representative Alyse Galvin
Representative Sara Hannan
Representative Andy Josephson
Representative Dan Ortiz
Representative Will Stapp
Representative Frank Tomaszewski
MEMBERS ABSENT
None
ALSO PRESENT
Representative George Rauscher, Sponsor; Craig Valdez,
Staff, Representative George Rauscher; John Crowther,
Deputy Commissioner, Department of Natural Resources; Derek
Nottingham, Director, Division of Oil and Gas, Department
of Natural Resources; Representative Tom McKay, Sponsor;
Trevor Jepsen, Staff, Representative Tom McKay.
PRESENT VIA TELECONFERENCE
Jhonny Meza, Commercial Manager, Division of Oil and Gas,
Department of Natural Resources; Brandon Spanos, Acting
Director, Tax Division, Department of Revenue.
SUMMARY
HB 223 TAX & ROYALTY FOR CERTAIN GAS
HB 223 was HEARD and HELD in committee for
further consideration.
HB 387 OIL & GAS TAX CREDIT: JACK-UP RIG
HB 387 was HEARD and HELD in committee for
further consideration.
Co-Chair Foster reviewed the meeting agenda.
HOUSE BILL NO. 223
"An Act relating to the production tax and royalty
rates on certain gas; and providing for an effective
date."
1:36:46 PM
REPRESENTATIVE GEORGE RAUSCHER, SPONSOR, introduced HB 223.
He read the sponsor statement (copy on file):
House Bill No. 223 represents a crucial step in
revitalizing Alaska's critical natural gas industry in
the Cook Inlet sedimentary basin and acts as a
legislative response to the impending natural gas
availability shortage. This bill addresses a
longstanding barrier to new investment and production
in this sector: the current royalty rates. By
proposing strategic modifications to these rates, HB
223 aims to elevate Alaska's competitiveness and
attractiveness for natural gas investments in new and
underutilized fields.
This legislation introduces a significant adjustment
to the royalty rates and payments structure for
certain oil and gas production, by reducing the
royalty payments to zero for qualified new gas and
cutting the minimum fixed royalty share by 50% for
qualified new oil, this legislation creates a more
favorable economic environment for energy companies to
invest in untapped resources. These incentives are
designed to catalyze the commercial production of oil
and gas from fields or pools that have not been
previously utilized for commercial sale before January
1, 2024.
This legislation is a testament to Alaska's commitment
to fostering innovation and investment within the
energy sector, addressing the immediate challenges
faced by the Cook Inlet and Railbelt region, and
laying the groundwork for a prosperous and energy-
secure future. The enactment of House Bill No. 223
will mark a significant step forward in achieving
these objectives, demonstrating Alaska's proactive
approach to energy policy and economic development.
1:39:11 PM
CRAIG VALDEZ, STAFF, REPRESENTATIVE GEORGE RAUSCHER, read
the sectional analysis (copy on file):
Section 1: AS 38.05.020(a)
Page 1, lines 7,8
This section amends the Authority and Duties of the
Commissioner so they shall make determinations under
new subsections (mm) and (nn)
Page 1, lines 9 through 12
Directs the Commissioner to adopt regulations as
necessary to carry out subsections (mm) and (nn),
including differentiating qualified new oil and gas
production from existing fields or pools.
Section 2: AS 38.05.180
Page 1, lines 14 through Page 2, line 9
A new subsection, (mm), is added to introduce terms
for complete payment of royalties due to the state for
qualified new gas and oil produced from the Cook Inlet
sedimentary basin, specifying a zero royalty for
qualified new gas and a 50% minimum fixed royalty
share for qualified new oil, under certain conditions.
Page 2, lines 11 through 26
A new subsection, (nn), is added to define "qualified
new gas" and "qualified new oil," including criteria
based on production commencement dates and economic
feasibility of producing from new wells.
Section 3:
Page 2, line 27
Repeal of Sections AS 31.05.030(i), AS
38.05.180(f)(5), and AS 38.05.180(dd): Simplifies the
regulatory framework and aligns provisions with the
current needs of Alaska's oil and gas industry,
removing outdated or redundant criteria to encourage
development and streamline operations.
Section 4:
Page 2, line 28
This Act takes effect immediately under AS
01.10.070(c).
Co-Chair Foster asked if the sponsor would like to comment.
