Legislature(2023 - 2024)BUTROVICH 205
01/30/2023 03:30 PM Senate RESOURCES
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| Audio | Topic |
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| Start | |
| Presentation(s): 2022 Cook Inlet Gas Forecast | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
January 30, 2023
3:30 p.m.
MEMBERS PRESENT
Senator Click Bishop, Co-Chair
Senator Cathy Giessel, Co-Chair
Senator Bill Wielechowski, Vice Chair
Senator Scott Kawasaki
Senator James Kaufman
Senator Forrest Dunbar
Senator Matt Claman
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Representative Tom McKay
COMMITTEE CALENDAR
PRESENTATION(S): 2022 COOK INLET GAS FORECAST
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
JOHN BOYLE, Commissioner-Designee
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Provided opening remarks and participated in
the presentation about the 2022 Cook Inlet gas forecast.
JHONNY MEZA, Commercial Analyst
Commercial Section
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Participated in the presentation about the
2022 Cook Inlet gas forecast.
JOHN BURDICK, Petroleum Reservoir Engineer
Division of Oil and Gas
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Participated in the presentation about the
2022 Cook Inlet gas forecast.
JOHN CROWTHER, Deputy Commissioner
Department of Natural Resources
Anchorage, Alaska
POSITION STATEMENT: Participated in the presentation about the
2022 Cook Inlet gas forecast.
ACTION NARRATIVE
3:30:13 PM
CO-CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:30 p.m. Present at the call to
order were Senators Claman, Dunbar, Wielechowski, Kaufman,
Kawasaki, Co-Chair Bishop, and Co-Chair Giessel. She recognized
that Representative Tom McKay was in the audience.
^PRESENTATION(S): 2022 Cook Inlet Gas Forecast
PRESENTATION(S): 2022 COOK INLET GAS FORECAST
3:30:52 PM
CO-CHAIR GIESSEL announced the committee would hear a
presentation from the Department of Natural Resources about the
2022 Cook Inlet gas forecast. She reviewed the course of events
starting 12 years ago when she joined the Senate. The
legislature responded to the concern about limited gas supplies
for Anchorage and the Interior by passing North Slope gas
pipeline legislation and instituting cash credits to incentivize
small producers in Cook Inlet. The gas pipeline has not been
built and the cash credits were discontinued which resulted in
several companies going bankrupt. She commented that history
appeared to be repeating itself because the committee was again
talking about the constrained gas supply in Cook Inlet. She
invited the presenters to the witness table.
3:33:25 PM
JOHN BOYLE, Commissioner-Designee, Department of Natural
Resources, Anchorage, Alaska, stated that it was a privilege to
talk about the status of Cook Inlet. He said it's important to
understand that Cook Inlet natural gas is a finite resource and
that the basin has been producing for more than 60 years.
Natural gas from Cook Inlet has been the primary source of
energy for Southcentral for decades and it is likely to be
critical going forward.
COMMISSIONER-DESIGNEE BOYLE stated that his team would summarize
the history of activity in the basin; the supply and demand
dynamics; and the prior fiscal terms and incentives the
legislature has instituted. He said the current analysis
incorporates certain assumptions that may change, but the
overall perspective is that Cook Inlet demand will exceed the
supply at some point in the future. Whether supply will increase
to meet demand or demand will decrease due to trucking LNG to
the Interior or increased efficiencies remains to be seen.
However, the department does see the need for policy discussions
about whether the current path is sustainable to provide energy
to Southcentral into the future.
COMMISSIONER-DESIGNEE BOYLE displayed the outline for the
presentation and reported that in 2022, the state offered two
Cook Inlet oil and gas lease sales and both currently are
producing natural gas for Alaskans in the Railbelt. Energy
security is a priority and the department is looking at a
variety of energy solutions to ensure that energy supplies are
available for the short, medium, and long term. There are also
alternatives such as LNG imports, the Alaska LNG project,
hydropower, on- and offshore wind, tidal energy, coalbed
methane, and geothermal prospects. He said the situation in Cook
Inlet will require a lot of discussions and involve policy
considerations. The goal today is to provide a snapshot in time
to show what the data is demonstrating and help inform the
committee's decision-making going forward.
CO-CHAIR GIESSEL listed the individuals who were available
online to provide information and answer questions.
3:39:09 PM
JHONNY MEZA, Commercial Analyst, Commercial Section, Division of
Oil and Gas, Department of Natural Resources (DNR), Anchorage,
Alaska, stated that the purpose today is to present information
from the recently published 2022 Cook Inlet Gas Forecast. The
presentation also would provide background information regarding
supply and demand and the geology of Cook Inlet.
