Legislature(2023 - 2024)BUTROVICH 205
02/23/2024 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB220 | |
| SB194 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SB 220 | TELECONFERENCED | |
| *+ | SB 194 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
SB 194-REDUCE ROYALTY ON COOK INLET OIL & GAS
3:43:32 PM
CO-CHAIR GIESSEL announced the consideration of SENATE BILL NO.
194 "An Act relating to temporarily reduced royalty on oil and
gas from pools without previous commercial sales in the Cook
Inlet sedimentary basin; and providing for an effective date."
3:44:25 PM
JOHN BOYLE, Commissioner, Department of Natural Resources (DNR),
Anchorage, Alaska, said the state is facing an energy challenge
in the Southcentral area that impacts the entire state.
Anticipated supply is currently projected to fall under
anticipated demand. As a result in upcoming years, the state is
facing a delta that needs to be filled. Royalty relief is one
tool DNR uses to incentivize new production in Cook Inlet. SB
194 is relatively straightforward and proposes lowering the 12.5
percent royalty rate to five percent. This would apply to
already existing leases and future leases in areas where the
state does not currently have existing oil and gas production.
The provisions for royalty relief would only apply to new
production being brought online and not to existing production,
which is already committed in the energy diversification
initiative. Various consultants and presenters conveyed that
some of those key drivers help influence a company's decision to
invest money into a prospective project. The decision to begin
with royalty relief is a significant component that factors into
the decision-making process on whether the economics of a
commercial project merit an investment.
MR. BOYLE said by providing some measure of royalty relief, the
economics could be improved to favor production. There is a
myriad of complex issues that challenge Cook Inlet gas
production and factors that need to be addressed, so DNR
anticipates working with the committee to explore available
policy options and identify the most meaningful actions the
state could do to encourage production. Regardless of other
technologies and diversified energy sources, the state will need
to consider other sources and acknowledge the continued demand
of natural gas, which is another reason to ensure a competitive
environment in Cook Inlet. Although the focus is on gas and
energy, SB 194 also applies to new oil production since the oil
produced out of Cook Inlet is essential to Alaska. That oil is
important to Marathon refiners and other applications, so
incentivizing both oil and gas production is important to the
state to address energy needs, continue to provide for fuel
needs, and lessen the reliance on importing other fuels, which
has an element of cost and risk when considering geopolitical
issues that have an impact on the ability to source important
resources.
3:50:17 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources (DNR), Anchorage, Alaska, introduced himself.
3:50:31 PM
DEREK NOTTINGHAM, Director, Division of Oil and Gas (DOG),
Department of Natural Resources (DNR), moved to slide 2 and
explained the significance of Cook Inlet Gas:
[Original punctuation provided.]
WHY IS COOK INLET GAS IMPORTANT?
Natural Gas Utilities
• Enstar serves over 440,000 people and operates in
over 25 communities throughout Southcentral
Alaska
• Interior Gas Utility (IGU) serves over 2,400
people
Electric Utilities
• Chugach Electric serves over 302,000 people in
Anchorage, Whittier, Girdwood, and Fairbanks
• Matanuska Electric (MEA) serves the Mat-Su
Borough and Chugach and Eagle River, over 180,000
people
• Homer Electric serves nearly 36,000 people
MR. NOTTINGMHAM said about seventy percent of people in Alaska
depend on natural gas. Half of the gas that comes out of Cook
Inlet is contracted by ENSTAR while the other half is contracted
by electric utilities to provide power.
3:52:00 PM
MR. NOTTINGHAM moved to slide 3 and provided an overview of Cook
Inlet basin:
[Original punctuation provided.]
COOK INLET OVERVIEW
Cook Inlet is a large mature oil and gas basin
• Has produced over 1.4 billion barrels of oil and
12 trillion cubic feet of gas
• 26 producing fields operated by 8 different
companies
• There are over 200 oil and gas leases in Cook
inlet
Gas production has been declining since 1990
• Peak gas production in 1990 was over 850,000
thousand cubic feet per day
• Current production is just over 200,000 thousand
cubic feet per day
Cook Inlet gas provides heat and electricity to 70
percent of Alaskans
MR. NOTTINGHAM said Cook Inlet produced 1.4 billion barrels of
oil and 12 trillion cubic feet of gas since the late 1950s,
including 26 producing fields operated by eight companies. The
green shaded areas on the map on the right side of the page
indicate gas production. He noted that current production has
significantly declined since 1990.