Representative Rauscher added that there had been a couple
of different versions of the bill, but the core of the bill
remained relatively the same. The governor and his staff
decided that the governor's version of the bill would merge
with the existing version and elements from both bills
would be combined. He explained that a representative from
the administration was also available to talk about the
bill.
Co-Chair Foster suggested that the Department of Natural
Resources (DNR) give its presentation.
1:44:35 PM
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, introduced the PowerPoint presentation "HB 233
Tax and Royalty for Certain Gas" dated April 4, 2024 (copy
on file). He explained that Mr. Derek Nottingham would be
providing the majority of the presentation. He hoped the
presentation would help the committee understand the
mechanics of the bill. The slides would detail the
projected outcome of the bill, which was influencing new
oil production.
DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, began on slide 2, which
detailed the "runway" of Cook Inlet gas with the maximum
state fiscal incentives. The slide did not reflect the
specific impacts of HB 223, but examined the runway, which
was the amount of gas that could be available if the
state's fiscal system, production taxes, state property
tax, and royalty were maxed out or taken to zero. He
explained that the blue line was the forecasted runway. The
gray line represented that technical forecast and did not
include the commercial aspects of the individual fields and
pools. The gray line was Cook Inlet's gas capability
excluding any real commercial constraints. By simply
reducing the fiscal system, the runway would build out to
about 2029 and the shortfall would be below the 70 billion
cubic feet (BCF) parameter. The projects that could be
coming online in Cook Inlet could create a surplus if the
projects were activated within the projected timeframe. The
maximum runway was represented by the black dashed curve
which showed when gas would be sold into storage, put away
for later use, and then sold into the market in the future.
The chart indicated that if the gas was brought online by
2037 and properly incentivized, it could be in the "cooking
lab."
1:49:11 PM
Mr. Crowther noted that there was a large amount of
information on the slide. He thought that it was
consequential to show that it was valuable to energy
supplies if the fields could be brought online and continue
to produce. The continuation of the fields would be
dependent upon provisions found in HB 223 and similar
pieces of legislation. He asked if there were questions.
Representative Josephson understood that the technical
forecast was synonymous with the term "no commercial
restraints." He asked if Mr. Nottingham could elaborate.
Mr. Nottingham responded that he meant that if the market
was in line with the current fields and operating at a
certain cost, the fields would continue to decline. He
explained that as the fields declined, the per thousand
cubic feet (MCF) cost increase in some fields within the
next few years would not allow the fields to generate
positive cashflow. The fields represented by the blue line
would shut down because the fields would no longer be able
to sufficiently operate at a profit. The technical forecast
assumed that there was no requirement for a positive
cashflow and the fields would technically be able to
continue to produce if economics were not a factor.
Mr. Crowther added that the cost presumptions, while
presented to be informative, were technical and complex. He
noted that the cost holding and the untruncated forecast
did not take the consumer price into account. There was a
price interplay that was not depicted on the chart but was
an interesting proxy for what could be recovered
irrespective of cost. If consumer prices dramatically
escalated, the gray line could become more accurate than
the blue line. He stressed that consumers would bear the
cost. He remarked that it was a rough description of a very
complex set of assumptions and deductions.
1:52:42 PM
Representative Galvin had a question related to the tan
colored portion of the chart representing known but
undeveloped gas resources. She asked whether DNR currently
had the authority to reduce the royalty if it would make a
project more economic.
Mr. Nottingham responded that there were specific statutes
that allowed the department to reduce royalties. One of the
issues was that the statutes had strict requirements in
order to prove that the royalty modification was necessary.
The process was lengthy and the outcome was uncertain for
companies. He felt that it was important to provide
certainty to potential developers in the Cook Inlet.
Representative Galvin asked Mr. Nottingham why there was a
need for something more broad-based and infinite. She
understood that the department could already reduce
royalties and it was not helping.
Mr. Crowther responded that Representative Galvin was
correct and the short answer was that the department could
already offer royalty relief. There were a couple dynamics
that made the process challenging for operators. The first
challenge was the requirement to develop, submit, and
review analysis data, and develop, according to the
statutory standard, a very clear finding that the project
is not economic. The submission then had to be reviewed by
the Legislative Budget and Audit Committee (LB&A). Once the
analysis was complete, it was a slow process for the
modification to go into effect. While the authority was
available, the benefit of HB 223 was that it would be
easier to offer relief as the timeframe would be greatly
reduced. A long analysis would not be required and there
would not be a runway of uncertainty before data could be
presented to the legislature and for the modification to be
put into effect. The department had offered royalty relief
on the North Slope for a few projects, but it was
complicated and the legislation would immediately promote
investment.
