Legislature(2021 - 2022)SENATE FINANCE 532
03/18/2022 09:00 AM Senate FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| Presentation: Cook Inlet Update by Department of Natural Resources and Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 62 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 18, 2022
9:22 a.m.
9:22:07 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 9:22 a.m.
MEMBERS PRESENT
Senator Click Bishop, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Lyman Hoffman
Senator Donny Olson
Senator Bill Wielechowski
Senator David Wilson
MEMBERS ABSENT
Senator Natasha von Imhof
ALSO PRESENT
Dan Stickel, Chief Economist, Economic Research Group, Tax
Division, Department of Revenue; John Crowther, Deputy
Commissioner, Department of Natural Resources; Ryan
Fitzpatrick, Commercial Analyst, Division of Oil and Gas,
Department of Natural Resources.
PRESENT VIA TELECONFERENCE
Heather Heusser, Natural Resource Specialist, Division of
Oil and Gas, Department of Natural Resources; Maduabuchi
Pascal Umekwe, PhD, Commercial Analyst, Division of Oil and
Gas, Department of Natural Resources.
SUMMARY
SB 62 GAS LEASES; RENEWABLE ENERGY GRANT FUND
SB 62 was SCHEDULED but not HEARD.
PRESENTATION: COOK INLET UPDATE BY DEPARTMENT OF NATURAL
RESOURCES AND DEPARTMENT OF REVENUE
9:22:52 AM
AT EASE
9:23:01 AM
RECONVENED
Co-Chair Stedman relayed that the committee would not hear
SB 62. The committee would consider updated presentations
from the Department of Revenue (DOR) and the Department of
Natural Resources (DNR) on the topic of a Cook Inlet
update.
^PRESENTATION: COOK INLET UPDATE BY DEPARTMENT OF NATURAL
RESOURCES AND DEPARTMENT OF REVENUE
9:23:56 AM
DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX
DIVISION, DEPARTMENT OF REVENUE, discussed the presentation
"Cook Inlet Update - Senate Finance Committee" (copy on
file). He relayed that the purpose of the presentation was
to provide information about production investment and
state revenue, specific to Cook Inlet oil and gas.
Mr. Stickel looked at slide 2, "Acronyms":
ANS Alaska North Slope
AOGCC Alaska Oil and Gas Conservation
Commission
Avg Average
Bbl Barrel
BOE Barrels of Oil Equivalent
CI Cook Inlet
CIT Corporate Income Tax
CY Calendar Year
Acronyms
DNR Department of Natural Resources
DOR Department of Revenue
FY Fiscal Year
GVPP Gross Value at Point of Production
mcf Thousand cubic feet
mmcf Million cubic feet
PTV Production Tax Value
Ths Thousands
Mr. Stickel spoke to slide 3, "Agenda":
? Oil and Gas Revenue Sources
o Production tax and January 1, 2022 changes
o FY 2020 FY 2024 Cook Inlet oil and gas
revenues
? Cook Inlet Oil and Gas Prices
? Cook Inlet Oil and Gas Production
Non-North Slope Lease Expenditures
? Non-North Slope Tax Credits
? Petroleum Revenue by Land Type
Mr. Stickel expanded that he would discuss some of the
activity and company spending related to tax credits. He
noted that the chart at the end was included for reference
and summarized that not all oil is equal in Cook Inlet
just as on the North Slope.
Mr. Stickel referenced slide 4, "Oil and Gas Revenue
Sources
? Royalty based on gross value of production
o Plus bonuses, rents, and interest
o Paid to Owner of the land: State, Federal, or
Private
o Usually 12.5% or 16.67% in Alaska, but rates
vary
? Corporate Income Tax based on net income
o Paid to State (9.4% top rate)
o Paid to Federal (21% top rate)
o Only C-Corporations* pay this tax
? Property Tax based on value of oil & gas property
o Paid to State (2% of assessed value or "20
mills")
o Paid to Municipalities credit offsets state
tax paid
? Production Tax based on "production tax value"
o Paid to State calculation to follow
* C-Corporation is a business term that is used to
distinguish the type of business entity, as defined
under subchapter C of the federal Internal Revenue
Code.
9:26:50 AM
Mr. Stickel turned to slide 5, "Cook Inlet Production Tax:
Before and Starting January 1, 2022," which showed a table.