3:53:26 PM
MR. NOTTINGHAM moved to slide 4 and detailed Cook Inlet leases:
[Original punctuation provided.]
COOK INLET LEASES
What is a State of Alaska Oil and Gas Lease?
• A lease is a tract of land designated for
oil and gas exploration
• Leases are offered at lease sales or through
exploration licenses
• Primary lease terms are between five and ten
years
• Commercial production extends the lease
beyond the primary term
What is an Oil and Gas Unit?
• Leases are combined to form a unit for the
protection of all parties
• Facilitates joint development, conserve
natural resources, and avoid waste
• Unit agreement is developed between the
lessees and the State
• Requires the development of a plan of
development/exploration (POD/POE) along with
other reporting requirements
• Requires the operator to act as a prudent
operator while developing the unit
3:55:23 PM
SENATOR KAWASAKI asked about general lease term requirements to
satisfy the terms of commercial production.
3:55:44 PM
MR. NOTTINGHAM replied that in general, the lease terms are
between a five-to-ten-year timeframe. Recently, DNR has offered
an eight-year lease with the option to extend it to ten years.
The lessee is required to pay rent on that lease as well as a
bonus to bid on it upfront. They are also required to fulfill
exploration activities. If oil or gas are found in commercial
quantities, the lessee is required to put it on production. If
production is not done within that timeframe, the lease is
returned to the state and can be offered for sale.
3:56:59 PM
SENATOR KAWASAKI asked if a lessee or operator could drill for
oil and gas then harvest and stockpile the resource.
3:57:31 PM
MR. CROWTHER replied no and said there is an iterative process
the state goes through to manage, encourage, and sometimes
compel or respond to a failure to produce from a lease or unit.
Individual leases are treated as a unit in the course of
development. When a project begins and operators acquire leases
for a potential unit, they provide exploration plans to DNR that
prove they will drill wells. DNR's process requires the operator
to identify the geological location of where that production can
be allocated to. If subsequent wells are not drilled that
identify, expand, or appropriately manage that development, DNR
requires the operator to fulfill their lease terms or risk
losing future leases. There is a very complex suite of
regulations that covers that. In the event an operator obtained
leases, was granted a unit, drilled a well or two, and never
pursued further development, DNR could take actions to reduce
the size of the unit, remove leases from it, and offer it up for
sale.
3:59:22 PM
SENATOR KAWASAKI asked if any current Cook Inlet leases are not
being developed or are in jeopardy of having leases being taken
back or reissued by the state.
3:59:37 PM
MR. CROWTHER replied that it is difficult to provide a decisive
answer since each lease unit is at a different stage. Some have
been in production between a decade and over a half-century,
while others are new and have yet to see that initial
exploration. A variety of units have seen attempts to expand
development, including the Cosmopolitan Unit. DNR is focusing on
bringing that unit as well as the Kitchen Lights Unit (KLU) into
full production. Given the large size of KLU, it is important to
ensure a plan is in place for continued activity.
4:01:04 PM
SENATOR KAWASAKI clarified that he wanted to know the status of
current leases. He stated it sounds like the price of Cook Inlet
gas is at an all-time high development should be taking place.
He expressed hope that developers who do not meet the lease
requirements be held to the terms of the lease.
4:02:00 PM
MR. NOTTINGHAM moved to slide 5 and spoke to Cook Inlet geology:
[Original punctuation provided.]
COOK INLET GEOLOGY
Two Sources of Gas In Cook Inlet Basin
1. Biogenic gas from coals
2. Oil migrated from source rocks, creating
associated gas
MR. NOTTINGHAM explained that the image illustrates the left
side of Cook Inlet and the Alaskan Range mountains on the
eastern side of the Kenai Peninsula. The shades of green
indicate the presence of sand deposits, gas, and deeper oil,
which have accumulated over time to form a fairway. This
accumulation is influenced by tectonic activity. On the right,
the image shows a stratigraphic section that has developed over
time, primarily from oil found deep within Jurassic and
Cretaceous sands. Oil is also visible in areas corresponding to
the Cenozoic Tertiary eras. Additionally, gas deposits are
evident in the sterling Beluga sands, primarily composed of
biogenetic gas produced by decomposed bug remains that are
primarily comprised of methane. The oils have migrated upwards
from deep source rocks. While many of the deeper sands are
tightly formed, they become more permeable as they move towards
shallower sands. It is the shallow permeable sands that yielded
most of the 1.4 billion barrels of produced oil.
