Legislature(2023 - 2024)BUTROVICH 205
05/08/2024 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB194 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| += | SB 194 | TELECONFERENCED | |
SB 194-REDUCE ROYALTY ON COOK INLET OIL & GAS
3:31:50 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."
CO-CHAIR GIESSEL said the committee previously adopted four
amendments to SB 194 and requested modeling before considering
further amendments. The modeling presentations were prepared for
the committee by Department of Natural Resources (DNR) and
GaffneyCline (GC).
3:32:32 PM
JOHN CROWTHER, Deputy Commissioner, Department of Natural
Resources (DNR), introduced a modeling presentation for SB 194.
3:32:52 PM
DEREK NOTTINGHAM, Director, Division of Oil and Gas, Department
of Natural Resources (DNR), said the modeling presentation would
cover various scenarios and a range of royalty rates, focusing
on incentives to address supply issues in the Cook Inlet. He
said the modeling included optimistic and pessimistic scenarios
to illustrate the economic possibilities for companies
developing projects in the Cook Inlet.
3:34:01 PM
JHONNY MEZA, Commercial Manager, Division of Oil and Gas,
Department of Natural Resources (DNR), Anchorage, Alaska,
provided the modeling presentation for SB 195 as requested by
the Senate Resources Committee. He moved to slide 2 titled
"Hypothetical Projects Considered: Optimistic Case" consisting
of a table comparing possible financial outcomes for an existing
oil and gas production project and three hypothetical new oil
and gas production projects. He noted that the production,
price, and cost values used are simplified assumptions for
illustrative purposes and that the existing production scenario
doesn't include capital investment or expenditures (Capex) and
it represents declining production.
• The existing oil and gas scenario produces 700 barrels of oil
per day and 3.5 million cubic feet (mcf) of gas per day. For
reference, he noted that the average current Cook Inet
production is 8000 barrels of oil per day and 200 million
cubic feet (mcf) of gas per day.
• The first [hypothetical] scenario involved a new offshore gas-
only project with a final investment decision (FID) in August
2025 and production starting in August 2027. He said the
potential gas production from the offshore project is 250
billion cubic feet (bcf), with no oil production, assuming a
required investment of $350 million.
• The second [hypothetical] considered is an oil development
project beginning in December of the current year, taking two
years to develop with some associated gas production. This
project would produce 45 million barrels of oil and 20 billion
cubic feet (bcf) of gas, with an assumed required investment
of $400 million.
• The third [hypothetical] scenario involves the infield
development of two additional gas-only wells, starting next
summer and taking a few months to develop. This project could
produce 20 billion cubic feet (bcf) of gas at a cost of $30
million, with each well costing $15 million to drill.
MR. MEZA explained that all the projects presented assume the
same operating expenditures of 50 cents per 1000 cubic feet of
gas and $10 per barrel of oil and the price assumptions for gas
and oil are $8.50 per mcf and $70 per barrel, respectively, with
an overriding royalty interest (ORRI) of 5%.
3:37:51 PM
CO-CHAIR BISHOP asked whether the two additional gas wells are
onshore or offshore.
3:38:07 PM
MR. MEZA replied that the [hypothetical scenario wells] were
assumed to be offshore.
3:38:13 PM
CO-CHAIR GIESSEL asked how Department of Natural Resources (DNR)
determined the capital expenditure/investment figures (Capex)
for the illustrated scenarios.
3:38:30 PM
MR. MEZA said this information was publicly shared by companies
for potential new projects in the inlet.
3:38:44 PM
SENATOR WIELECHOWSKI referred to the new offshore gas-only
[hypothetical scenario]. He observed the capital expenditure
(Capex) cost of $350 million and the operating expenditure
(Opex) cost of $.50 per mcf and the sale price of $8.50 per mcf
gas. He asked what the cost of production per mcf would be for
the producer.
3:39:24 PM
MR. MEZA replied he did not have that exact figure but said the
analysis considered the cost of supply as an investor would,
considering not only the cost of production, of investment and
associated operating expenditures, but also of taxes and royalty
payments to the overriding royalty interest (ORRI) owners.
3:40:00 PM
SENATOR WIELECHOWSKI noted figures from the charts and said he
was trying to determine the costs for a producer that would lead
to a cost of $8.50 for the consumer.
3:40:47 PM
MR. MEZA said he would provide the answer through the
presentation.
3:41:07 PM
MR. CROWTHER sought to orient the committee by noting that the
optimistic case was first up in the presentation. The optimistic
case assumes a more attractive production volume, and lower
capital expenditures and operating expenditures. He said the
pessimistic case later in the presentation would include
different assumptions.
3:41:35 PM
SENATOR KAUFMAN acknowledged the spectrum of optimistic through
pessimistic scenarios and asked whether there was a sense of
which is more likely or realistic.
3:42:00 PM
MR. NOTTINGHAM said the optimistic scenario assumes that all
projections, including reserves, resources, and costs, are met
exactly as projected. He acknowledged that in the real world,
delays in startup dates and other unforeseen issues are common,
which the optimistic scenario does not account for. He described
the pessimistic case as the low-end scenario, while the actual
outcome is expected to be somewhere in between these two
extremes.
3:43:37 PM
MR. MEZA moved to slide 3 titled "Project Economic Metrics:
Optimistic Case." He explained that the table compared possible
outcomes for various royalty relief interest rates, including
the status quo, for each of the three hypothetical oil and gas
production scenarios: new offshore gas-only, new oil and
associated gas, and traditional gas-only wells.