1:56:34 PM
Representative Galvin understood that it was appropriate
given the circumstances for a broad based form of relief as
opposed to a more precise approach. She thought it was
important for the legislature to understand the approach
because some companies would already be taking in data to
determine whether or not it was economic. She suggested
that perhaps the state was asking for more information than
was necessary. She agreed that the process sounded
complicated.
Representative Stapp asked what the material difference was
between the various approaches. He looked at the maximum
state fiscal incentives, zero royalties, zero production,
and zero property tax at the bottom of slide 2. He asked
why it would not be logical to simply allow the price to
float upward to compensate for the margin.
Mr. Crowther responded that there were a couple of policy
considerations driving the choices. One of the
considerations was that the market changes could be abrupt
and contracts would need to be facilitated at different
prices, which would then be subjected to a review which
could frustrate financing up front due to the slow
timeline. The other consideration was that the department
aimed to develop natural resources of all kinds and the
governor's energy policy was focused on access to
renewables and working on transmission, among other topics.
There were situations in which the price would increase
above switching prices for other resources. The department
thought the most effective strategy was to ensure that the
state had a highly competitive royalty environment, was
making appropriate investments, encouraging companies to
make investments, and bringing resources into development
in the near term. The goal was to allow the market and the
price to compete for the best options and to extend the
shortfall.
2:00:28 PM
Representative Stapp asked if the issue was that the gas
was available, but the projects would not yet make economic
sense. There was either a problem with the cost for
production, or the price at the point of sale. He
understood that the bill would effectively make the cost at
point of production as low as possible and the state would
no longer receive royalties or property taxes. He suggested
that the other way to accomplish it would simply to mandate
that producers pay double the price in gas. He asked if it
would have the same impact as the bill.
Mr. Crowther responded that there was some price level that
would have a similar effect, although the mechanics would
be different. The purpose of the legislation was to control
the levers to encourage investments. The price was already
moderating in response to the supply, and both forces would
likely drive increased supply.
Representative Galvin thought that the bill could have a
great outcome. She wondered if it would be pointless to
offer relief for the whole lease time period, as opposed to
a limited time frame such as 15 years to allow for income
to build.
Mr. Crowther replied that page 2, line 6 of the bill
referred to a time limit in the 10 years following the
commencement of commercial production that would begin
after July 1, 2024. The legislation included a cap for the
period under which royalty reduction would be available.
There was a resource development potential in Cook Inlet
that would continue to be present for years, and it was
unlikely that there would be a massive expansion of supply.
However, in the event that there was an expansion, a time
limit would be in place.
Representative Galvin asked if the department expected it
to take 10 years before gas was developed and provided to
Alaskans.
2:04:32 PM
Mr. Nottingham responded that the royalty provision would
only apply when a well was in production or development.
The timeframe of 10 years was only applicable to the first
10 years of the production of the new pool. There was a
slide later in the presentation that would show the typical
timeframe for a major gas project in the Cook Inlet, which
was four to six years. The 10-year timeframe would allow
the project to achieve payout as well as provide some
buffer time.
Representative Josephson remarked that he was frustrated
with slide 2. The slide said there were known but
undeveloped gas resources and there would be more
production if the state provided maximum fiscal incentives,
of which he was aware. He was confused about the part of
the slide that referenced "billion cubic feet." He thought
that the slide demonstrated basic economic principles that
he was already aware of, but beyond that information, he
had not learned anything new.
Mr. Crowther apologized for the ambiguity. He explained
that the billion cubic feet per year referred to
consumption per year. The intent was to show the production
possibilities relative to the estimated demand of about 70
billion cubic feet per year.
2:07:07 PM
Mr. Nottingham continued on slide 3 to explain why the
legislation was necessary. He relayed that 70 percent of
Alaskans used Cook Inlet Natural Gas for power and heating.
Gas was forecasted to drop below the demand of 70 BCF per
year within the next few years and action was needed.
Improved fiscal terms would directly impact project
economics, such as payout and rate of return for developing
companies. Royalty reduction was a mechanism that DNR could
implement expediently, and the resulting steps could be
quickly accomplished by producers.