3:39:36 PM
JOHN BURDICK, Petroleum Reservoir Engineer, Division of Oil and
Gas, Department of Natural Resources, Anchorage, Alaska,
displayed slide 3 and explained that gas in the Cook Inlet basin
comes from two primary sources. One is the biogenic gas from
coals in the shallower strata. The second comes from oil that
migrates from source rocks and creates associated gas.
3:40:20 PM
MR. MEZA displayed slide 4 and discussed the history of gas
production from Cook Inlet fields since 2001. The graph on the
left shows gas production from only state lands in the billions
of cubic feet per year. During this time, the producers were
primarily the oil and gas majors. That changed in more recent
years to independent oil and gas companies such as Hilcorp,
Furie, Chugach Electric, Vision Resources, and Cook Inlet
Energy.
The graph on the right shows Cook Inlet gas production over the
same timeframe but from state, federal, and private lands. It
also shows that the production of gas has come down to 200
billion cubic feet per year. He said that's important to
remember when the demand component is discussed late in the
presentation. He noted that the production decline was stemmed
in more recent years. This was due in part to continued drilling
in the existing fields, but also the arrival of new fields such
as Kitchen Lights, Kenai Loop, and Cosmopolitan.
3:42:04 PM
SENATOR DUNBAR asked what color on the chart represented Beluga.
MR. MEZA said he couldn't say for sure, but Beluga is a major
contributor to production in the basin.
CO-CHAIR GIESSEL asked if anyone online could answer the
question.
3:42:53 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources, Anchorage, Alaska, offered to follow up with the
information.
3:43:23 PM
SENATOR CLAMAN asked whether the production identified as MOA
ML&P on the left chart represented the Beluga gas field.
MR. MEZA confirmed that was correct.
3:43:51 PM
MR. MEZA displayed slide 5 and explained that the chart provides
production numbers for 2022. According to the Alaska Oil and Gas
Conservation Commission (AOGCC), Hilcorp contributed about 85
percent of the gas production and about 78 percent of the oil
production from January through November 2022.
MR. MEZA displayed slide 6 and pointed out that the graph shows
the different components of demand for Cook Inlet gas from 2000
through 2022. These include commercial use, electric power, and
residential use. It shows that over this time, the demand by
category didn't change very much. In recent years, these user
groups account for about 80 percent of the total demand for Cook
Inlet gas. He noted that the graph also reflects the demand to
power oil and gas field operations in Cook Inlet. He also
pointed out that in the early years the excess production was
used for LNG export from Kenai and the Nutrien Fertilizer Plant.
The last LNG exported from the Kenai facility was in 2015 and
the fertilizer plant ceased operation in 2007.
3:46:07 PM
MR. MEZA turned to slide 7 and explained that the bar chart
shows the development, exploratory, and stratigraphic wells that
were drilled from 2005-2022. It also shows the evolution of the
production tax in Cook Inlet and the North Slope.
He explained that the early part of the graph reflects the
Economic Limit Factor (ELF) that assessed tax on gross revenues.
In 2006, the state transitioned to a new tax system that was
based on net profits. Importantly, this was also about the time
that the state instituted ceilings for production tax forecasts
in Cook Inlet. In 2010, the legislature passed the Cook Inlet
Recovery Act (CIRA), which allowed some credits related to
exploratory drilling and activity, especially related to
offshore activity and the buildup of gas storage facilities. He
pointed to the evolution of the number of wells drilled and how
the segment representing exploratory drilling declined
significantly. He noted that a later slide would illustrate why
that is important to maintain the level of production of gas in
the basin. In 2017, House Bill 247 repealed the credits that
hadn't expired, so the only remaining incentive is the discovery
royalty which applies to production from previously undiscovered
pools or fields in the basin.
3:48:16 PM
SENATOR CLAMAN noted the increase in exploratory drilling in
2011-2013 that started to tail off in 2014 and dropped to almost
nothing after that. He asked if those exploration numbers could
be attributed to passage of House Bill 280 and House Bill 247,
or ACES and Senate Bill 21.
MR. MEZA said there was no intention to assign cause and effect
to a certain tax system. The purpose of the graph was to provide
information related to exploratory drilling because that's
important to maintain production levels.
SENATOR CLAMAN asked if the credits or incentives in House Bill
280 (CIRA) were also present in ACES.
MR. MEZA answered that there were credits in the Cook Inlet
Recovery Act that applied to drilling in Cook Inlet and on the
North Slope. ACES had credits that predated CIRA.