MR. MEZA said the analysis was conducted from the investors'
perspective. He noted a typo in the description of Amendment [6]
(A.15) but he said the model accurately reflected the language
of the amendment.
3:44:59 PM
MR. MEZA said there were three variables of interest for
potential investors: net present value (NPV), internal rate of
return (IRR), and the payback period. He pointed out that under
the status quo, the new offshore gas-only project has a NPV of
$58 million, an IRR of 19.3 percent, and a payback period of
over nine years. He noted that the discount rate used for all
three projects is 15 percent annual real rate. When different
options for royalty relief are applied, the outcomes are
affected as expected, with improvements to NPV and IRR and a
reduction in the payback periods.
MR. MEZA explained that the commercial value of oil is higher
than that of gas, as reflected in the oil and gas project
scenario and that the gas-only project which did not require new
infrastructure also had higher rates of returns.
MR. MEZA commented that the effect of Amendment [6] (A.15) was
described as a middle case between the more beneficial, gas: 0
percent [royalty relief] and oil: five percent [royalty relief];
and the less beneficial royalty relief scenarios, gas: 6.25
percent and oil: 12.5 percent.
3:48:12 PM
SENATOR KAUFMAN noted that the table on slide 3 did not line up
with Amendment [6] (A.15).
3:48:55 PM
CO-CHAIR GIESSEL asked Mr. Meza if this was the typo he
described earlier.
3:48:58 PM
MR. MEZA affirmed that it was.
3:49:11 PM
MR. CROWTHER assured the committee that the presentation would
be updated to correctly reflect Amendment [6] (A.15).
3:49:22 PM
SENATOR DUNBAR asked whether it was fair to say the primary
driver of the net present value (NPV) difference in the model is
the oil over the gas. He pointed out that there is only a two-
million-dollar difference with a five percent change in the gas
royalty. He asked whether he was reading the slide correctly.
3:50:05 PM
MR. MEZA agreed and said that under the second scenario the
commercial value of [oil] is, as expected, greater than the
value of gas. The reduction of the royalty rate affecting gas,
but not moving the oil [royalty] rate would not create as
impactful a change, as in the other cases.
3:50:35 PM
SENATOR DUNBAR said SB 194 is described as gas royalty relief
but slide 3 seems to demonstrate that it would really be oil
royalty relief in the inlet and that the hope is to sort of spin
off gas. He asked whether that was what slide 3 was showing.
3:50:57 PM
MR. CROWTHER revisited the parameters for scenario 2 and
explained that the project produces 20 bcf of gas per day, which
is significant for state demand but not a major gas producer,
primarily targeting oil. He noted this project scenario is based
on an existing project in the inlet that is primarily targeted
for oil development and the oil [royalty] relief would be
material for that project moving forward, while gas-focused
projects are more economically driven by gas [royalty] relief.
3:52:09 PM
SENATOR WIELECHOWSKI recalled previous testimony and today's
testimony that the expected internal rate of return (IRR) for a
project in Cook Inlet to be economic was between 15 and 20
percent.
3:52:27 PM
MR. NOTTINGHAM affirmed that was correct.
3:52:34 PM
SENATOR WIELECHOWSKI noted that all the projects in the model
showed a minimum of 19.3 percent, which was within the expected
IRR.
3:52:43 PM
MR. NOTTINGHAM affirmed that was correct.
3:52:47 PM
SENATOR WIELECHOWSKI asked whether royalty relief was needed if
the rate of return was already in the expected range. He further
opined that a 15 percent rate of return seemed high. He said,
according to some websites, the standard rate of return for gas
production is ten percent discount rate. He asked what the
difference in the rate of return would be if the [royalty
relief] is lowered from 15 to 10 percent.
3:53:37 PM
MR. CROWTHER affirmed that was correct, the [optimistic] chart
does show attractive rates of return. He noted that the reality
of today is that current operators do not have sufficient
confidence in the optimistic case to move forward [with
production]. He said the pessimistic case is likely not
reflective of reality, either. He said it was a very fair point
that the discount rate used in this [optimistic] model is high
and reflects that the cost of capital for oil and gas in Cook
Inlet is high.
3:55:29 PM
MR. MEZA offered further reflection on the optimistic case. He
noted the assumption that investors would use a 15 percent
annual discount in real terms and that a different rate would
affect the net present value (NPV) in the table, but it would
not affect the internal rate of return (IRR). He pointed out
that the payback, the number of years of production required for
investors to recover their capital, ranges from three years all
the way to nine years. He emphasized that investors might prefer
to recover their capital in four years and variation in investor
expectations could influence project viability, even with
royalty relief.
3:57:08 PM
MR. MEZA moved to slide 4, a chart illustrating state revenues
for the optimistic case model, applying the different royalty
options to each scenario. He reminded the committee of the typo
regarding Amendment [6] (A.15) and that the model does reflect
the language of the amendment as intended. He said, assuming
investor approval of the projects based on economic metrics, the
state could receive revenue from production tax, royalty
revenue, and property tax. These revenues are calculated for the
different modeling scenarios and are discounted using a 3
percent annual rate of return, which aligns with the state's
preferences, to reflect present value.
3:58:12 PM
SENATOR DUNBAR sought the relationship between slide 3 and slide
4. He asked how the reduction in state revenue of $175 million
translated to the increased net present value (NPV) of $75
million [for the producer].
3:59:17 PM
MR. MEZA explained that is the impact of the different discount
rates. For the calculation of the net present value (NPV) the
model used a 15 percent real annual discount rate. For the
revenues to the state, the model used a three percent real
annual discount rate. He said that was what generated the
differences in terms of magnitude.