He noted that there had been some recent changes to the
production tax in Cook Inlet, which worked differently than
the North Slope. For the Cook Inlet in particular, a
company nominally paid a tax rate of 35 percent of
production tax value. He explained that the production tax
was the gross value of the oil and gas produced less
allowable lease expenditures. There were no per-taxable
barrel credits in Cook Inlet, and there was no minimum tax
floor. There was a tax ceiling of $1 per barrel of oil
produced, and a tax ceiling averaging $17.7 cents per
thousand cubic feet of gas produced. The gas ceiling varied
by property.
Mr. Stickel continued to address slide 5. He recounted that
in 2016, HB 247 was passed and repealed most of the tax
credits in Cook Inlet. The credits were phased out by
January 1 of 2018. The change that took effect on January 1
of 2022 had to do with how gas was taxed. Prior to 2022,
oil and gas were subject to net tax. A company that
produced both oil and gas would allocate its lease
expenditures between oil and gas in calculating the net
tax.
Mr. Stickel continued his remarks. The change that happened
in the current year was that gas production was now subject
to a 13 percent gross tax, and all lease expenditures were
now allowed to be deductible against the oil tax
calculation. The change was in place as part of SB 138,
which passed in 2014 and intended to support a major gas
sale. The changes to the statutes for gas was taxed and how
lease expenditures were allocated applied statewide.
Co-Chair Stedman asked Mr. Stickel to touch on the gas tax
rate of 13 percent of gross value of point of production.
Mr. Stickel noted that prior to January 21, 2022, oil and
gas were both taxed at 35 percent of production tax value
with a tax ceiling in place. Beginning on January 31, 2022
oil was still taxed at 35 percent of production tax value,
and the $1/bbl tax ceiling still applied. Starting in the
current year gas was taxed at 13 percent of gross value,
and the $17.7 cents per thousand cubic feet tax ceiling
still applied.
Co-Chair Stedman asked if future presentations would show
the tax ceilings.
Mr. Stickel informed that slide 6 would show a history and
forecast of revenue for Cook Inlet.
9:30:25 AM
Mr. Stickel considered slide 6, "Cook Inlet Oil and Gas
Revenue: Five-Year Comparison," which showed a table
depicting two full years of history, the current fiscal
year, and two years of forecast. He noted that the five
years was broken out to see two full years with and without
the recent tax changes. The property tax shown represented
the state share of property tax only, and there was a
similar amount of property tax levied by municipalities as
well. The corporate income tax represented the total
estimated corporate income tax for non-North Slope. The
production tax did incorporate the tax changes that took
effect on January 1.
Mr. Stickel continued that the department was forecasting
that the tax ceilings would apply for gas. The estimate was
that gas would be paying the $17.7 cents per thousand cubic
feet tax ceiling. The department was forecasting that oil
would be paying only the private landowner royalty and
hazardous release surcharge. The 35 percent net tax
calculation was not expected to generate an oil tax
liability for production tax. He pointed out that the shift
to the 13 percent gross tax resulted in a tax increase for
Cook Inlet. The state had been receiving a little under $1
million per year in production tax, which was expected to
increase to around $7 million per year starting in FY 23.
Mr. Stickel addressed royalties, which included bonuses,
rents, and interest, as well as the Permanent Fund and
School Fund shares, which were the largest source of state
revenue from Cook Inlet. He informed that DNR did not
forecast Cook Inlet oil price or gas price explicitly. For
Cook Inlet oil price, the department used the North Slope
oil forecast as a proxy, because the values of the oils
were fairly similar in the market. For gas prices the
department used the prevailing value published by DOR, and
assumed that the prices would increase with inflation going
forward. He noted that DNR did produce an oil production
forecast specific to Cook Inlet. For gas production, DNR
took the most recent fiscal year production and assumed
there would be stable production.
Co-Chair Stedman asked about slide 7.
Mr. Stickel displayed slide 7, "Cook Inlet Oil and Gas
Prices," which showed a graph with two lines depicting the
price of oil and gas over time from 2018 to 2031.
Co-Chair Stedman asked about a hypothetical scenario in
which the price of oil stayed level at $80/bbl, and whether
the gas tax would also run horizontally.