3:50:17 PM
MR. CROWTHER added that in 2014-2015, there was a significant
decline in the price of oil so it was reasonable to assume that
those price dynamics challenged any interest in oil exploration.
3:50:52 PM
SENATOR WIELECHOWSKI asked if he was saying that the tax
structure had nothing to do with the level of exploration and
development in Cook Inlet.
MR. CROWTHER responded that the slide indicates that in the pre-
2014 timeframe, there was true exploration well activity in Cook
Inlet. He said it was reasonable to assume that it had to do
with incentives or corporate objectives, but there had not been
that sustained level of exploration drilling since the Cook
Inlet incentive program ceased.
SENATOR WIELECHOWSKI asked what the oil and gas tax and royalty
rates were in Cook Inlet.
3:52:01 PM
MR. MEZA replied the royalty rates in Cook Inlet generally are
12.5 percent and starting in 2022 the production tax in Cook
Inlet was 35 percent of the production tax value, although the
ceilings he referenced earlier remain active.
SENATOR WIELECHOWSKI asked if any tax credits or incentives were
currently available in Cook Inlet.
MR. MEZA replied he was not aware of any, but the slide
references a discovery royalty statute that allows the royalty
rate to be reduced by five percent for a producer that discovers
a new field or pool.
3:52:54 PM
SENATOR KAWASAKI asked if part of the reason for the increase in
exploratory drilling in 2011-2014 was due to the high price of
oil.
MR. CROWTHER said it's fair to say that the industry in Cook
Inlet, particularly the companies focused on oil development and
exploration, are very oil price sensitive.
SENATOR KAWASAKI noted that the Cook Inlet Recovery Act passed
at the lower end of the price spike. He asked how much could be
attributed to the large credits under CIRA versus just the price
spike in 2010.
MR. MEZA said it may be a combination of factors other than the
credit.
SENATOR WIELECHOWSKI asked how the price of Cook Inlet gas to
the consumer compares to the price throughout the US.
3:55:08 PM
MR. CROWTHER said the Henry Hub price has seen upward pressure
recently and it's been more volatile. The average over the last
ten years was about $2/Mcf compared to gas prices in Cook Inlet
of about $6-$7/Mcf. For a variety of reasons, the Henry Hub
price has gone up to $3-$4/Mcf and sometimes a little higher.
The Henry Hub price is converging with Cook Inlet prices, as
opposed to the historical norm which was flat and fixed.
SENATOR WIELECHOWSKI recapped the answer and asked if Cook Inlet
gas was still in the $6-$7 range.
MR. CROWTHER replied that was an accurate high-level summary.
SENATOR WIELECHOWSKI asked if any other jurisdiction had gas
that was priced as high as Cook Inlet.
MR. CROWTHER offered his understanding that in limited
jurisdictions in the northeast US, imported LNG prices were
quite high, but most markets in the Lower 48 were closer to the
Henry Hub than the Cook Inlet price.
SENATOR WIELECHOWSKI asked why there wasn't more production when
Cook Inlet prices were the highest in the US.
MR. CROWTHER replied that while Cook Inlet natural gas prices
are high, the demand profile is relatively limited, and mostly
under contract, which makes it challenging to incent new
production.
3:59:10 PM
SENATOR WIELECHOWSKI asked how the internal rate of return and
net present value at Cook Inlet compare to Henry Hub or other
places in the Lower 48.
MR. MEZA replied that may be confidential information.
SENATOR WIELECHOWSKI expressed frustration about the lack of
analysis when Alaska was the resource owner and the producers
were under lease obligation.
MR. CROWTHER said DNR believes that the producers are largely
fulfilling their development obligations for their existing
fields.
SENATOR WIELECHOWSKI asked what sort of policy tools the
legislature had at its disposal to get more production out of
Cook Inlet.
4:00:59 PM
COMMISSIONER-DESIGNEE BOYLE said it was beyond DNR's ability to
predict what causes one company to move forward with greater
activity, but the department was hearing from some Cook Inlet
operators about external constraints. For example, the
environmental, social, and governance (ESG) policies of some
major lending institutions consider Cook Inlet to be Arctic.
This limits access to outside capital and constrains these
companies from moving forward on some promising developments. If
this were resolved, it could lead to increased production.
CO-CHAIR GIESSEL asked if it was true that natural gas prices go
up when the weather is extremely cold because some of the
additional supply is drawn from the Cook Inlet Natural Gas
Storage Alaska (CINGSA) facility and that gas is more expensive.
MR. CROWTHER offered his understanding that there were sales
from both CINGSA that requires the payment of the storage costs
in addition to the production costs, and the utility contracts
that have different costs associated with high demand for a
short term.