3:59:58 PM
SENATOR WIELECHOWSKI focused on the scenario with new offshore
gas only and compared the status quo value, $246.6 million, with
the values directly below, $127.7 million which are calculated
using the staggered discount rate. He asked whether it was a
correct reading of the table to conclude that the reduced
interest to the state resulted in a loss of approximately $119
million to the state.
4:00:43 PM
MR. MEZA concurred that it was the correct reading of the table
under the assumption that the projects were sanctioned [by
investors] under the status quo. He noted the economic metrics
[for the optimistic case] are appealing. He reminded the
committee that investors would consider the range of potential
scenarios affecting the outcome of the projects and that is the
reason the presentation would transition to consider a
pessimistic scenario.
4:01:24 PM
SENATOR WIELECHOWSKI asked him to explain how Department of
Natural Resources (DNR) determines whether a producer is
adhering to its duty to produce. For example, if a company
showed a 19.3 percent rate of return or 29.5 percent rate of
return for new oil and gas. He noted that the returns could be
lower on the pessimistic side. He asked how DNR would determine
whether a company should proceed to drill under the terms of
their lease obligations.
4:02:08 PM
MR. CROWTHER said the primary enforcement mechanism to consider
whether there was fulfilment of development obligations by
lessees occurred at every stage of the process. He outlined the
stages of developing a project and said for different projects
at different stages, there are different metrics to evaluate a
producer's performance. He posed a hypothetical production
project for which Department of Natural Resources (DNR) had
confidence in the nature of the reserve and resource and a level
of confidence in the economics affecting it and doesn't see
active efforts [on behalf of the producer] to pursue investment.
He pointed out that the optimistic case indicated a very
attractive project. DNR would encourage that producer to develop
or take remedial action against them. He said the internal rate
of return (IRR) would be different in the presentation of the
pessimistic scenario and in those scenarios DNR would be
encouraging a developer to pursue investment from every possible
source and continuing to monitor market conditions to see if
there were material changes that would make that project more
attractive. He concluded that IRR was just one metric for
determining whether a producer was meeting their commitments and
there were many other variables depending on a project's stage
in the overall development cycle.
4:04:51 PM
SENATOR WIELECHOWSKI noted the scenario with two additional gas-
only wells and 30.2 percent IRR, which, he said, was extremely
high. He stated a company that bought a large amount of lease
acreage had an obligation to produce everything. He said the
state gave up that land, gave the resource to that company. He
noted testimony by attorneys that [producers] don't get to make
the decision [to forego production on leased land] and go
somewhere else. He emphasized that producers have an obligation
to produce on all the leases. He asked whether that was
Department of Natural Resources (DNR)'s perspective.
4:06:11 PM
MR. CROWTHER affirmed that it was. He confirmed that oil and gas
companies have the right and obligation to develop leases, with
the state's interests protected through leasing and unitization
programs. If a company fails to explore a lease, the lease may
expire, and the Commissioner may choose not to grant extensions.
Similarly, if a company breaches a unit agreement, the unit may
contract or terminate, reverting leases to the state. Department
of Natural Resources (DNR) actively manages leases, promoting
ongoing development, drilling, and investment to maintain
production. They identify participating areas, consider contract
units, and review annual development plans to encourage
continued investment.
4:07:55 PM
SENATOR WIELECHOWSKI said overriding royalty interest (ORRI) was
noted at five percent on slide 2. He asked whether the
calculations for internal rate of return (IRR) included the
ORRIs. He asked how ORRIs impact DNR's evaluation of a [oil or
gas] field. He opined that a project could be extremely
profitable, but with ORRIs it might not be. He asked whether DNR
would enforce a lease if there were ORRIs.
4:08:42 PM
MR. CROWTHER replied that, generally, the need for development
accrues irrespective of the operator's commercial terms. ORRIs
are a contractual third party right and can be created and
applied in some circumstances, but they wouldn't change the
terms of the lease, implied or otherwise.
4:09:26 PM
MR. MEZA replied that ORRIs and other cash layouts as well as
the cost of production are considered in the calculations for
net present value, internal rate of return and payback period.
4:09:44 PM
SENATOR WIELECHOWSKI asked for confirmation that five percent
ORRI was included in internal rate calculations.
4:09:58 PM
MR. MEZA affirmed that a five percent deduction of the gross
revenue represented payment to the ORRI owners. Anything left
after the five percent deduction would be the cash flow to the
producers, after accounting for the cost of production and
taxes.
4:10:19 PM
SENATOR WIELECHOWSKI asked whether the 19.3 percent [slide 3,
new offshore gas scenario, status quo] included a five percent
ORRI and assumed a fifteen percent annual discount, which, he
opined, is high. He opined that the five percent ORRI shouldn't
be included in the calculations because it is not part of
[DNR's] consideration whether [a producer should] produce.
4:11:00 PM
MR. CROWTHER agreed, conceptually, that projects are more
attractive without royalties of any kind, naturally, because
it's a gross cost. [ORRIs] are included for the model's
hypothetical projects because they represent the reality that
most of the development projects in Cook Inlet already feature
ORRIs under existing contractual commitments and those cannot be
abridged under the DNRs current authority.
4:11:55 PM
SENATOR WIELECHOWSKI pointed out that the state did not force
producers to take on overriding royalty interests (ORRIs). He
opined [ORRIs] skew the economics and the state should not bear
the burden. He said if producers were not producing because
ORRIs make production unprofitable, it [should not be] the
state's problem. He opined that ORRIs should not be considered.