4:04:03 PM
CO-CHAIR GIESSEL said she appreciated these diagrams that dispel
the myth of gas being extracted from caverns.
4:04:21 PM
SENATOR KAWASAKI asked if gas used in oil basins to increase
production would be subject to SB 194 or a 12.5 percent royalty
rate.
4:05:07 PM
MR. NOTTINGHAM replied he believes that gas used for EOR
purposes that stays within a unit would not be subjected to SB
194 since it is not subject to a royalty-bearing event. The only
field in Cook Inlet that uses gas cycling is Swanson River and
that gas stays within that unit and is managed at the federal
level.
4:06:10 PM
MR. NOTTINGHAM moved to slide 6 and spoke to undiscovered oil
and gas resources:
[Original punctuation provided.]
COOK INLET EXPLORATION & DEVELOPMENT: UNDISCOVERED
RESOURCES
Undiscovered, Technically Recoverable Oil & Gas (U.S.
Geological Survey 2011):
• mean conventional oil 599 million barrels of oil
• mean conventional gas 13.7 trillion cubic feet
• mean unconventional gas 5.3 trillion cubic feet
Undiscovered, Technically Recoverable Gas:
• 1.2 trillion cubic feet additional mean resource
assessed in the federal Southern Cook Inlet Outer
Continental Shelf area (Bureau of Ocean Energy
Management 2011)
• Governor's Legislation targets making these
prospects more economic for development
MR. NOTTINGHAM said this slide demonstrates undiscovered
resources outside of existing units. The map on the left side of
the page represents Cook Inlet lands as far south as Homer and
as far north Talkeetna. The outline in red represents the
potential for full-bed gas. The other outlines represent the
potential for different oil and gas plays through the
stratigraphic cross section. He said it conveys there is a huge
amount of undiscovered gas in Cook Inlet and the lion's share of
it is not on existing leases or units.
4:08:24 PM
CO-CHAIR GIESSEL noted that USGS does not comment on the cost of
accessing those undiscovered resources.
4:08:34 PM
MR. NOTTINGHAM replied that is correct. He stated "technically
recoverable" translates to gas extraction opportunities that
have been demonstrated elsewhere in the world. However, it does
not mean applying it in Cook Inlet will be commercial.
4:09:13 PM
MR. NOTTINGHAM moved to slide 7 that showcases a graph of Cook
Inlet production history over time. In the late 1950s to early
1960s, oil production reached over 200,000 barrels per day. He
stated peak gas production occurred in 1990 at 853,476 mcf/d.
Water production came from water flood breaking through in the
oil reservoirs and is how pressure is maintained. It is an
enhanced recovery technique that has been widely applied in Cook
Inlet. Production has declined to around 200 million cubic feet.
4:10:17 PM
SENATOR KAWASAKI said in 2012 or 2013, it appears there was more
gas produced in that year. He referred to the Cook Inlet
Recovery Act (CIRA) and Cook Inlet Natural Gas Storage Act
(CINGSA) that preceded it. Two major developments were made
where the state lost revenue in hopes of producing more gas. He
asked why these approaches increased production for one year
only.
4:11:04 PM
MR. NOTTINGHAM replied he is unsure but would report back to the
committee. The impact is subtle on the actions taken to improve
gas production in Cook Inlet. He stated the graph demonstrates a
change in the trajectory.
4:11:58 PM
MR. NOTTINGHAM moved to slide 8 and spoke to the history of gas
production from 2000 to 2023. He said the main point of the
graphic on the left is to demonstrate state-owned oil and gas
leases and the companies that left Cook Inlet. Currently,
Hilcorp and several small producers make up Cook Inlet producers
and leaseholders. The graphic on the right shows where that
production comes from. He stated that big fields have declined
significantly and another big field was not brought online, so
although there was incremental change through CIRA, no major
discovery came online.