4:05:00 PM
SENATOR KAWASAKI asked who owns CINGSA.
MR. MEZA answered that a group of companies own CINGSA and one
is related to ENSTAR.
SENATOR KAWASAKI asked if he was saying that some CINGSA owners
were also producers.
MR. MEZA said he would follow up with an answer.
SENATOR KAWASAKI said he'd also like to know if they take
advantage of the gas storage credit that are attached to the
program under the Cook Inlet Recovery Act.
MR. CROWTHER said he would follow up and provide an answer.
SENATOR CLAMAN asked how many companies participated in the 2022
gas sales.
MR. CROWTHER explained that the state held its regular spring
lease sale and another in December. There was also a mandated
federal lease sale in the federal Outer Continental Shelf area
of the southern Cook Inlet. In the earlier lease sale, Hex got
two leases adjacent to its existing operations. In the December
state lease sale, Hilcorp acquired five leases adjacent to its
existing lease holdings, some of which are under production.
Hilcorp also added one federal lease to its existing federal
lease position in the federal Outer Continental Shelf.
SENATOR CLAMAN asked if there would have been more participation
if more leases were offered.
MR. CROWTHER said it's difficult to speculate about the
decisions that companies might make, but DNR was happy to see
the commitment from the existing leaseholders. The department
would like to have seen interest from new companies, but that
did not happen.
4:08:17 PM
SENATOR WIELECHOWSKI observed that the situation had not changed
since it was discussed 10-15 years ago even though the
legislature had tried a variety of things, including $1.5
billion in tax breaks over the years that only worked to a
degree. He wondered whether DNR had additional levers it could
use to get more gas to the consumers.
MR. CROWTHER suggested that one distinction between now and ten
years ago was that the current operators in Cook Inlet have
indicated that they do not anticipate automatically extending
their existing contracts as they have in several recent years.
This is an indication of some market dynamic other than purely
cost that is affecting their decisions. One dynamic is that the
basin is advanced in years and is contributing a smaller amount
of supply. He cited the Beluga River field as an example and
noted that there was more about that later in the presentation.
To the question about what the department can do, he cited the
discovery royalty provision for new discoveries that Mr. Meza
mentioned, and working to improve the financial attractiveness
of projects in the Cook Inlet environment as the commissioner
mentioned. He said the department would be happy to engage in
other policy discussions with the committee related to Cook
Inlet production. DNR sees significant potential but
acknowledges that it's a complex and unique market.
SENATOR WIELECHOWSKI asked what the annual investment would be
to ensure an adequate supply of gas for consumers and utilities.
MR. CROWTHER said he wouldn't suggest a dollar figure, but an
assumption in the department's forecast was for about 15
development wells per year for Cook Inlet to continue to produce
the existing reserves into the market and meet demand.
SENATOR WIELECHOWSKI asked for the ballpark cost of drilling a
well.
COMMISSIONER-DESIGNEE BOYLE replied it depends in part on
whether the well uses an existing platform and infrastructure.
For a new platform the estimates range from $200 million to
about $0.5 billion and estimates for an exploration well from an
existing platform are still in the multimillion dollar range. He
added that oil production helps underpin or even support gas
production in Cook Inlet. The margins for oil are higher than
for gas, so the harder it is to find new oil deposits in
commercial quantities, the more the supply of gas is constrained
because the supplies of gas that are brought online oftentimes
are associated with a new oil discovery.
CO-CHAIR GIESSEL noted that BlueCrest Energy said it had
significant gas offshore but to produce it would require
significant investment for an offshore platform, which would be
prohibitively expensive.
4:15:17 PM
MR. MEZA advanced to slide 8 which emphasizes the need for new
wells to maintain the gas supply for the basin. The bar chart
provides data points for 2005, 2010, and 2021 that illustrate
that wells drilled in Cook Inlet pre-2000 have declining
production, but when new wells are drilled they maintain the
level of production in the basin.
4:16:20 PM
MR. BURDICK paraphrased the bullet points on slides 9 and 10
that read as follows:
2009 - Preliminary Engineering and Geological
Evaluation of Remaining Cook Inlet Gas Reserves
â?¢ Consisted of engineering and geologic evaluations
of 28 currently producing Cook Inlet gas fields
to derive estimates of remaining Proved and
Probable reserves.
â?¢ Applied single deterministic Decline Curve
Analysis (DCA) and Material Balance (MBAL)
engineering methods to publicly available
production and pressure data obtained from Alaska
Oil and Gas Conservation Commission (AOGCC).