Mr. Nottingham continued to slide 4, which showed the
department's perspective on the mechanics of the bill. The
yellow diamonds represented milestones or decision points
in terms of whether the field or pool qualified. If a field
or pool had never produced in the Cook Inlet before, it
would automatically qualify. The bottom oval shape
represented the decision points if a field was produced
before 2024 but was not online during 2024. Bringing the
field back online would qualify it for the royalty
reduction. He clarified that there were three main
qualifications: if a field was new, if a field was brought
back online after a period of production but was shut in
recently, and if the prospect fell outside of what existing
wells could produce.
Mr. Nottingham continued on slide 5, which he thought would
answer some questions posed by Representative Stapp. The
slide described the gas supply cost under the current
royalty regime as compared to the royalty regime of HB 223.
There were three examples on the slide that each showed a
variety of outcomes on undeveloped gas resources. The first
scenario was optimistic with a lower investment amount and
cumulative resource of about 275 BCF and a development time
of three years. Scenario two was a "mid-case" with an
investment amount of $350 million, 250 BCF, and a
development time of three years. The third scenario was a
more pessimistic view with a higher investment amount of
$400 million, a longer development timeframe, and 250 BCF.
The scenarios did not reflect any one particular project,
but were simply intended to provide information.
Mr. Nottingham explained that the left side of the slide
showed the cost of gas supply, which was the minimum price
that investors needed in order to move forward. The chart
assumed that one of the most important criteria was a
payback time of around four years and a minimum annual
return rate of 15 percent. The first three bars were the
cost of supply under the current royalty regime for
scenario one, two, and three, and the arrows tied back to
the cost of supply under the royalty regime of HB 223. He
explained that scenario two under the current royalty
regime would cost $12.26 per MCF to the developer in order
to onboard a project at the investor requirements of four
years for payback and a 15 percent rate of return. The
orange bar was the cost of royalty. If royalty was brought
down to zero, the cost of supply would be reduced by $1.74
to $10.48. The cost would not be passed on to a consumer.
2:13:53 PM
Representative Galvin wondered if it was possible that the
bill would encourage a project to go offline for a year in
order to qualify for royalties. She asked what the state
would do to make sure that the system would not be
manipulated.
Mr. Nottingham responded that the intent was not to
encourage manipulation. The legislation would not consider
fields that were to be shut in during 2025 or 2026, only
fields that were shut in during 2024 or earlier. Any
manipulation of the system was protected by the date
restriction.
Mr. Crowther added that the department already knew which
fields would be eligible for royalties.
Representative Galvin asked for confirmation that the
legislation would not incentivize manipulation of the
system because the department already knew which fields
would be eligible.
Mr. Nottingham responded in the affirmative.
2:16:03 PM
Mr. Nottingham continued on slide 6 of the presentation
which detailed the economics from a hypothetical company's
point of view. On the right-hand side of the slide, the
graph showed the internal rate of return to the company,
and the yellow line and the black line represented the
internal rate of return under the royalty regime proposed
by HB 223. The graph also included the internal rate of
return for the current royalty regime under the same
hypothetical company. As gas prices increased, the rate of
return also increased, but there was an incremental
internal rate of return benefit to the company of about 5
percent under HB 223 as compared to the current royalty
regime.
Mr. Nottingham explained that the left-hand side of the
graph showed that the payback time was also improved. The
payback time under the current royalty regime was
represented by the gray bar and the payback time under HB
223 was represented by the blue bar. Under the proposed
legislation, the payback time would be greatly reduced,
thereby creating a financial incentive for companies.
Representative Galvin asked what the 5 percent difference
would translate to in terms of dollar amounts.
Mr. Nottingham responded that he was uncertain, but the
division's commercial manager could respond to the
question.
2:18:55 PM
JHONNY MEZA, COMMERCIAL MANAGER, DIVISION OF OIL AND GAS
DEPARTMENT OF NATURAL RESOURCES (via teleconference),
responded that slide 6 reflected the impact of the reduced
royalty rates on the investment metrics potentially
required by investors. If the internal rate of return was
increased as a result of the policy, new projects would
become available. He thought there would be a positive
impact in terms of revenue; however, because there were a
variety of potential scenarios and the scope of the new
projects was uncertain, it was difficult to pinpoint the
specific revenue impact.