Mr. Stickel explained that for DOR's forecast, the
department estimated that, given that all the lease
expenditures were deductible for oil, the department was
not forecasting a net profits tax payment from oil. The
department was forecasting very little in tax from oil, and
that the $17.7 cents per thousand cubic feet tax ceiling
would essentially be the gas tax that was paid. He
explained that slightly higher or slightly lower oil or gas
forecast would not significantly impact the production tax
revenue for Cook Inlet, but it would impact royalty.
Mr. Stickel explained that slide 7 showed a history and
forecast of Cook Inlet gas and oil prices with oil price
values on the left axis and gas price values on the right
axis. He reiterated that the department used the forecast
for Alaska North Slope oil as a proxy for Cook Inlet oil,
and then assumed consistent growth with inflation for gas
prices.
9:35:19 AM
Co-Chair Stedman asked for more discussion related to the
forecast oil and gas prices and how it was tied to
inflation.
Mr. Stickel relayed that for gas prices, DOR published the
prevailing value for Cook Inlet gas prices. He continued
that DNR used an official inflation assumption of 2.25
percent, which was incorporated into the forecast. He
acknowledged that inflation was running a little higher
lately. He summarized that the department took the most
recent year of published prevailing value and assumed gas
prices would increase by 2.25 percent.
Co-Chair Stedman understood there were long-term contracts
in Cook Inlet, which meant production was tied up for
several years. He asked if the contracts dictated what the
gas would be worth coming out of the ground. He added that
Cook Inlet was a closed basin.
Mr. Stickel affirmed that the gas forecast was a na?ve
forecast with assumptions around production and price
given the relatively small impact on state revenue. He
acknowledged that there were definitely reasons gas prices
could be higher or lower than the forecast.
Co-Chair Stedman doubted that there would be gas prices to
the citizenry climb with inflation in perpetuity. He did
not think it seemed logical with a closed basin and long-
term contracts.
Mr. Stickel highlighted slide 8, "Cook Inlet Oil and Gas
Production," which was a similar chart to the previous
slide but for oil and gas production. He relayed that Cook
Inlet was Alaskas first oil and gas basin, began producing
in the 1950s, and peaked at 230,000 barrels per day of
production in the early 1970s. The inlet had supplied the
Southcentral gas market for many years with exporting gas
to Asia. More recently for oil production, there had been a
pretty significant increase when Hilcorp entered the inlet
in 2012, which had coincided with some very generous tax
credits offered by the state at the time.
Mr. Stickel continued that generally production of oil had
been declining since 2015, since the bump in production. He
noted that DNR forecasted Cook Inlet oil production and
foresaw new projects that would stabilize production over
the next decade. He reiterated that DOR and DNR did not
explicitly forecast natural gas production, but assumed it
would be stable going forward. He understood some reserves
existed, so that companies could supply the market for the
next several years. He thought the forecast was a
reasonable assumption for modelling purposes.
9:38:46 AM
Co-Chair Stedman asked to go back to slide 7. He wanted to
gain clarity on the concept on ever-increasing price
increases based on inflation in a closed basin with long-
term price contracts. He asked if the Regulatory Commission
of Alaska (RCA) got involved in pricing of gas and utility
issues in the Railbelt.
Mr. Stickel explained that the concept of the inflation
adjustment was that in current dollar terms, the cost of
the gas would be unchanged. The cost of operation and the
cost of producing the gas would be similar. The only
adjustment being made was for general inflation in the cost
of anything. If the chart was shown in real terms, it would
reflect a flat price.
Mr. Stickel looked at slide 9, "Non-North Slope Lease
Expenditures," which showed a graph. He expanded that the
story told by the graph was that if there were high oil
prices, low taxes, and generous state support, there would
be investment. There was significant capital investment in
Cook inlet in the early and mid-2010s, spurred by the Cook
Inlet Recovery Act in 2010 and provided very generous tax
credits for drilling and exploration in the inlet.
Coinciding with the act, Hilcorp entered the inlet in 2012
and had a focus on renewing and extending field life. More
recently there had been a capital investment decline that
followed the decline in oil prices starting the second half
of 2014 as well as the repeal of most of the tax credits in
Cook Inlet in 2016. The forecast expected fairly modest
capital spending going forward. He commented that operating
costs had been fairly stable, with a slight decline during
the Covid-19 pandemic as some activities were scaled back.