â?¢ Did not address economics of drilling additional
wells, recompleting existing wells, optimizing
infrastructure, and the ability to sell the gas
into the Cook Inlet market.
â?¢ Proved + Probable reserves estimated at 1.14
trillion cubic feet (Tcf).
2011 - Cook Inlet Natural Gas Production Cost Study
â?¢ Investigated investment requirements around
various targeted reserves.
â?¢ Addressed commercial viability of remaining gas
by postulating conceptual plans to produce
natural gas from the Cook Inlet Basin to meet a
demand of 90 billion cubic feet (bcf) per year.
2015 - Updated Engineering Evaluation of Remaining
Cook Inlet Gas Reserves
â?¢ An update to 2009's study of 34 currently or
historically producing Cook Inlet gas fields to
derive estimates of remaining Proved and Probable
reserves.
â?¢ Applied single deterministic DCA and MBAL
engineering methods to publicly available
production and pressure data obtained from AOGCC.
â?¢ Did not address prospective (undiscovered),
contingent (discovered, non-producing), and 3P
(Proved + Probable + Possible) reserves.
â?¢ Proved + Probable reserves estimated at 1.18
trillion cubic feet (Tcf).
2018 - Cook Inlet Natural Gas Availability
â?¢ Built on three previous DOG Cook Inlet gas
studies, while incorporating future supplies by
formulating hypothetical development projects
required to produce undeveloped volumes and
estimate each project's economic viability.
â?¢ 500800 bcf of additional gas is economic to
develop at a price range around $6-8/thousand
cubic feet (real 2016 dollars).
â?¢ P50 reserves estimate of 700 bcf when price is $8
per thousand cubic feet (mcf).
CO-CHAIR BISHOP asked how many years the production of 700
bcf/year was estimated to last.
MR. MEZA answered that the study concluded that 2028 would be
the last year.
4:20:54 PM
SENATOR KAWASAKI referenced the third bullet in the 2015 study
and asked for the definition of "Proved + Probable + Possible."
MR. BURDICK explained that those are industry-recognized
categories for a commercially available resource in a petroleum
resources management system. Proved + Probable + Possible is
much more certain than contingent or prospective resources.
Proved has 90 percent certainty with the particular volume;
adding Probable to Proved has a 50 percent certainty; and
Possible + Probable + Proved has a 10 percent certainty.
Methodology applications are what distinguish each category.
SENATOR KAWASAKI asked if the [Proved + Probable reserves
estimated at 1.18/Tcf] was based on the net price of gas at the
wellhead. He confirmed he was referring to the 2015 study.
MR. BURDICK explained that it was a technically-based forecast
that had no economic factors.
SENATOR CLAMAN asked if he could place the 1.2 Tcf of reserves
in the context of and comparison to the 700 bcf at a price
point.
MR. BURDICK explained that what demarcates both studies is that
there is no cost factor for the 2015 study and there is a cost
associated with the 2018 study.
SENATOR CLAMAN observed that the 1.2 Tcf suggests it's the
volume in the reserve that has not been produced, whereas the
700 bcf suggests the volume at $8 per thousand would be
economically recoverable. Together, the 1.2 Tcf and the 700 bcf
would be the volume of gas that at $8/Mcf is too expensive to
extract.
4:24:10 PM
MR. BURDICK said that's a fair assessment.
SENATOR DUNBAR referenced the 2011 study that estimated demand
of 90 bcf/year and the estimate in 2022 of 70 bcf/year. He asked
if the difference could be attributed to the fact that LNG was
no longer exported from the Kenai facility.
MR. CROWTHER answered that two things primarily changed the
demand profile. One was Agrium no longer producing fertilizer
for export and second was that consumer and utility efficiencies
increased from 2015 to 2022.
SENATOR DUNBAR referenced the 2018 study that estimated reserves
of 700 bcf at $8/Mcf and asked if it was fair to say that there
was 10 years of economically recoverable gas.
MR. CROWTHER called it a fair extrapolation.
4:25:40 PM
MR. BURDICK paraphrased the following bullet points on slide 11:
2022 Cook Inlet Gas Forecast
â?¢ A technical reserves assessment of 90 different
gas & oil pools in the Cook Inlet Basin using
publicly available production data obtained from
AOGCC.
â?¢ Decline Curve Analysis (DCA) used to estimate
volumes from currently producing well set. Type
Curve(s) were developed to estimate volumes from
future development wells.
â?¢ Discovered resources contingent upon more
favorable commercial conditions and undiscovered
(prospective) resources were not included in the
forecast.
â?¢ Estimated field level economic limits were used
in the "truncated" forecast cases.