4:13:38 PM
CO-CHAIR GIESSEL said a lot of money was spent on CIRA and the
state subsequently had to pull back cash credits offered. While
there were some results, many companies left Cook Inlet.
4:14:08 PM
MR. NOTTINGHAM moved to slide 9 and described Cook Inlet
production field history. He said about 68 bcf of gas was
produced out of Cook Inlet last year. The lion's share of that
came from leases that Hilcorp operates. About 90 percent of the
production is operated by Hilcorp, which owns about 80 percent.
Around nine thousand barrels per day come from Cook Inlet.
4:14:59 PM
CO-CHAIR GIESSEL said she appreciated the quantified breakdown
of the various fields on slide 9.
4:15:23 PM
MR. NOTTINGHAM moved to slide 10 and explained gas storage:
[Original punctuation provided.]
GAS STORAGE
What is gas storage?
• Gas can be stored by re-injecting it in
subsurface reservoirs and re-producing when it is
needed, although it comes with costs and
operational demands.
• It is used within a year to mitigate the fact
that demand is much higher in the winter than the
summer, but it is best to produce from fields at
a relatively steady rate. Production over the
summer months can be "saved up" for cold winter
days.
• Storage is critical, as peak winter demand
already requires more gas than is deliverable
from producing reservoirs.
• Gas storage can also be used across multiple
years.
There are currently four active gas storage pools
• CINGSA Established in 2011, gas storage
capacity 18 bcf , operated by CINGSA (an RCA
regulated utility)
• Kenai Gas Pool 6 Established in 2006, gas
storage capacity 50 bcf, operated by Hilcorp
• Pretty Creek Established in 2005, gas storage
capacity 3 bcf, operated by Hilcorp
• Swanson River (Federal) Established in 2001,
gas storage capacity 3.4 bcf, operated by Hilcorp
4:15:52 PM
CO-CHAIR GIESSEL asked him to elaborate on CINGSA's sand
production during the recent cold snap.
4:16:17 PM
MR. NOTTINGHAM replied that he is unsure of specifics. In a
general sense, when a well produces, it does not have a downhole
mechanism to control sand as a gravel pact does. Over time
through pressure cycles and drawing down the well, the sand may
become unconsolidated, sluff into the well, and create obstacles
for well production. When possible, sand can be cleaned out to
restore production or install completion equipment that
mitigates sand production in the future.
4:17:27 PM
MR. NOTTINGHAM moved to slide 11 and detailed Cook Inlet gas
demand:
[Original punctuation provided.]
COOK INLET GAS DEMAND
Kenai LNG Plant
• Nikiski liquified natural gas (LNG) facility is
operated by Trans-Foreland Pipeline Co. LLC
which is a subsidiary of Marathon Petroleum
• Last exported LNG was 2015
• Department of Energy (DOE) authorization for
exporting LNG expired in 2018
• Dec. 2020 Federal Energy Regulatory Commission
(FERC) approved LNG imports to this facility an
annual capacity up to 1.8 billion cubic feet
(bcf) per year
Nutrien Fertilizer Plant
• Second largest ammonia/urea plant in U.S.
• Shut down and mothballed in 2007, however Nutrien
maintains permits and remains interested in
reopening the plant
• Gas prices relative to Lower 48 makes economics
difficult
• Potential source for blue hydrogen/blue ammonia
MR. NOTTINGHAM said one of the main components is outlined under
bullet point 2 of the Nutrien Fertilizer Plant section. By 2007,
the unit was offline. Kenai LNG went offline in the mid-2010s,
so the industrial baseload has weaned Cook Inlet for various
reasons. Currently, power, heat, and some oil and gas operations
make up the 70 bcf of annual gas that is demanded out of Cook
Inlet.
4:18:25 PM
MR. NOTTINGHAM moved to slide 12 and spoke to the 2022 Cook
Inlet forecast:
[Original punctuation provided.]