The department was expecting that the activities would
bounce back in the current year and stabilize at a little
over $300 million per year.
Senator Hoffman thought the chart on slide 9 did not take
into consideration what was happening in Russia, where
sanctions were shutting down 600 million barrels of oil per
day. He asked how the graph might be affected into the
future if the sanctions continued.
Mr. Stickel stated that to some extent, the impact of what
was happening in Russia was reflected in a higher expected
oil price forecast. The department had made some adjustment
to the lease expenditures forecasts to account for the
potential that cost across the industry would be inflated a
bit with the higher oil price forecast. He considered
protracted disruptions to the market, and thought it was
possible that a demand for more investment or a tighter
market for services could potentially increase the cost of
doing business.
9:42:58 AM
Mr. Stickel addressed slide 10, "Non-North Slope Tax
Credits," which showed a chart of ten years of history and
forecast for tax credits for non-North Slope. He cited that
the chart was consistent with figure 8-4 of the Spring 2022
Forecast. He explained that DOR aggregated the data from
Cook Inlet with all other activity outside of the North
Slope for confidentiality purposes. The credits against tax
liability included capital expenditure credits, net
operating loss credits, well-lease expenditure credits, and
small producer credits. Most of the credits had been
entirely phased out for Cook Inlet. The "credits purchased"
shown on the graph included capital expenditure credits,
net operating loss credits, well-lease expenditure credits,
exploration credits, gas storage credits, liquid natural
gas (LNG) storage credits, and refinery investment credits.
The large suite of credits available to non-North Slope had
all been repealed and sunset. There were capital
expenditure and net operating loss credits that remained
available outside of Cook Inlet and outside of the North
Slope in the remaining area of the state colloquially known
as Middle Earth.
Mr. Stickel noted that the changes put in place in 2016 led
to the phase-out of the availability of the credits by
2018. Given the state budget issues over the previous
several years, the full value of the credits available for
purchase had not been appropriated each year. For FY 22,
there was $54 million appropriated for purchase of tax
credits, $18 million of which went to non-North Slope
credits. The outstanding balance as of the end of FY 22 was
expected at $264 million for non-North Slope credits, out
of $532 million statewide. The chart showed how the
remaining tax credits specifically for non-North Slope
credits would be paid off, assuming the statutory
appropriation for tax credits were made beginning in FY 23.
He pointed out that given the higher price and revenue
outlook in the spring forecast, he expected the entire
balance of the credits would be retired by 2024.
Co-Chair Stedman expected the committee would not use the
forecast to calculate the credits.
Mr. Stickel understood. He noted that the appropriation
would be slightly less with a lower oil price.
Co-Chair Stedman relayed that the matter would be worked
out at a later time depending upon what the members wanted
to do. He thought he thought there would be a meeting
dedicated to the subject.
9:46:39 AM
Senator Olson agreed with Co-Chair Stedman. He asked about
the non-North Slope tax credits and asked if the reasoning
for getting rid of the credits was due to the ability to
sell the credits or if it was to do with net operating
losses.
Mr. Stickel thought he should not speak to the policy
decisions behind repealing the credits.
Co-Chair Stedman followed up on Senator Olson's question.
He thought the slide showed substantial credits in Cook
Inlet. He mentioned that many members were concerned about
the negative cash flow from Cook Inlet around 2012 through
2015. He asserted that the legislature wanted to assist the
industry in staying viable, but still had to have some
revenue coming in the door. He thought there was negative
cash flow shown on the chart. He requested some data points
from what Non-North Slope revenue had come into the state
during the time, to see how policies had affected revenue
and production, so there was a more realistic view of the
matter. He recalled that the review of the escalating
credits in Cook Inlet relative to the cash flow coming in
had created a conversation with DNR and brought forward the
issue of adjusting the credits. He thought the numbers were
staggering.
9:49:19 AM
Mr. Stickel explained that for the presentation, the slide
showed two years of revenue history. He pointed out an
estimated total Cook Inlet oil and gas revenue to the state
was $68 in FY 20 and $65 million in FY 21. He did not have
the exact numbers going back farther, but could confidently
say that for the years from FY 13 to FY 16 the credits
purchased would have significantly exceeded state revenue
from Cook Inlet.