â?¢ Forecasted volumes do not account for gas
produced from gas storage to avoid duplicative
gas volumes produced.
â?¢ Flat gas demand of 70 billion cubic feet per year
does not assume future additional requirements
nor does it assume possible substitutes or
increasing efficiency in consumption both for
energy producers and commercial or domestic
consumers.
4:27:44 PM
SENATOR WIELECHOWSKI questioned the reason the study did not
include the 20 Tcf of undiscovered, technically recoverable gas
the US Geological Survey (USGS) has said exists.
MR. CROWTHER replied the intent of the study was to focus on the
reserves and resources in existing fields, both under production
and expected to be develop with the consistent level of
activity. There was no intention to forecast when and how an
undeveloped known resource would be brought into production, or
to attribute exploration success to the undiscovered category
that the USGS says is abundant in Cook Inlet.
SENATOR WIELECHOWSKI asked if the USGS estimate how accurate and
what it considered technically recoverable.
MR. CROWTHER explained that USGS does undiscovered resource
assessments in Alaska and worldwide. They are extrapolations
based on representative assumptions about the particular basin,
including historical well activity, exploration success, the
scope of pools in the context of the geologic structure of the
particular basis, and the statistical extrapolation thereof. He
said it's fair to say those assessments are meant to provide
tranches of what could be in a basis at a very high level
without any economic screens. Although economic screens are
applied at times to obtain a high level assessment of what could
be there to compare one basin or one jurisdiction to another.
4:30:43 PM
CO-CHAIR BISHOP commented that economically recoverable was
where the rubber meets the road.
MR. CROWTHER agreed.
4:31:03 PM
MR. BURDICK advanced to the bar chart on slide 12 and conveyed
that the chart illustrates that approximately 15 wells per year
were drilled in the 2009-2019 pre-pandemic years.
SENATOR CLAMAN asked if the projection for 2023 was 15 wells.
MR. BURDICK confirmed that for 2023, 15 development wells were
factored into the forecast.
4:32:27 PM
MR. MEZA stated that slide 13 provides a little more detail
about how the current study considered a technically recoverable
gas resource, by applying an economic limit test to the decline
curve analysis and type well curve analysis. Essentially, this
compared the marginal revenue associated with production in a
given month to the marginal expenditure associated with the
production of that volume.
The exercise was to demonstrate that upstream companies are
unlikely to operate their fields at a sustained loss. Once a
company reaches the point that it can no longer cover its
marginal expenditures with their marginal revenues, it will
probably consider shutting down the field. At that point, the
technically recoverable forecast would no longer be available to
the market.
The analysis considered the technically recoverable forecast
from each of the fields and an approximation of gas prices using
the publicly available information between some Cook Inlet
producers and local utilities. For cost, a one-size-fits-all
approach was followed using a benchmark of the cost to produce
the fields, while allowing for differences based on the
proximity of those fields to infrastructure. Comparing fields on
the western side to those on the eastern side demonstrated that
offshore fields tend to have a higher cost than onshore fields.
The exercise also considered the royalty rate of 12.5 percent
and the tax structure related to production tax and the oil and
gas property tax.
SENATOR WIELECHOWSKI referenced the information on the chart
about taxes and asked for an explanation of "$1/bbl and
$0.177/Mcf ceilings."
4:35:15 PM
MR. MEZA replied those are the ceilings referenced earlier that
are applicable to taxable production from Cook Inlet. It follows
the same net profits structure as for the North Slope but is
subject to the values that appear on the slide.
SENATOR WIELECHOWSKI recalled that he said the tax rates were 35
percent, which would be less than one percent at $1/bbl.
MR. MEZA confirmed that he said that the tax rates were based on
35 percent.
SENATOR DUNBAR offered his understanding that the tax rate on
gas coming out of Cook Inlet was so low it could not be used as
a lever to incentivize more production.
MR. MEZA responded that the tax rate is 35 percent of the
production tax value, which is taxable revenue minus lease
expenditures. However, the calculation of taxable obligations
from these fields also includes the values for oil of $1/bbl and
a ceiling of $0.177/Mcf.
SENATOR DUNBAR asked if the $0.177/Mcf ceiling was applied to
$8/Mcf or some other value.
MR. MEZA replied the $8 is part of the taxable revenue and then
the lease expenditures are deducted. The result of that
calculation is compared to the $0.177/Mcf ceiling.
MR. CROWTHER added that the calculation is revenue minus
expenditures multiplied by the tax rate. If that number is
higher than the ceiling, it would be reduced to the ceiling.
SENATOR DUNBAR asked if that calculation was currently at the
ceiling.