Co-Chair Foster asked Mr. Meza to model a few scenarios and
provide the information to the committee.
Representative Galvin added that the modeled scenarios
would help answer her question. She asked if a specific
number could be extrapolated in example scenarios.
Mr. Crowther responded that he believed so. He understood
that Representative Galvin was referring to project-wide
costs. He confirmed that the division could develop
scenarios and present the scenarios to the committee.
HB 223 was HEARD and HELD in committee for further
consideration.
2:21:54 PM
AT EASE
2:24:55 PM
RECONVENED
HOUSE BILL NO. 387
"An Act relating to a tax credit for certain oil and
gas equipment in the Cook Inlet sedimentary basin; and
providing for an effective date."
2:25:25 PM
REPRESENTATIVE TOM MCKAY, SPONSOR, explained that HB 387
attempted to help oil and gas development in the Cook
Inlet. He realized that a "jack-up" rig would be required
if drilling activity in the inlet were to be increased. The
current rig in the inlet was being fully utilized drilling
wells for Hilcorp. He explained that it was not possible to
drill year-round in Cook Inlet but it was possible to drill
from approximately May through October with a jack-up rig.
He thought the rig was needed in order to increase
production. He read the sponsor statement (copy on file):
As we face the reality of a shortage in natural gas
production in Cook Inlet, the backbone of Southcentral
Alaska's energy supply, the urgency to act has never
been more critical. Cook Inlet gas has been an
invaluable resource as an affordable, reliable energy
source that has powered homes, businesses, and
industry for decades. Projections indicate a rapid
decrease in gas supply in the coming years under the
current market conditions, a scenario that threatens
the energy security of over half of Alaska's
population and could lead to our reliance on imported
Liquefied Natural Gas (LNG), which is likely to be
significantly more expensive.
Jack-up rigs are specialized offshore drilling rigs
necessary for developing Cook Inlet gas reserves.
Currently the state has only one rig available, a
handcuff on any significant increase in drilling
activity. The bill proposes a targeted incentive that
will increase the project economics for investing in
another jack-up rig to be used in Cook Inlet to
explore for and extract natural gas by providing a
carry-forward tax credit equal to the costs associated
with purchasing and transporting the rig to Alaska. HB
387 has a clear goal: to increase exploration and
production activities, thereby enhancing Cook Inlet
gas reserves and increasing gas production.
I urge my colleagues of the 33rd Legislature and the
people of Alaska to support, HB 387 as a step towards
energy development, economic resilience, and the long-
term prosperity of our great state.
2:28:58 PM
TREVOR JEPSEN, STAFF, REPRESENTATIVE TOM MCKAY, introduced
the PowerPoint presentation "HB 387 Cook Inlet Jack-Up Rig
Credit" dated April 4, 2024 (copy on file), and began on
slide 2. He relayed the projected Cook Inlet gas shortage
would threaten the energy security of the Southcentral
region of the state and there could be a potential
shortfall as early as 2027. A public opinion poll from July
of 2023 suggested that 72 percent of residents reported a
high level of opposition to importing natural gas and 60
percent of residents supported incentives for oil and gas
companies to find and produce more Cook Inlet gas. He noted
that residents' opposition to imports decreased markedly in
the unlikely scenario that liquified natural gas (LNG)
imports would be cheaper. Many stakeholders, such as the
Alaska Energy Authority (AEA), believed that LNG imports
would be significantly more expensive than locally produced
Cook Inlet gas. He argued that the legislature owed
Alaskans a solution to help incentivize more Cook Inlet gas
exploration, production, and development. He relayed that
figure 1 on the slide showed the projected fuel costs for
coal, natural gas, LNG, and diesel over the next 16 years.
The information was compiled by AEA. The actual price of
gas to the consumer was unknown and the numbers were
projections, but it was worth considering the projections
when making policy decisions.
Mr. Jepsen continued to slide 3 and explained that jack-up
drilling rigs were specialized rigs in the mobile offshore
drilling unit class and were intended for relatively
shallow waters up to roughly 500 feet. The rigs consisted
of a floating hole that could either be self-propelled or
pulled by a barge to a drilling location. The rigs had
extendable legs that provided the support for the rig on
the sea floor. He stressed that jack-up rigs were necessary
to develop offshore Cook Inlet gas. The slide included a
drawing of the different mobile offshore drilling classes,
not drawn to scale, and the jack-up rig was circled in red.