Co-Chair Stedman suggested that in the future when the
legislature made policy changes, it would be helpful to
look back at numerics. He informed that the legislature had
been trying to stimulate gas production in Cook Inlet to
alleviate potential brownouts. The component that was not
reflected in the data was the changes Regulatory Commission
of Alaska had made in allowing the price to move. Once the
price moved, there was more gas than could be used from
Cook Inlet. He opined that the state had overstimulated
Cook Inlet by hundreds of millions of dollars. He asked Mr.
Stickel to go up to FY 25 with the additional data points
for the graph. He asked Mr. Stickel to use fair discretion
about presenting the credits against revenue.
9:52:24 AM
Mr. Stickel advanced to slide 11, "Non-North Slope Tax
Credits: Key Statistics":
? FY 2007 through CY 2021, $0.1 billion of credits
applied against production tax liabilities
? FY 2007 through CY 2021, $1.6 billion of credits
earned and eligible for state purchase
o $1.3 billion purchased through end of CY 2021
o $265 million outstanding as of end of CY 2021
? Legislative action has eliminated most Cook Inlet
credits:
o Qualified Capital Expenditure Credit, Well
Lease Expenditure Credit, Net Operating Loss
Credit all repealed January 1, 2018.
o Eligibility for In-State Refinery and LNG
Storage Facility Credits ended January 1, 2020.
o Small Producer Credit remains: applicable to
tax liability only, phasing out completely by
2024.
o No per-taxable-barrel credits or carried-
forward loss for Cook Inlet.
Co-Chair Stedman requested that Mr. Stickel back up the
cash flow data to 2007 so it would match the time span on
slide 11.
9:53:59 AM
Mr. Stickel looked at slide 12, "Non-North Slope Tax
Credits: Correlation with Company Activity":
? For the $1.3 billion of credits purchased through CY
2021:
o Non-North Slope lease expenditures for
companies receiving the credits totaled $4.8
billion through CY 2020
? Credit support averaged 27% of lease
expenditures
o $1.1 billion to companies with production by
the end of CY 2020 (includes production by
acquiring companies)
? Total Non-North Slope production through
CY 2020 of 154 million BOE
? Credits to producers equate to $7/ BOE or
$1.18/ mcf
o $215 million to companies without regular
production
? Credits per unit of production and as a share of
lease expenditures will decrease over time due to
additional production and spending
Mr. Stickel explained that slide 12 looked at the $1.3
billion in tax credits for non-North Slope that were
purchased and looked at what activity was seen from the
companies that received the credits. The companies that
received the $1.3 billion in credit had $4.8 billion in
non-North Slope lease expenditures through the end of 2020.
The credits amounted to about 27 percent of lease
expenditures. He noted that for companies that had
production there were about $1.1 billion in credits that
went to NNS companies that were in production, which worked
out to about $7/bbl equivalent, or about $1.18 per cubic
feet of gas equivalent. Additionally, there was about $215
million that went to companies that did not have non-North
Slope production. Some of the companies could have
production in the future, but even if not there were
benefits to the state from the activity that was done
through DNRs data collection.
Co-Chair Stedman was a little concerned about companies
that came forward for credits after producing nothing, and
considered policy adjustments in the future to ensure the
state got something back.
Mr. Stickel showed slide 13, "Non-North Slope Tax Credits:
Correlation with Company Activity," which showed a chart
showing how state petroleum revenues varied by land type.
He cited the concept not all oil is equal. He explained
that production tax, corporate income tax, and property tax
applied everywhere in the state except federal waters three
miles offshore. Royalty rates varied by ownership of the
type of land it was on.
Co-Chair Stedman thanked Mr. Stickel for a response to the
committee regarding the order of operations. He recommended
that Mr. Stickel include the information on the effective
tax rate and accumulation of credits year by year in the
fall revenue forecast. He thought there was a couple
billion in accrued credits, and he thought the information
would help the legislature keep track of and understand the
information.
9:58:19 AM
AT EASE
9:59:11 AM
RECONVENED
JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL
RESOURCES, introduced himself.
RYAN FITZPATRICK, COMMERCIAL ANALYST, DIVISION OF OIL AND
GAS, DEPARTMENT OF NATURAL RESOURCES, discussed the
presentation "COOK INLET GAS MARKET BRIEFING FOR THE SENATE
FINANCE COMMITTEE" (copy on file).