MR. MEZA replied he didn't have the information for the
particular taxpayers, but the law provides for that ceiling. He
offered to follow up with the Department of Revenue (DOR) to
find out whether they had specific information about taxpayers.
4:38:20 PM
SENATOR WIELECHOWSKI asked if the state was getting the full
12.5 percent on all the fields in Cook Inlet or if the state was
providing royalty relief on some fields.
MR. MEZA replied the Kitchen Lights unit enjoys the discovery
royalty provision for 10 years.
SENATOR CLAMAN observed that the 35 percent tax rate seemed to
be largely irrelevant in the calculation about whether to
produce because the $1/bbl ceiling had a greater impact unless
the company was making almost no money on the field.
MR. CROWTHER acknowledged that DNR needed to meet with DOR to
get the most accurate information for the committee about how
the tax is currently applied. To Senator Dunbar's question about
the application of the tax cap to the oil and gas production
tax, he explained that Cook Inlet operators were not only
obligated to make Cook Inlet tax payments but also property tax
and corporate income tax payments. He opined that depending on
the size of those fiscal assessments, any of those levers could
be relevant to operators' commercial decisions.
SENATOR WIELECHOWSKI pointed out that the majority of the Cook
Inlet producers do not pay any corporate income tax.
MR. CROWTHER responded that he wasn't speaking to the status of
the different taxpayers in Cook Inlet, just that corporate
income tax was associated with activity in Cook Inlet.
SENATOR WIELECHOWSKI asked for confirmation that S corporations
pay no corporate income taxes.
MR. CROWTHER said he was not a tax professional, but that was
his understanding.
SENATOR WIELECHOWSKI asked whether companies producing in Cook
Inlet were able to write off their costs associated with
exploration, production, and development in Prudhoe Bay, or if
they were fenced off.
MR. CROWTHER replied he would confer with DOR and follow up with
the information.
4:42:35 PM
CO-CHAIR GIESSEL noted that the $1/bbl and $0.177/Mcf ceilings
were passed in about 2016, but she didn't recall whether there
was any fencing. She said the question of incentives is an
important one.
SENATOR DUNBAR commented that the Department of Revenue probably
should be present for all the discussions about economical
reserves and whether the collection of tax revenues impacts the
decision about whether the reserves are recoverable.
CO-CHAIR GIESSEL agreed.
4:44:07 PM
MR. BURDICK stated that slide 14 reflects a technical base
forecast for the high, mid, low, and mean cases for total gas
reserves from 2010 to 2041. He explained that an untruncated
forecast means that economics are not factored. The forecast for
the high case was for about 1.4 Tcf and the low case was about
843 bcf. The mean case forecast for total gas reserves was
approximately 1.1 Tcf.
4:45:05 PM
MR. BURDICK displayed the chart on slide 15 and explained that
this truncated forecast incorporates economics into the
technical forecast. The high case is about 1.1 Tcf and the low
case is about 603 bcf. The mean case forecast of total gas
reserve was about 820 bcf.
4:45:41 PM
MR. MEZA pointed out that the middle part of the graph shows the
impact of the economic limitations. It reflects the pace of
drilling and that, according to the assumptions, some of the
fields may reach the end of their economic life, which affected
the production for the whole basin
SENATOR WIELECHOWSKI asked what internal rate of return (IRR)
was assumed on the truncated forecast.
MR. MEZA replied that future investments were not evaluated.
Primarily, the ongoing costs of production were compared to the
marginal revenue associated with that production.
SENATOR WIELECHOWSKI asked if the truncated forecast assumed the
companies would make a profit.
MR. MEZA replied that the production reflected in the graph
means that the marginal revenues are higher than the marginal
expenditures. Therefore, there is a marginal profit associated
with that production.
SENATOR WIELECHOWSKI asked if he was saying that the assumption
was that the company would move forward even if there was
virtually no profit.
MR. MEZA said yes.
SENATOR WIELECHOWSKI asked if it wasn't necessary to factor in
some return for the company.
MR. MEZA clarified that the scenario that the slide seeks to
present is one where companies have to make a decision about
whether to continue production when a field returns no profit at
all.
4:48:02 PM
COMMISSIONER-DESIGNEE BOYLE added that the illustration is
simplified to avoid the problem associated with trying to target
IRRs, because a return that's sufficient for one company may be
completely insufficient for another.
SENATOR WIELECHOWSKI asked if the forecast considered that
companies would write off their expenses in Cook Inlet against
their profits in Prudhoe Bay.
COMMISSIONER-DESIGNEE BOYLE said he would defer to DOR because
he didn't know whether that was an option for companies working
in Cook Inlet.