He said it appeared internal rates of return (IRR) would be
several percentage points higher absent ORRIs. He proposed that
if a company is not producing because they agreed to a contract
term that makes it unprofitable [to produce], [the producer]
should give the lease back [to the state].
4:13:29 PM
MR. CROWTHER said he appreciated the point. He noted DNR denied
applications to create new ORRIs under the rationale that they
burden long-term development of state leaseholds. The denials
were upheld by the Alaska Supreme Court. In many cases ORRIs
were created years and sometimes decades ago and they persist
with the life of the lease, so leases that remain may continue
to have ORRIs for a very long time. He said the goal of the
presentation is to provide a realistic hypothetical that matches
the scenarios seen currently in Cook Inlet with contractual
commitments [including ORRIs], some of which were put in place
by developers decades ago.
4:14:32 PM
SENATOR WIELECHOWSKI asked whether the ORRIs would disappear if
the state took a lease back.
4:14:44 PM
MR. CROWTHER replied that ORRIs persist with the life of a lease
and would be terminated with the end of the lease.
4:14:52 PM
SENATOR DUNBAR stated that the goal [of SB 194] was to find a
balance supporting production and reducing the state's revenues
as little as possible. He referred to the modeling charts and
said it appeared that under Amendment [6] (A.15), producing
companies would be in no worse shape and the state would earn
$55-60 million dollars more. He said that seemed ideal and asked
for further explanation.
4:16:08 PM
MR. MEZA explained that the reason for different discount rates
for the state and for investors was to represent the opportunity
costs for each side. Investors would consider various risk
profiles and the state would consider its alternatives for
future cash flow. He said that is the main reason the state uses
a lower discount rate and that has been done for other types of
analysis. He acknowledged comparing those different perspectives
might lead to a disconnect.
4:17:19 PM
SENATOR DUNBAR sought to clarify his question. He noted that the
payback, internal rate of return (IRR), and net present value
(NPV) are about the same [see slide 3, new oil and associated
gas scenario, line 3, compared to line 9] for the status quo and
[the projected results of] Amendment [6] (A.15). He said slide 4
shows that revenue to the producer remains about the same and
revenue to the state is $50-60 million more under Amendment [6]
(A.15) [line 1] than under the status quo [line 1]. He asked if
he was misunderstanding the model.
4:18:28 PM
MR. MEZA noted the comparison of fixed royalty rates of five
percent whereas Amendment [6] (A.15) uses royalty rates that
vary throughout three periods. The calculations reflect the
impact of those different royalty rates and constitutes a large
portion of revenues to the state. He said cash flow to producers
is just one component of different cash outlays for investors
that includes not only royalty rates, but also taxes and
production costs.
4:19:30 PM
SENATOR DUNBAR said if these numbers are correct, it is a very
strong argument for Amendment [6] (A.15) relative to the
zero/five percent structure.
4:19:52 PM
CO-CHAIR GIESSEL noted that the status quo is even better [for
the new oil and associated gas scenario].
4:20:14 PM
MR. MEZA moved to slide 5, transitioning to the pessimistic
case. He said this case assumed the estimated cost [to produce]
related to each of the three project scenarios would be higher
and production was assumed to be lower than for the optimistic
case. He briefly repeated the values from the slide and
explained this [pessimistic case] was included to convey the
message that investors not only consider the [optimistic] case
initially shown, but they also consider variations where costs
are higher, and production is lower. He said investors would
consider the range and assign probabilities for net present
value (NPV), internal rate of return (IRR) and length of payback
period to each of the scenarios based on the investors' appetite
or aversion to risk.
4:23:06 PM
MR. NOTTINGHAM noted the variability in reserve estimates and
capital expenditure (Capex) in subsurface resource drilling
projects. He said the differences are not extreme and are to be
expected due to the inherent uncertainty in such projects. He
stated that the modeling presented represented realistic
scenarios.
4:24:31 PM
SENATOR WIELECHOWSKI recognized the range [of factors considered
for the model] and asked why the range differed for each
scenario. He specified some of the variations between the
scenarios and asked why the model did not assume a uniform range
of conditions to allow for comparison.
4:25:45 PM
MR. MEZA affirmed the observation and explained that the model
intentionally used different percentage changes because the
variables are not observed to change at the same rate in the
market. The model was purposely constructed to demonstrate the
effect of negative shocks to the producer. He said it was valid
to consider other cases with an exact percentage change.
4:26:36 PM
MR. MEZA moved to slide 6, a chart illustrating Project Economic
Metrics: Pessimistic Case. He explained that analysis of the
various scenarios revealed that under pessimistic assumptions,
some projects face negative net present values (NPV) and low
internal rates of return (IRR), indicating potential investor
losses. For instance, the NPV for new oil and associated gas
projects varied from negative $10.8 million to [positive] $46.3
million depending on royalty relief. However, [according to the
modeling] not all projects would benefit equally from royalty
rate reductions, and some may still face financial losses. He
noted a typo in the results for new offshore gas-only scenarios
and promised corrected data post-hearing. He emphasized that
investors would consider both optimistic and pessimistic
scenarios and if the economic metrics of the scenarios do not
meet investors' investment criteria, they may not sanction the
projects. Consequently, there would be no gas or oil production,
and no revenues to the state.
4:30:05 PM
SENATOR DUNBAR recalled that Department of Natural Resources
(DNR)'s strongest argument in favor of SB 194 was that [Cook
Inlet] projects were not moving forward under the current
conditions. He concurred that was clear. He quoted figures from
slide 6 compared to the optimistic case figures. He concluded
that it appears the projects would be profitable under all the
given scenarios and asked which [royalty relief] DNR would
recommend.