Mr. Jepsen continued to slide 4 and relayed that there was
presently one jack-up rig in Cook Inlet. The bill was
solely focused on implementing a second rig in the inlet,
which was required in order to adequately explore and
develop gas reserves. The current jack-up rig in Cook
Inlet, Spartan 151, would be fully utilized by Hilcorp for
the foreseeable future. He explained that any new major
developments would require a second rig. The decline in the
Cook Inlet gas shortage projections did not account for a
potential second rig in the inlet. In addition to
developing known reserves in Cook Inlet on state land,
there were federal leases in Cook Inlet which were too deep
below the surface for the Spartan rig to operate in and a
more capable jack-up rig was needed. Market interest had
shown that investing in Cook Inlet exploration and
production was not a highly popular option. The primary
factors came down to risk and rate of return. The high cost
nature of oil and gas exploration and development
operations in Cook Inlet directly impacted both risk and
rate of return. The state fully or partially subsidizing
the purchase or transfer of another jack-up rig to develop
Cook Inlet offshore reserves would offset the risk and
increase the rates of return for a potential project. There
was some risk to the state, but a "silver bullet" solution
to address Cook Inlet did not exist. He reiterated that
Alaskans wanted incentives to be offered and HB 387
represented a strong incentive to implement a second rig in
Cook Inlet.
Mr. Jepsen continued to slide 5 and explained that the bill
would introduce a Title 43 tax liability reduction credit,
which was not a cash credit. The credit was equal to 100
percent of the cost of purchasing and transporting a jack-
up rig to Alaska limited to a maximum credit value of $75
million. The credit would only apply to jack-up rigs for
Cook Inlet and included language that would ensure the rigs
were used for at least three years, which would disallow
the credit to be used as a pass-through in order to move
the rig to a different location. He thought that the risk
to the state was not as large as it may seem because the
new rig would benefit Alaskans if the rig was used in
Alaska for three years. There would be no cost to the state
if the credit was not utilized and the state did not
acquire a second jack-up rig.
2:34:37 PM
Mr. Jepsen relayed that there was an old jack-up rig credit
which was a drilling credit that was only applicable to
drilling costs for a rig exploration well that was drilled
with the jack-up rig. The only possible recipients of the
old credit were oil and gas companies. The new credit
proposed by the bill was for any Title 43 tax liability and
would not be limited to oil and gas companies' drilling.
Co-Chair Foster invited Mr. Jepsen to review the sectional
analysis.
Mr. Jepsen reviewed the sectional analysis on slide 6 (copy
on file):
Section 1: Amends AS 43.98 by adding a new section
(43.98.080) which introduces a tax credit for persons
installing a jack-up rig in the Cook Inlet sedimentary
basin.
Section 2: Repeals a prior jack-up rig drilling credit
Section 3: Provides for an immediate effective date.
Representative Galvin asked why the jack-up rig was chosen
to be in federal waters as opposed to state waters.
Representative McKay responded that the intent was to allow
the rig to be utilized in state waters or federal waters.
He explained that jack-up rigs were typically leased from
the Gulf of Mexico or Southeast Asia. There were three
important elements of jack-up rig drilling: the depth of
the water, the desired drilling depth, and configuration of
the drilling platform. If a drilling platform was set at a
location with known gas, the important information to know
was the water depth, the platform height, and the depth of
the wells to be drilled. The appropriate jack-up rig could
then be acquired with the known specifications. He
reiterated that the intention was for the rig to work in
state or federal water.
Representative Galvin asked if there was a reason why a
project on the water was chosen over a project on the land.
She understood that there was gas available everywhere and
wondered if there was a reason that the focus was on Cook
Inlet.
2:38:43 PM
Representative McKay responded that there were already land
rigs on the shore and some of the bigger gas prospects were
offshore.
Representative Galvin asked how the bill would be an
improvement upon what had already been done in the past.
She was aware that the state had spent hundreds of millions
of dollars in the past on new rigs and the efforts were
unsuccessful. She asked why Representative McKay thought
the bill would be more successful than past efforts.
Representative McKay responded that in many of the energy
focused bills he was sponsoring, he was trying to leverage
reserves that were in the ground already instead of taking
funds out of the treasury. He thought leveraging existing
reserves would have a different result than past efforts.