Mr. Fitzpatrick showed slide 2, "Agenda":
?Southcentral Gas Demand
?Cook Inlet Field Overview
?History of Cook Inlet Tax Credit Program
?Exploration and Development in Cook Inlet
?Future Production and Gas Reserves
Mr. Fitzpatrick advanced to slide 3, "SOUTHCENTRAL GAS
DEMAND: DEMAND BY USER TYPE":
Kenai LNG Plant
? Nikiski liquified natural gas (LNG) facility is
operated by, Trans-Foreland Pipeline Co. LLC
which is a sub of Marathon Oil
? 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
? 2nd largest ammonia/urea plant in U.S.
? Shut down and mothballed in 2007, however
Nutrien maintains permits
? Gas prices relative to Lower 48 makes economics
difficult
? Potential source for blue hydrogen/blue ammonia
Mr. Fitzpatrick spoke to the graph on the slide entitled
'Demand for Cook Inlet Gas,' which was broken down into
different user types. The bottom four layers represented
oil and gas operations in the Cook Inlet area. He pointed
out that the four layers represented a stable base of about
75 billion cubic feet per year consumption in the Cook
Inlet Region. He noted that going back to 2000, there was a
little more variability in the power generation use for gas
in Cook Inlet, which was due to a number of factors. He
described differences in electrical efficiency both in end
user level and in power generation. He used the example of
a power plant put in place by Chugach Electric.
Mr. Fitzpatrick pointed out the red layer that represented
the fertilizer plant, and the light green layer
representing the Kenai liquid natural gas (LNG) exports. He
noted that the export sources contributed a significant
amount to gas demand going back to 2000. The fertilizer
plant used gas to create ammonia fertilizer for export, and
the Kenai plant was one of the very early LNG plants in the
world and exported LNG primarily to Asia.
10:03:42 AM
Co-Chair Stedman recalled that the LNG plant had exported
to Japan.
Mr. Fitzpatrick agreed, and described that the plant began
operations in the 1960s, and exported LNG for a long period
of time. He believed for a long while it was the only LNG
export from the United States into the Asia-Pacific region.
Mr. Fitzpatrick continued to address slide 3. He observed
that over time from the 2000s to the 2010s, the two
export facilities were responsible for large amounts of the
gas demand in Cook Inlet. Starting in the 2010s both uses
fell off rather dramatically and was responsible for a
large amount of the decline for demand of gas in Cook
Inlet. He made note of the black layer on the top of the
graph that started around 2010, which represented a small
amount of gas that was diverted from Cook Inlet up into the
Interior LNG Project. The gas was liquified in Cook Inlet
and exported to Fairbanks for primarily residential use.
Mr. Fitzpatrick continued to read information from the
slide related to the fertilizer plant and the LNG plant.
10:06:44 AM
Mr. Fitzpatrick spoke to slide 4, "COOK INLET FIELDS
OVERVIEW: PRODUCTION BY FIELD," which showed a table
listing of the current producing fields in the Cook Inlet
area. He noted there was a number of currently producing
fields, although there were many owners in the inlet,
Hilcorp was the predominant owner of many of the units. He
pointed out that the table had information on the current
2021 production by field, and that gas production was
expressed in billions of cubic feet, while oil was
expressed in barrels per day. There were several fields
producing oil in Cook Inlet, most of which also produced
gas. He thought there was only one or two fields that
produced oil but not gas. He noted that the predominance of
fields in the inlet that produced only gas was one of the
major differences between Cook Inlet and the North Slope
basin. He cited that gas-only production was still capital
intensive, but not as profitable as mixed oil and gas
production, which presented certain challenges for
producing gas in the Cook Inlet Area.
Mr. Fitzpatrick noted there was a map on the slide that
showed the locations of the different fields in Cook Inlet.
He thought the appendices of the presentation also
contained the information. He added that there was a link
on the slide to the department's website to see the larger
map.
Co-Chair Stedman asked about the market saturation due to
longer term contracts in the Cook Inlet area. He asked if
the market was tied up for multiple years, or if there was
huge capacity.
Mr. Fitzpatrick affirmed that the majority of the
production in the Cook Inlet area was tied up in long-term
contracts. The majority of the gas production, going
primarily to residential and electrical use, was tied up in
long term contracts that were approved by RCA. The
contracts had different pricing mechanisms, was sometimes
there was a flat gas price and sometimes with provisions
for escalations in gas price over the term of the contract.