4:31:23 PM
MR. CROWTHER answered that Department of Natural Resources (DNR)
generally viewed the state, the consumer, the market and the gas
supply as very sensitive to these projects occurring as soon as
possible. He noted that a small difference in the [royalty
relief] percentage was associated with a small difference in the
economic metrics for the producer. He said the question for the
legislature was whether a slightly more attractive project [for
investors], given the extreme sensitivity to the need for
success, was worth the associated cost [lower revenue to the
state]. He explained that the administration supports
legislation that makes projects more attractive and mentioned a
bill introduced by the governor reducing the state's royalty
interest to five percent for both oil and gas. He said going
lower [with royalty interest to the state] to meet market needs,
is supported [by DNR].
4:33:51 PM
SENATOR DUNBAR concluded from the modeling that [royalty
interest to the state] should stay at five percent and not go to
zero percent given the very small change to IRR for the
producer.
4:34:15 PM
MR. CROWTHER said it depended on the scenario. He agreed that
for the gas-only scenario, staying at five percent was
attractive. He noted the differences in the model scenarios,
highlighting the different potential outcomes to the producers'
economic indicators of applying different royalty rates. He
recommended looking across all possible scenarios and choosing
the [royalty interest rate that strikes the] right balance.
4:35:07 PM
SENATOR DUNBAR noted that it would be hugely expensive for the
state to cut the royalty interest on oil to zero and that
[legislation to lower the royalty interest] should be focused on
gas.
4:35:25 PM
MR. CROWTHER said it was DNR's firm position that success
required all three of these projects moving forward. He
advocated for finding a balance that would encourage all three
production scenarios as well as exploration.
4:36:21 PM
SENATOR WIELECHOWSKI expressed appreciation for the modeling
presentation and said it was what the committee requested and
needed. He observed:
• overriding royalty interests (ORRIs) distort the oil and gas
royalty analysis and the state should not have to bear the
ORRI burden.
• the 15 percent discount rate also distorts the analysis by
underestimating returns and leading to unrealistic conclusions
about payback periods.
• the AIDEA reserve-based lending program, which allows for
lower discount rates, could be more economically beneficial.
SENATOR WIELECHOWSKI concluded that oil remains profitable under
all scenarios and did not see a strong case for reducing the oil
royalty rate.
4:38:25 PM
MR. NOTTINGHAM said this oil project represents what is known
about oil projects in Cook Inlet. He noted the significant
decline from 18,000 barrels per day in 2018 to below 9,000
barrels currently. He said that no new oil wells have been
drilled since late 2018 or early 2019. He emphasized that
despite the economic potential of a new oil project, there are
challenges in advancing further oil development in the Cook
Inlet.
4:39:32 PM
SENATOR WIELECHOWSKI asked whether companies have come forward
with oil projects that are not economic.
4:39:39 PM
MR. NOTTINGHAM said he was not aware of any, but hesitated to
say there weren't any. He said there were companies looking into
developing additional oil in Cook Inlet, beyond the more well-
known projects, and they report significant challenges,
including high costs, high risk and [limited] access to
services, drilling rigs, etc.
4:40:36 PM
CO-CHAIR GIESSEL noted that the governor talked about
encouraging companies to drill for gas. She asked whether he was
also encouraging oil development. She pointed out that gas was
associated with oil and [oil] was more profitable.
4:40:57 PM
MR. CROWTHER said the governor's bill referenced earlier
included both gas and oil and DNR supported that because of the
value of a healthy market service industry. He said equipment
and drilling services are all supported when people are pursuing
oil, gas or both. He noted consumers were using both oil and gas
and both were important commodities.
4:41:32 PM
CO-CHAIR GIESSEL appreciated the presentation and affirmed that
it provided the information the committee sought.
4:42:20 PM
NICHOLAS FULFORD, Senior Director, Gas and Energy Transition,
Gaffney Cline, Houston, Texas gave a modeling presentation on
the application of SB 194 to the Economics of Cook Inlet
Developments.
MR. FULFORD moved to slide 8 at the direction of the chair.
[Original punctuation provided.]
Development Cases Evaluated
Royalty relief proposals were evaluated for two
hypothetical Cook Inlet developments.
• Project 1: Standalone shallow water gas field
• Project 2: Gas well (incremental development) in
an existing onshore gas-condensate field. (work
in progress)
Detailed excel model has been developed, capable of
modelling multiple scenarios
[Slide 8 includes a screen-shot of the Excel model.]
MR. FULFORD stated that the model was still a work in progress
and while they have a good understanding of the gas side, they
haven't delved into the oil side yet and the presentation would
focus on gas developments and economics.
4:44:00 PM
MR. FULFORD moved to slide 9.
[Original punctuation provided.]
Sensitivity to Royalty Changes
• Royalty changes will help to create an investment
case
• Other features are more influential, especially gas
purchase price and production levels
• Higher production levels can be facilitated by
additional gas storage
MR. FULFORD explained the significance of royalty changes for
gas or oil developers, noting that their impact on the
investment's net present value (NPV) is comparable to a 20
percent change in operating expenses (Opex) and somewhat less
than 20 percent change in capital expenditures (Capex). He
emphasized that maximizing production levels and the price of
the gas sold are the two major factors that substantially
influence the project's economics.
4:44:56 PM
MR. FULFORD moved to slide 10, consisting of several data tables
illustrating three different cases or scenarios of gas
development and the potential outcome of various royalty
interest levels:
Case 1: 250 billion cubic feet (bcf) offshore development, with
all the processing facilities contained on a new offshore
platform; gas delivered by pipeline.