He did not want to criticize what was done in the past and
he was certain the intentions were good. He relayed that
there was gas in the ground that may not be produced unless
the state leveraged and incentivized operators to monetize
it for the benefit of all Alaskans. He explained that his
energy bills were all structured to leverage reserves
rather than utilize cash from the treasury. He suggested
that Mr. Jepsen could add more details.
Mr. Jepsen clarified that the bill was not specifically
targeting federal waters or state waters. He continued that
the older version of the jack-up grid credit was
specifically for drilling costs associated with exploration
wells. The credit would only apply for the first three
exploration wells with a jack-up rig and it was limited to
$25 million for the first well, $22.5 million for the
second, and $20 million for the third. The credit proposed
by HB 387 intended to keep the jack-up rig in the state for
three years with the assumption that it would be drilling
nonstop. The rig could be drilling exploration wells or
development wells. The bill would ensure that the three-
year drilling contract was in place and that the rig would
be working nonstop to meet the gas demand.
2:42:24 PM
Representative Galvin understood that the credits would not
be displacing revenue.
Mr. Jepsen replied that the state would be reimbursing oil
companies and gas companies, but there was a benefit to
Alaskans because the rig would be in the state for three
years and it would be drilling nonstop. The payout of the
credit would be a reimbursement, but it would still be
leveraging gas in the ground because both exploration wells
and development wells would be eligible. He argued that the
drilling of the wells for a significant period of time
would benefit the state.
BRANDON SPANOS, ACTING DIRECTOR, TAX DIVISION, DEPARTMENT
OF REVENUE (via teleconference), explained that the way the
tax credit was structured was that the credit could be
applied against the taxpayers' tax revenue in the year in
which the credit was claimed. The credit would first need
to be earned, which would generally line up with the
taxation time period. For example, if a taxpayer brought a
rig up to Alaska in 2026 and also had production tax due in
2026, the taxpayer could apply the credit in 2026. If there
were any credits left over, the taxpayer could apply the
credits in subsequent years.
Representative Galvin understood that the credit would only
be earned if the tax bill was over $75 million. She asked
for confirmation that a company would be receiving the
credit in exchange for a promise that it would drill for at
least three years.
Mr. Jepsen responded in the affirmative.
Representative McKay commented that everyone had seen the
projection that showed there would be a gas gap in
approximately 2027 or 2028 and the earliest date LNG would
be imported was 2030. The intended purpose of the bill was
to bridge the gap to ensure that the state had sufficient
gas supplies at least until the state had the ability to
import LNG.
2:46:31 PM
Representative Cronk asked how long it would take for gas
to be utilizable if the second jack-up rig was drilling and
hit gas. He understood the process would not only involve
finding the gas, but also building the pipeline. He asked
how long the entire process would take.
Representative McKay responded that there would be a
certain amount of pressure to take action quickly to allow
the industry to react and plan. He explained that it would
take two to three years to procure a new platform. Any new
platform would need a subsea gas pipeline to shore and tie
the gas into the NSTAR gas line. He noted that the process
would take time and none of the steps could happen quickly.
There could hypothetically be around 30 new wells after
three years between two different platforms. Offshore work
was time intensive, but it had been done before in Cook
Inlet and could be done again.
Representative Cronk understood that if there was a new
field in the water, a new platform would need to be built
before any drilling could occur.
Representative McKay responded in the affirmative. He
explained that subsea developments were the only
developments that did not need a platform because the
wellheads were on the sea floor. Most scenarios that would
work for Cook Inlet were centered around building a new
platform. The platform would likely be built in Korea or
Japan and transported to the state and then the platform
would be anchored to the sea floor. The jack-up rig could
then drill the wells and begin production. The process had
been employed in the inlet for decades.
2:49:34 PM
Representative Cronk asked how long a jack-up rig would
take to get to Alaska in the best case scenario.
Representative McKay responded that the jack-up rig would
likely come from the Gulf of Mexico and could either be
towed up or hauled up to the state. The rig would be
mobilized in summer or early spring. He acknowledged that
it was a substantial operation and required supply vessels,
materials, and manpower, among other resources.
Representative Coulombe commented that she liked the bill.
She referred to slide 3 which detailed the various types of
drilling rigs. She asked why the bill would not be expanded
to other types of rigs for future drilling purposes.