DNR 2022 COOK INLET FORECAST
Purpose of the 2022 Cook Inlet Gas Forecast:
• Independent analysis to provide information on
gas supply issues in the Cook Inlet
• Also provides production information for the
Department of Revenue's revenue forecast
Methodology:
• Utilized public production data to assess Units
producing gas in the Cook Inlet
• Generally accepted petroleum engineering
practices used to develop projections
• Standardized set of economic limits were used for
each Unit 12
Key Assumptions:
• Assumes 15 development wells per year until 2030,
and no new wells beyond that
• Assumes gas price is flat at 70 BCF, with
escalation for inflation. Does not forecast
market changes responding to supply/demand
• Does not include contribution from non-producing
known prospects and does not forecast likelihood
of their development
• Forecasted volumes do not account for gas
produced from gas storage
MR. NOTTINGHAM said in response to Hilcorp informing the
utilities that it was going to meet its contractual obligations
but could no longer be the swing producer in Cook Inlet, DNR
sought to understand and develop a forecast. At the end of 2022,
the forecast was presented to various legislative committees.
Publicly available data was used to steer clear of
confidentiality issues. Operators' plans and known prospects in
Cook Inlet helped develop the assumption of 15 development wells
per year until 2030.
4:20:40 PM
MR. NOTTINGHAM moved to slide 13 and said the blue bars
demonstrate existing wells that are online today but are on the
decline. The orange bars represent the 15 development wells. In
2027, there were significant gaps between supply and demand in
Cook Inlet. He emphasized the importance of establishing the 15
annual development wells and continuous drilling to continue
providing gas and meet future demand.
4:21:43 PM
MR. NOTTINGHAM moved to slide 14:
[Original punctuation provided.]
2022 FORECAST VS ACTUALS
Key Differences from Actuals
• Wells Drilled:
18 development wells were drilled in 2022 vs
DNR-assumed 15 development wells
• Routine Field Events:
Well Maintenance (i.e., tubing replacements,
casing repairs, etc.)
Well Enhancements (i.e., perforations,
stimulations, etc.)
Facility Turnaround Events (i.e., compressor
& separator maintenance, infrastructure
repairs, etc.)
MR. NOTTINGHAM added that development is on track with the
forecast. He said the green line represents actual production
while the blue and gray line represents the forecast.
4:22:16 PM
MR. NOTTINGHAM moved to slide 15 and listed 2023 development
well activity:
[Original punctuation provided.]
2023 DEVELOPMENT WELL ACTIVITY
Well Activity
• 17 gas development wells have been drilled and
completed during calendar year 2023:
o North Cook Inlet Unit x3
o Lewis River Unit x1
o North Trading Bay Unit x1
o Swanson River Unit x3
o Beluga River Unit x5
o Lewis River Unit x1
o Ninilchik Unit x3
• 1 development well is currently being drilled in
Kenai Unit
• 1 development well drilling permit is currently
approved for Beluga River Unit
Production
Major Field Contributors (through November 2023):
• Ninilchik ~21.8 percent
• North Cook Inlet ~18.8 percent
• Beluga River ~18.5 percent
• All other gas fields represent less than 10
percent each
The above percentages are based on gas volumes for
sale, and discounts gas produced from storage as well
as gas reinjected for EOR purposes.
4:22:52 PM
CO-CHAIR GIESSEL asked if all 17 wells are operated by Hilcorp.
4:23:00 PM
MR. NOTTINGHAM replied that is correct.
4:23:04 PM
CO-CHAIR GIESSEL asked for information on the one development
well currently being drilled in the Kenai Unit.
4:23:16 PM
MR. NOTTINGHAM replied that all 17 development wells have been
drilled and completed. In the Kenai Unit, there was another
development well drilled for a total of 18 development wells
completed in 2023. Also, the Baluga River Unit had one
development well permitted.
4:23:46 PM
CO-CHAIR GIESSEL asked if the two additional wells are operated
by Hilcorp.
4:23:51 PM
MR. NOTTINGHAM replied that is correct.
4:23:58 PM
CO-CHAIR BISHOP referred to slide 13 and asked if years 2020,
2027, 2028, and 2029 are looking for 10, 15, and 20 bcf of
replacement to reach demand.
4:24:17 PM
MR. NOTTINGHAM replied that is correct. He said it's a needed
increase of about 5 bcf in 2027, 15 bcf in 2028, and 20 bcf in
2029.
4:24:32 PM
CO-CHAIR BISHOP observed the these are the deficits after
including the 15 annual development wells.
4:24:36 PM
MR. NOTTINGHAM replied that is correct.