Case 2: gas is produced in the platform, then tied into another
offshore facility, and from there, it goes to market. He noted
this case was the most economic.
Case 3: is a tie back to onshore production, which he compared
to the Cosmopolitan concept.
MR. FULFORD explained the tables and concluded that the
difference between a 10-year relaxation royalty and an
indefinite royalty is quite marginal and unlikely to change the
perspective of an investor.
4:47:07 PM
SENATOR WIELECHOWSKI asked whether a ten percent overriding
royalty interest (ORRI) was included in the model.
4:47:09 PM
MR. FULFORD said a five percent ORRI was included.
4:47:21 PM
MR. FULFORD moved to slide 11 titled, Example Economics - 250
bcf vs 500 bcf standalone platform. The slide contains two data
tables and two graphs comparing economic data for two different
gas production volumes at a given standalone platform. He noted
the economic case moves from being sub-economic for [production
level of 250 bcf] to fairly attractive IRR and NPV numbers for
[production level of 500 bcf]. He said the scale of the
development is particularly important as well as the manner in
which new developments are brought to market and the extent to
which they use existing infrastructure. He noted that, for the
250 bcf case, using existing infrastructure for the tie in is a
prerequisite for investment.
4:48:23 PM
SENATOR DUNBAR asked for clarification about the difference
between the two projects on the slide.
4:48:34 PM
MR. FULFORD said one illustrated 250 bcf [of gas] recovered and
the other illustrated recovery of 500 bcf. He said this was to
demonstrate the importance of scale [of production].
4:49:04 PM
MR. FULFORD moved to slide 12 titled, Example Economics - Impact
of 100 percent Take or Pay and flat daily nominations. Slide 12
contained two data tables and two graphs comparing the potential
economic outcomes for two different contractual arrangements
between a gas producer and a gas and power utility [purchasing
the gas]. He noted the sensitivity of the gas economics to the
nature of the contract. The slide was informed by analyzing
contracts available on the public domain, comparing minimum and
maximum daily contract volume with annual contract volume. He
pointed out that, especially for the gas and power utilities in
Alaska, a significant degree of contractual flexibility is
required to deal with demand changes due to weather, etc.
MR. FULFORD explained that one scenario demonstrated a
contractual obligation for the gas buyer to nominate [purchase]
exactly the same quantity of gas every day, effectively removing
the volume risk from the gas producer. He pointed out that the
impact on the NPV and the IRR was substantial and said he would
revisit the comparison when he presented recommendations and
consequences.
4:50:28 PM
MR. FULFORD moved to slide 13 titled, Example Economics - Impact
of potential Gas Line/Price Adjustment ($1/MMBtu discount in
2035). The slide contained two data tables and two graphs and
was intended to convey the perspective of a global investor who
has the choice of deploying capital anywhere in the world. It
illustrated the impact on Cook Inlet of a potential liquid
natural gas (LNG) line development. He said such a development,
particularly if it's linked to an LNG export plant, would be a
huge asset to the state and would bring in very substantial
state revenues. However, for a Cook Inlet producer, it
represented a significant risk. The economics of an LNG line as
well as public statements by Alaska Gasline Development
Corporation (AGDC), suggest that if such a project were built,
it would deliver gas to the rail belt area at a substantial
discount to what people were currently paying for gas out of
Cook Inlet. He said, even with robust contractual obligations
between gas buyer and seller, this sort of global market action
is very disruptive.
MR. FULFORD explained that slide 13 posed a hypothetical start
date of 2035 for the LNG line and assumed that there would be a
$1 discount price adjustment. He pointed out that the model
indicated a significant effect on the IRR for the Cook Inlet gas
producer. He said, from an investor perspective, these events
would make it much more difficult to finance a project in Cook
Inlet.
4:52:47 PM
SENATOR WIELECHOWSKI asked what the general, overall lifting
costs were in Cook Inlet, the cost to produce one million cubic
feet (mcf) of gas.
4:53:02 PM
MR. FULFORD said [producers] were carrying a two dollar per mcf
operating cost. He elaborated, noting the capital expenditures
(Capex) recovery and amortization would be on top of that, plus
tax royalties, etc. From a purely operating expenditures (Opex)
point of view, direct cost is about two dollars per Mcf.
4:53:33 PM
SENATOR WIELECHOWSKI asked for a sense of the all-end cost.
4:53:39 PM
MR. FULFORD replied that at a relatively low discount rate, for
example ten percent, it would be potentially less than the $8.50
that is being paid for the gas. However, he pointed out that the
cost of borrowing and IRR expectations could change the picture
substantially. He suggested that sharing the model and other
scenarios he had prepared would help address the question.
4:54:28 PM
MR. FULFORD moved to slide 14
[Original punctuation provided.]
Key Conclusions
• A 250bcf offshore development typical of the Cook
Inlet currently has marginal economics if
developed as a stand alone platform
• A tie-back to offshore or onshore infrastructure
is needed
• In this case, changes to royalty may be help in
establishing an investment case for development
• A larger resource base considerably improves
economics
• Royalty reductions may still be required to
meet investor requirements
• Higher average production significantly helps
investment case
• The potential for "disruption" owing to a gas
line from the North Slope is material within the
lifetime of these projects
• There are many examples internationally of
material changes in the market creating
"stranded assets"
• In fill wells appear to have strong economics,
without royalty changes
MR. FULFORD said his initial impressions were that Cook Inlet
gas would have relatively good economic returns. However, over
the last five years, perspectives and expectations for dry gas
projects changed significantly with restricted access to
capital. He emphasized that economically justifying a standalone
250 bcf gas development was very difficult, with or without a
concession on the royalty. Existing infrastructure could make a
250 bcf project more feasible and a 500 bcf development may be
very respectable. He said the concerns for operators and
investors were aged infrastructure, which posed very high
technical risk, and abandonment costs, as well as the difficulty
of obtaining oil and gas services, offshore and onshore. He said
these features begin to explain why an apparently attractive gas
province has failed to attract capital for development. He said
the imbalance between apparent economics and action on the
ground, was clearly something experienced over the last many
years, and was part of the reason for SB 194.