Representative McKay responded that jack-up rigs were the
most efficient and the most economical. There had been
drill ships used in Cook Inlet in the past, but the rigs
had to be dynamically positioned, which required a
significant amount of power. The ships were designed to sit
in the tides without moving, which required a tremendous
amount of fuel.
Representative Coulombe understood that there was only one
jack-up rig in the inlet currently and it was being fully
utilized by Hilcorp. She asked Representative McKay how
confident he was that there would be enough drilling
opportunities to keep the two jack-up rigs busy.
Representative McKay responded that determining the scope
was up to the private sector. There were two gas reservoirs
that could be exploited and two platforms, which would take
at least two years to drill to completion. He noted that it
was a hypothetical situation at the moment. He thought the
legislature was responsible for setting up the environment
and the industry was responsible for deciding how to
proceed. The projects would likely proceed if the
legislature was able to ensure that the projects would be
economically viable. He pointed out that none of his energy
bills required that the state take action, but instead
offered opportunities to the private sector. He thought
that the private sector knew how to operate drilling
projects better than the state. The role of the state was
to offer incentives and put forth appropriate legislation.
The owner of the potential jack-up rig in the Gulf of
Mexico or Southeast Asia would likely not likely bring the
rig to Alaska for an abbreviated program, but for a two-
year or three-year contract to ensure that there would be a
return on investment.
2:55:06 PM
Representative Josephson understood that the credit was not
limited to oil and gas companies. He asked which party
would receive the tax credit in the following hypothetical
situation: a jack-up rig drilling in the Gulf of Mexico was
not producing oil and the owner of the rig decided to enter
into a contract with an oil or gas producer in the Cook
Inlet. He assumed that the producer would receive the
credit and the producer would enter into an independent
contract with the owner of the jack-up rig.
Mr. Jepsen responded that the tax credit was structured to
apply to any Title 43 tax liability. The intent was to open
up the credit eligibility to Alaska Native corporations
that do not drill for oil or a transportation company with
a high corporate income tax liability. The credit would
make it easier to transport the rig to Alaska, lease the
rig, and become the owner of the rig, which would make the
rig an asset to Alaska. He explained that the overall idea
was not to limit the credit to oil and gas companies and
allow other corporations or entities in the state to
potentially become an owner of a rig.
Representative McKay added that Representative Josephson
had described a typical scenario. He explained that an oil
and gas company would contract with a drilling contractor
and pay the contractor to lease the rig, then the oil and
gas company would receive the tax credit.
Representative Josephson provided a hypothetical example
where the Northwest Alaska Native Association (NANA)
initiated the development. He asked if the corporate taxes
would be written off against NANA's assets or if the credit
would belong to the ultimate developer. In the example
scenario, NANA would be the general contractor.
Representative McKay responded that he would offer a
different example. He relayed that Doyon Incorporated would
be considered the parent company, and beneath the parent
would be Doyon Drilling. The two were considered separate
divisions. He noted that Doyon could contract or purchase a
jack-up rig which would become part of its fleet, but it
would have nothing to do with Doyon's other divisions and
their other businesses.
Representative Josephson asked if Mr. Spanos could respond
to the question.
2:59:18 PM
Mr. Spanos responded that he understood that the question
was how the credit would be applied if a non-producer were
to take on the cost of bringing up a jack-up rig to the
state. He relayed that it would depend upon the company. If
the company was a C corporation, the credit would apply
against its AS 43.20 C corporation taxes, which were net
income taxes. If the company was another entity with a
different type of tax, such as a fishing company, the
company could bring up a jack-up rig and apply the credit
against its fish taxes.
Representative McKay thanked the committee for its time.
HB 387 was HEARD and HELD in committee for further
consideration.
Co-Chair Foster reviewed the agenda for the following day's
meeting.
ADJOURNMENT
3:01:36 PM
The meeting was adjourned at 3:01 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 223 Sponsor Statement.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 223 |
| HB0223 CS(RES) Summary of Changes B to U.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 223 |
| HB0223 CS(RES) Sectional Analysis.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 223 |
| HB387 Sectional Analysis ver U 3.28.24.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 387 |
| HB387 Summary of Changes (B to U) 3.28.24.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 387 |
| HB387 Sponsor Statement ver U 3.28.24.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 387 |
| HB 223 DNR DOG Presentation to HFIN 04.04.2024.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 223 |
| HB 387 Presentation ver. U.pdf |
HFIN 4/4/2024 1:30:00 PM |
HB 387 |