4:24:40 PM
CO-CHAIR BISHOP emphasized that this is a real situation.
4:24:50 PM
CO-CHAIR GIESSEL commented that she thought Senator Bishop's
question might ask about the projected costs for the additional
wells.
4:24:50 PM
CO-CHAIR BISHOP said Co-Chair Giessel could ask the question.
4:25:12 PM
CO-CHAIR GIESSEL asked if the economical evaluation is
available.
4:25:16 PM
MR. NOTTINGHAM asked if the question is about the cost of a
well.
4:25:21 PM
CO-CHAIR GIESSEL clarified that the question is about projecting
the five additional bcf in 2027 at what cost. She asked if the
calculations came from DNR or a consultant.
4:25:46 PM
MR. NOTTINGHAM replied that utilities and ENSTAR have not done
an economic analysis of the various options they have for
economical gas. DNR did not complete that analysis.
4:25:59 PM
MR. NOTTINGHAM moved to slide 16 and shared Cook Inlet lease
sale results from 2023:
[Original punctuation provided.]
COOK INLET 2023 LEASE SALE RESULTS
New, competitive lease terms offered:
• Net profit share as the bid variable
• Fixed per-acre cash bonus
• No royaltypercentage of net profits owed to
the State after recovering capital
investments and operating costs to bring
production online
Six tracts received bids
• Three from Hilcorp Alaska LLC
• Three from Hex LLC
Net profit share rate bids: 5.7 percent 11 percent
Cash bonus revenue: About $600,000
Acres receiving bids: About 15,000 acres
MR. NOTTINGHAM added that the net profit share only kicks in
when the project achieves payout. It allows the lessee time to
locate the gas, drill wells, and get the production online and
achieve economic payout before the state starts receiving the
net profit share. He said these are good terms for the lessee.
The bids provided insight on Cook Inlet interest and indicate
there is not a large group of interested investors.
4:28:44 PM
MR. NOTTINGHAM moved to slide 17 and compared existing oil and
gas royalty statutes of new leases and existing leases in terms
of no production and mature production. He expressed that AS
38.05.180(f)(4) is restrictive and scarcely used. He said he
does not believe any producers in Cook Inlet applied for the AS
38.05.180(j) modification.
4:32:20 PM
MR. NOTTINGHAM moved to slide 18 and explained why SB 194 is
necessary:
[Original punctuation provided.]
SB 194: WHY IT IS NECESSARY
Why this legislation is necessary
• Alaskans need access to reliable, affordable
energy
• Nearly 70 percent of Alaskans use Cook Inlet
natural gas for heating, energy, and electricity
generation
• Cook Inlet gas supplies are forecasted to drop
below demand in coming years unless new sources
are brought online
• There are several significant known natural gas
fields in Cook Inlet that are not seeing
development under the status quo
• Policies and actions to support future
development need to be taken today
• More competitive development terms will increase
total recovery and utilization of Alaska's
natural resources, which otherwise may not be
developed or generate revenue for the State
• Alaska should use all the local natural gas
resources available as we work on long-term
energy solutions for the Railbelt
MR. NOTTINGHAM said Cook Inlet is part of the overall solution
and this acts as a bridge to a longer-term solution.
4:34:07 PM
CO-CHAIR GIESSEL inquired about any specific field locations SB
194 would help develop under the status quo.
4:34:27 PM
MR. NOTTINGHAM mentioned specific field locations in focus. He
said there are smaller developments that would be impacted.
4:34:51 PM
CO-CHAIR BISHOP asked what the runway would look like if the two
pools on slide 13 were in production, so the committee can make
an informed economic decision for long-term plans.
4:35:31 PM
MR. NOTTINGHAM replied he would follow up with the committee
with an answer.
4:35:35 PM
CO-CHAIR GIESSEL said the long-term is key. In 2013, CIRA was a
short-term solution and Alaska couldn't afford the cash credits.
The legislature does not want to make the same mistake.
4:36:10 PM
MR. NOTTINGHAM moved to slide 19 and explained the effects of SB
194:
[Original punctuation provided.]