4:57:25 PM
SENATOR DUNBAR noted the point about disruption to the [market
via a gas line] and mentioned a large project by BlueCrest that
was having difficulty accessing capital. He asked whether
investors are hesitant to invest in Cook Inlet because of
worries about a developing LNG line. He said that seemed
optimistic and noted that it would take a long time to build [an
LNG pipeline]. He said it seemed Cook Inlet producers would have
years, if not decades of profitable operation before the [LNG
line would operate]. He asked for clarification.
4:58:03 PM
MR. FULFORD said that when he puts himself in the place of
someone considering the deployment of $300 or $400 million
dollars of capital in a project that has a 15-to-20-year payback
period, these are the sorts of things he would worry about. He
explained that when he has been asked to determine the causes
for past chaotic outcomes for major gas investments, he found
market disruptions such as price deregulation or the
introduction of new technology or a new project. He said it was
often these significant changes in the market dynamic which
completely unraveled a gas project, because of their long-term
nature. He said that, although it might seem a little odd that
somebody would look at what is a highly speculative project and
allow it to put them off an investment, it's a real factor which
an investor might contemplate, but he said he thought there were
solutions for that.
4:59:39 PM
SENATOR WIELECHOWSKI asked whether Mr. Fulford had any comment
on the previous presentation by Department of Natural Resources
(DNR).
4:59:54 PM
MR. FULFORD replied that nothing stood out as being materially
different. He said GaffneyCline (GC) took a different modeling
approach with more detailed development plan assumptions, but
that, directionally, the two models were similar.
5:01:25 PM
At ease.
5:03:18 PM
CO-CHAIR GIESSEL reconvened the meeting.
5:03:23 PM
MR. FULFORD moved to slide 15.
[Original punctuation provided.]
What facets may be helpful to spur continual
exploration and development?
• The key economic impact of tie-ins and tariffs for
access to infrastructure may support regulatory
action to improve utilization of existing pipelines
and processing facilities
• High take or pay gas offtake contracts would assist
in improving economics, but may lead to higher
consumer prices for gas and electricity
• Potential for a socialized "reliability charge"
on utility bills
• Cooperation between buyer groups, with sub-
allocation
• Additional storage may also release greater value by
reducing volumetric flexibility needs of the field
production
• Very strong contractual mechanisms to maintain
commerciality of Cook Inlet environment, should a
gas line be constructed.
MR. FULFORD expanded on the ideas for the committee to consider.
He noted that Cook Inlet has an array of existing infrastructure
around processing pipelines, gathering plants, etc. One of the
conclusions from the economics is that efficient utilization of
existing infrastructure will aid future development of new gas
and could make the difference between an investable project or
not. He said some kind of structured approach to utilization of
existing assets might be something to consider.
5:04:41 PM
MR. FULFORD noted that flexibility in a dry gas contract is
economically damaging and very costly for the producer and
investor, but equally for the consumer, whether it be an
electric utility or a gas utility. He suggested determining
where that risk sits and who should pay for it. He noted that
was not part of SB 194 but said some kind of structured
mechanism whereby the gas buyers in the state could offer the
gas producers a greater degree of firm demand would, in turn,
help the economics. He acknowledged that it may have
consequences for energy users.
5:05:46 PM
MR. FULFORD said another factor to consider was the value of
storage in the Cook Inlet. Given the climate changes that occur
in that part of the world, having gas storage is an essential
part of meeting demand fluctuations. One consideration would be
to determine whether investment dollars would best be spent
increasing the storage capability and thereby leveling out the
gas production from new facilities, or whether it would be best
spent on the new facilities themselves.
MR. FULFORD concluded by addressing the considerations for Cook
Inlet and the possibility of a new gas line. He suggested the
state could consider some kind of mechanism providing for a
supporting agreement to maintain the value of Cook Inlet gas in
the event of a gas line, thereby alleviating some of the
concerns of potential Cook Inlet development investors.
5:06:59 PM
SENATOR DUNBAR said the last point implies that gas producers
would want very long contracts. Currently, he said gas
purchasers like ENSTAR, are asking for long contracts, but the
producers are refusing to give them long contracts. He asked for
an explanation for that observation.
5:07:27 PM
MR. FULFORD opined that the nature of those contracts is
unusual. Typically, a long-term, firm offtake contract would be
something an investor or lender considers a prerequisite for
investment. He suggested that the technical features of
developing the gas resources in Cook Inlet may be leading the
gas producer to hold back that option depending on market
conditions. He opined that mechanisms to generate a longer term,
stable investment platform for dry gas is a good thing and
understanding why producers are not willing to embrace long-
term, firm contracts would be very helpful.
5:08:42 PM
MR. FULFORD moved to slide 16.
[Original punctuation provided.]
Other commentary
• HB 393 requires further study, with benefit of
oil examples
• If differential royalty changes are applied, they
may be better assigned to utility contracts,
owing to the more variably demand pattern
• Could be administratively complex to
administer
• Unlikely to make a difference to investment
levels
• Export market for Cook Inlet gas not
considered viable
• HB280 appears to have been appropriate for the
environment that existed in 2010. Other
jurisdictions have experienced similar investment
challenges owing to a changed market conditions.