4:49:22 PM
MR. BURDICK explained that slide 16 was a zoomed in view with
data incorporated into the forecast. The dashed green line shows
the actual volumes of gas, which fall between the high and low
case. He said there is high certainty that the actual data will
fall in the band between the high and low cases. There's low
probability of any production above the high case or below [the
low case].
4:50:07 PM
MR. BURDICK stated that slide 16 showed a rate-based plot and
slide 17 looks solely at volume on an annual basis with no
economics factored into the forecast. The demand profile is
overlayed as a benchmark for technically recoverable reserves.
4:50:48 PM
SENATOR KAWASAKI asked whether the assumptions were based on the
current contracts.
MR. MEZA replied the pricing information in the current multi-
year contracts was used.
SENATOR KAWASAKI asked if most of those contracts were 4-6 years
old.
MR. MEZA answered yes.
4:51:34 PM
MR. BURDICK stated that slide 18 reflects the truncated version
of the forecast of annualized gas volume by year. He pointed out
that looking at the assumed demand profile compared to supply
highlights the impact of factoring economics into the forecast.
4:52:03 PM
MR. BURDICK explained that slide 19 is the same untruncated
scenario, but it focuses on the mean case, broken out by proved
developed, and incremental proved undeveloped.
MR. BURDICK advanced to slide 20 and explained that it
illustrates the truncated view of the previous slide. It shows
the impact of factoring in the economics, but it primarily shows
the impact on proved undeveloped volumes. That speaks to the
assumption of drilling 15 development wells per year.
4:53:16 PM
SENATOR DUNBAR offered his perspective that slides 17-20 were
the heart of the presentation. They offer DNR's estimate that
sometime between 2027 and 2030, the Cook Inlet gas supply will
be insufficient to meet the demand.
MR. CROWTHER said the assumptions in the study could change, but
it was fair to say that the status quo would be affected in the
2027 to 2029 timeframe.
SENATOR CLAMAN summarized that the forecast on slide 20
illustrates that the three main factors that could change the
graph over time and avoid the challenge in the 2027-2030
timeframe would be a change in price dynamics, a change in
legislative dynamics, or a change in the economic model due to
the discovery of new fields.
MR. CROWTHER said that's a good summation.
4:55:17 PM
MR. BURDICK stated that slide 21 provides a comparison of the
four studies that the Division of Oil and Gas released. The gray
bars reflect the cumulative gas volumes produced at the time of
the study and the red bars reflect the total estimated reserves.
The takeaway is that each study incorporated different
methodologies and different scopes of work. This study showed a
cumulative volume of 820 bcf and roughly 9.7 Tcf of estimated
ultimate recovery.
4:56:16 PM
MR. BURDICK displayed slide 22 that talks about undiscovered
resources in the Cook Inlet basin. The first of two 2011 studies
was by the US Geological Survey (USGS). The agency estimated the
total volume of mean conventional and mean unconventional
technically recoverable oil and gas resource to be 19 (Tcf).
The second study, which was conducted by BOEM, estimated the
technically recoverable undiscovered gas resource to be 1.2 Tcf.
The assessment was in the southern Cook Inlet Outer Continental
Shelf (OCS).
COMMISSIONER-DESIGNEE BOYLE cautioned that as fewer companies
are operating in Cook Inlet, it was important to maintain the
health of support services in the area or the exploration and
development companies would be constrained in how aggressive
they could be during the exploration season. Trying to bring
support services up from the Lower 48 or down from the North
Slope would increase costs.
CO-CHAIR GIESSEL expressed appreciation that he raised the
issue.
4:58:45 PM
SENATOR WIELECHOWSKI said he appreciated the discussion but it
was the same as the last 15 years. He commented on the lack of
available levers and advocated for thinking outside the box to
look for solutions, perhaps by working with the utilities and
Native corporations so they could produce the fields. He
emphasized that without a solution, consumers would suffer.
CO-CHAIR GIESSEL advised that the committee would hear from the
utilities on Wednesday and perhaps DOR would be available to
respond to the questions that came up during this meeting. She
added that she was interested in inviting some Cook Inlet
5:02:23 PM
There being no further business to come before the committee,
Co-Chair Giessel adjourned the Senate Resources Standing
Committee meeting at 5:02 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2022 Cook Inlet Gas Forecast Report.pdf |
SRES 1/30/2023 3:30:00 PM |
|
| 2023 01 30 SRES DNR-DOG 2022 Cook Inlet Gas Forecast Presentation v.2.pdf |
SRES 1/30/2023 3:30:00 PM |