SB 194: EFFECTS
What the bill does
• Grants a reduced royalty of five percent for the
first ten years of production from pools in Cook
Inlet that have not previously been produced for
commercial sale
• Includes known resources that are not yet in
production and resources that could be discovered
through further exploration
• Applies to any state land in Cook Inlet, whether
or not in existing fields, units, or leases
• Does not reduce royalties for pools presently in
commercial production
4:37:09 PM
MR. NOTTINGHAM moved to slide 20 and explained qualifying
production under SB 194:
[Original punctuation provided.]
SB 194: QUALIFYING PRODUCTION
AS 38.05.180(f)(5) is amended to read:
"[T]he lessee of all or part of an oil or gas pool in
the Cook Inlet sedimentary basin that, subject to
determination by the commissioner, has not previously
produced for commercial sale oil or gas shall pay a
royalty of five percent on oil or gas produced for
sale from that pool for 10 years following the date on
which the production for commercial sale commences;"
4:38:00 PM
SENATOR KAWASAKI said AS 38.05.180(f)(5) used to have a
qualifier that was just subject to the first 25 million barrels
and 35 million cubic feet of gas produced. He asked for an
opinion on why it was previously included.
4:38:27 PM
MR. CROWTHER replied he is unaware of the exact policy
rationale. The perception is that the six identified fields at
the time were known resources that needed development to build
revenue and gas supply. The state wanted to encourage field
startup and the initial capital investment while recognizing
that the state would revert back to its status quo royalty. One
reason volume metric limitations are excluded from SB 194 is
because DNR wants all that volume to be produced to get those
additional resources to market. At the time of investment, they
focused on encouraging investment, field startup, and
production.
4:39:34 PM
SENATOR KAWASAKI asked if volume metric field requirements
produced the anticipated results that were sought in AS
38.05.180.
4:39:54 PM
MR. CROWTHER said the best thing to do is identify start-up
times for the six fields. He offered to return to the committee
with this information. He noted several of the fields are still
in production today.
4:40:25 PM
MR. NOTTINGHAM continued reading slide 20:
[Original punctuation provided.]
What "has not previously produced for commercial sale
oil or gas" means:
• Production from wells or sidetracks drilled after
the effective date of this legislation that would
not have otherwise been produced from existing
wells
• "[S]ubject to determination by the commissioner"
means DNR considers if the source of oil and gas
has produced in the past, proximity to existing
wells, drainage area of existing wells, and
timeframe for recovery from existing wells
• Examples of qualifying production:
o A newly-drilled well or sidetrack from the
edge of an existing or previously-producing
development
o A new well or sidetrack from an unproduced
accumulation of oil and gas
• The lessee or lessees shall jointly or separately
apply for reduction in royalty for one or more
wells with each application
• Data and interpretations will be supplied with
the application, and DNR may request further data
and interpretations
• A well or accumulation may be determined to
receive reduced royalties before a well is
drilled when supported by data and
interpretations
4:41:55 PM
CO-CHAIR BISHOP asked if AS 38.05.180(f)(5) would be part of the
economic incentive to take on the endeavor.
4:42:12 PM
MR. NOTTINGHAM replied yes and said it is part of the economic
incentive. It is critical for some producers in Cook Inlet to
know they will receive the benefits before they consider
investing. If producers believe they will need to generate or
acquire a significant amount of data and go through a time-
consuming process through the state, it creates uncertainty.
Having the royalty reduction up front is important.
4:43:02 PM
CO-CHAIR BISHOP commented that the benefits help with small
business financing.
4:43:13 PM
MR. NOTTINGHAM stated that is correct.
4:43:16 PM
CO-CHAIR GIESSEL asked whether it is similar to the cash credits
that the legislature promised, which drew investment from large
creditors like Bank of America and others.
4:43:37 PM
MR. NOTTINGHAM replied that the five percent royalty benefit is
not an upfront cash payout and would require ground production.
That is the distinction of the cash credit program. The royalty
reduction incentivizes getting the production online.
4:44:08 PM
CO-CHAIR GIESSEL said it would apply to new gas or oil for ten
years and seems similar to the gross value reduction offered on
the North Slope for new oil for seven years.
4:44:31 PM
MR. NOTTINGHAM replied that it did apply to the North Slope Oil
and Gas Production tax, which was a reduction for the first
seven years on a per-barrel basis from certain qualifying
fields. This would apply to the royalty, so it is a benefit off
of the gross value for 10 years.