• Recent history suggests that a relaxation on oil
royalties may be necessary to maintain or slow
decline in the basin, but this has not been
studied yet.
MR. FULFORD said he would need more time to incorporate oil
mechanisms into the model. He addressed a question from the
committee about applying different royalty rates and said there
could be an argument for assigning royalty discounts to the
utility contracts which have volume inefficiency embedded in
them, rather than the flat demand that, for example, a refinery
would have for fuel. He questioned whether the administrative
burden and the difference it would make to an investor would be
worth breaking it up in that way, however.
5:09:50 PM
MR. FULFORD addressed the possibility of out-of-state markets
and said Cook Inlet gas was not a viable source of energy for
export markets because the cost is just too high.
MR. FULFORD answered a question about House Bill 280 from 2010.
He said the environment for gas, in particular, is very
different now than it was then. He said when House Bill 280 was
debated and put in place he didn't see anything inappropriate
given what people knew at that time. However, considering what's
happened since then, clearly there are things which could have
been changed.
5:10:40 PM
MR. FULFORD offered a final comment on oil royalties, based on
public domain information and history. He said there seemed to
be diminishing interest in developing oil in the Cook Inlet and
questioned whether royalty rates were part of that. He said it
could be something to look at in a lot more detail.
5:11:13 PM
SENATOR KAUFMAN suggested a model showing replacement of Cook
Inlet gas. He said it was important to consider. He opined that
the worries about royalty rates were less a concern than the
looming possibility of the total replacement of Cook Inlet gas,
which would make Cook Inlet completely uneconomic, resulting in
no revenue for the state. He asked for comment on that and how
quickly a model incorporating oil metrics could be prepared.4
5:12:01 PM
MR. FULFORD replied that the alternatives to Cook Inlet were all
potentially complex, time-consuming, and expensive. He
highlighted the liquid natural gas (LNG) option and said it
would involve a high price of gas and the leasing of a floating
storage unit for what would be a relatively small volume of gas
in early days. He said it would lead to a disproportionately
high fixed tariff for a vessel of that sort. He concluded that
the LNG option for the short to medium term would be expensive
compared to further incentivization for Cook Inlet development.
He revisited an earlier comment about whether the state should
use its own resources to invest in a kickstart for Cook Inlet
development. He said that could be an avenue to pursue and
suggested modeling for consideration.
5:13:55 PM
SENATOR WIELECHOWSKI asked for Mr. Fulford's perspective on the
discussion about a sunset provision that would go into effect
ten years after production and the proposal to incentivize
quicker production using a waterfall concept.
5:14:25 PM
MR. FULFORD questioned the benefit of a sunset provision to
incentivize early production versus a permanent reduction [in
royalties] because it adds risk to the back end of the profile.
He said many of the other risks also increase in magnitude
further down the profile. The potential for a return or an
increase in royalties after ten years, for example, may have a
negative influence. He said he would need time to consider
mechanisms to incentivize early production that might be
applicable to Cook Inlet.
5:15:50 PM
SENATOR WIELECHOWSKI asked for general advice.
5:16:03 PM
MR. FULFORD replied that the implications of a significant gas
shortage in Cook Inlet for the whole of the Railbelt and the
Alaska economy are such that, at this point in time, he would
err on the side of creating a more generous investment climate
for potential new gas developments rather than holding back in
an effort to mitigate losses to the state. He said he was
unaware of current analysis to determine the implications of
volatile energy prices for Alaska businesses and consumers in
terms of jobs, etcetera, but the implications of that would lead
him to err on the side of caution, lifting royalties more than
they might think would strictly be necessary. He said that might
lead to a good outcome.
5:17:13 PM
SENATOR WIELECHOWSKI noted that oil seemed to be profitable
under all scenarios. He asked how important it was to reduce the
oil royalty and what rate Mr. Fulford would recommend.
5:17:29 PM
MR. FULFORD acknowledged that he had not yet studied the oil
situation in as much detail as gas, but to revive Cook Inlet and
create a dynamic investment environment with the return of
services and to make it attractive to global investors, changing
oil royalty rates may be advisable and would indicate Alaska is
a place to do business.
5:18:29 PM
[CHAIR GIESSEL held SB 194 in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 194 Amendment #A.1.pdf |
SRES 5/8/2024 3:30:00 PM |
SB 194 |
| SB 194 Amendment #A.2.pdf |
SRES 5/6/2024 3:30:00 PM SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |
| SB 194 Amendment #A.7.pdf |
SRES 5/6/2024 3:30:00 PM SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |
| SB 194 Amendment #A.10.pdf |
SRES 5/6/2024 3:30:00 PM SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |
| SB 194 Amendment #A.14.pdf |
SRES 5/8/2024 3:30:00 PM |
SB 194 |
| SB 194 Amendment #A.15.pdf |
SRES 5/8/2024 3:30:00 PM |
SB 194 |
| SB 194 Amendment #A.16.pdf |
SRES 5/6/2024 3:30:00 PM SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |
| SB 194 Amendment #A.17.pdf |
SRES 5/6/2024 3:30:00 PM SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |
| SB 194 GaffneyCline Modeling 5.8.24.pdf |
SRES 5/8/2024 3:30:00 PM |
SB 194 |
| SB 194 DNR Modeling 5.8.24.pdf |
SRES 5/8/2024 3:30:00 PM SRES 5/9/2024 2:00:00 PM |
SB 194 |