4:45:29 PM
MR. NOTTINGHAM moved to slide 21 and presented the sectional
summary:
[Original punctuation provided.]
SB 194: SECTIONAL SUMMARY
• Section 1: Amends AS 38.05.180(f)(5). The
original statute granted a five-percent royalty
rate for oil or gas for the first ten years but
was limited to six Cook Inlet fields discovered
before 1988 and provided a deadline of January 1,
2004, for start of production (in AS
38.05.180(dd)).
This amendment modifies the program to include
new production in Cook Inlet, regardless of
discovery date, and removes limits on eligible
volumes of oil or gas during the ten-year period
of reduced royalty. Eligibility is subject to
determination by the Department of Natural
Resources (DNR) commissioner, rather than being
automatic.
• Section 2: Repeals the following statutes:
AS 31.05.030(i):
This section relates to the powers and duties of
the Alaska Oil and Gas Conservation Commission
(AOGCC) and the paragraph outlines the procedure
for approving plans of development by the AOGCC.
This statute is no longer necessary because the
Department of Natural Resources, not the AOGCC,
is the agency that administers and approves plans
of development.
AS 38.05.180(dd):
This section relates to the State of Alaska's oil
and gas and gas only leasing policies. Paragraph
(dd) established a deadline for start of
production under the unamended AS 38.05.180(f)(5)
and is no longer appropriate.
• Section 3: The legislation takes effect
immediately under AS 01.10.070(c).
4:47:22 PM
CO-CHAIR GIESSEL asked if DNR has had any indication this would
be helpful to producers.
4:47:33 PM
MR. NOTTINGHAM replied that DNR has had conversations with
lessees that indicated it would be helpful. It may not be the
key to fully unlocking things but would be beneficial since it
removes an upfront cost in gas and oil production and helps
achieve the rate of return that investors need to see.
4:48:17 PM
CO-CHAIR GIESSEL acknowledged this was discussed during
conversations about the North Slope and while rewriting those
tax policies. It is important they realize fully repaying the
cost of development as soon as possible. She asked what the
state defers in revenue.
4:48:56 PM
MR. CROWTHER replied that DNR has a variety of hypothetical
field developments and general amalgamated information about
history revenue trends and revenue associated with the total
return of the state. He offered to deliver this information to
the committee. In addition to the direct benefits of receiving
some royalty, the associated economic security benefits are
significant.
4:49:38 PM
CO-CHAIR GIESSEL agreed that the legislature honing in on some
of the cost could ripple out to a much larger impact on the
entire economy. That is the driving motivation as the state
loses its working-age population, which is impacting the economy
significantly. She noted the fiscal note is zero and the
narrative discusses it being indeterminate.
4:50:23 PM
SENATOR KAWASAKI said he reviewed USGS data that was presented
over the past 60 years in the Cook Inlet-Anchorage region. Eight
trillion cubic feet of gas was utilized. He said he understands
there is only an estimate of undiscovered gas that is not
technically or economically recoverable. Somewhere between five
and 40 trillion cubic feet still exist, which is generations of
potential gas in Cook Inlet. The need is immediate. He
appreciated Co-Chair Giessel's question about costs, deferred
revenue, and what is lost.
4:51:55 PM
CO-CHAIR GIESSEL held SB 194 in committee.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 194 Sponsor Statement 2.23.24.pdf |
SRES 2/23/2024 3:30:00 PM SRES 5/6/2024 3:30:00 PM |
SB 194 |
| SB 194, version A.pdf |
SRES 2/23/2024 3:30:00 PM SRES 5/6/2024 3:30:00 PM |
SB 194 |
| SB 194 Sectional Analysis, version A 2.23.24.pdf |
SRES 2/23/2024 3:30:00 PM SRES 5/6/2024 3:30:00 PM |
SB 194 |
| SB 194 DNR Fiscal Note 1.16.24.pdf |
SRES 2/23/2024 3:30:00 PM SRES 5/6/2024 3:30:00 PM |
SB 194 |
| SB 194 Reduce Royalty on Cook Inlet Oil & Gas SRES Presentation 2.23.24.pdf |
SRES 2/23/2024 3:30:00 PM |
SB 194 |