He continued that the other types of gas demand in Cook
Inlet, for commercial uses and oil and gas operations, may
be tied into long term contracts although the contracts
were not subject to approval by the RCA.
Co-Chair Stedman wanted to reverse the question. He queried
how much gas could be delivered to Anchorage without
additional exploration and development in Cook Inlet,
whether there was a one-month supply, five-month supply, or
twenty-year supply.
Mr. Fitzpatrick thought a later slide would address the
question, and would show remaining reserves in Cook Inlet.
10:11:03 AM
Mr. Fitzpatrick addressed slide 5, "COOK INLET FIELDS
OVERVIEW: GAS PRODUCTION HISTORY," which showed two graphs
that addressed historical production within the basin. The
graph on the left showed the production from state leases
by lessee, and the graph on the right showed total
production in Cook Inlet by field and included the gross
production including state, federal, and private leases.
Co-Chair Bishop asked if the private leases were comprised
of pre-statehood homesteads and Native allotments.
Mr. Fitzpatrick affirmed that the number of private leases
in Cook Inlet was relatively small, and the majority of the
private leases were pre-state homesteading leases.
Mr. Crowther added that there was also some production from
Alaska Native corporation owned land.
Mr. Fitzpatrick advanced to slide 6, "HISTORY OF COOK INLET
TAX CREDIT PROGRAM: DESIGN AND PURPOSE," which showed a
table of primary Cook Inlet credits versus other major tax
credits. He cited that DNRs primary interest in the tax
credit program was that a number of the credits required
submission of data to DNR. He drew attention to the left-
hand side of the table, which showed two credits that
required data submission, as well as one credit listed on
the right. In order to qualify for the credits, companies
had to certify and turn over data regarding the wells or
the seismic exploration campaigns undertaken to earn the
credits. The data could be used in-house for DNRs
evaluations of different basins and fields.
Co-Chair Stedman asked if all the companies produced all
the data that was required.
Mr. Fitzpatrick thought there was someone from the
department available online to answer the question.
10:14:49 AM
HEATHER HEUSSER, NATURAL RESOURCE SPECIALIST, DIVISION OF
OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES (via
teleconference), answered in the affirmative. She explained
that as a condition of the tax credit, companies had to
submit the data prior to receiving the credit.
Mr. Fitzpatrick referenced slide 7, "DATA RELEASE THROUGH
THE TAX CREDITS PROGRAM," which showed two maps and
information regarding the seismic data release status and
wellhead data release status of entities that utilized the
tax credits program. In addition to being able to use the
information within DNR, one of the provisions of the tax
credit data program allowed the data to be released to the
public. The areas shown in red were surveys that qualified
for tax credits through the program, but the data had not
reached the statutory holding period by DNR.
Mr. Fitzpatrick continued to address slide 7. The right-
hand side showed information about wells using the tax
credit program. All the data from the wells was publicly
available, and free of charge for research institutions and
government entities.
10:18:23 AM
MADUABUCHI PASCAL UMEKWE, PHD, COMMERCIAL ANALYST, DIVISION
OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES (via
teleconference), spoke to slide 8, "EXPLORATION &
DEVELOPMENT IN COOK INLET: 2000 THROUGH 2021," which showed
the count of wells that had been drilled since 2000. He
drew attention to the top left, which showed the different
categories of wells. On the lower left there was a bar
graph that showed the well count by class over the period.
The blue bars showed the exploration wells and rust bars
showed stratigraphic test wells, both of which were drilled
as part of exploration activity by operators in Cook Inlet.
Mr. Umekwe thought it was easy to see there were years in
which no wells were drilled, around 2007 and 2008, after
which there was a surge. He mentioned incentives for
exploration. He noted that lately there were more
stratigraphic wells drilled, which were a fraction of the
cost for full-blown exploration wells. The wells would help
with understanding the structure and stratigraphy in areas
of interest.
10:20:38 AM
Mr. Fitzpatrick turned to slide 9, "EXPLORATION &
DEVELOPMENT IN COOK INLET: COOK INLET FUTURE PRODUCTION,"
which showed two different graphs. The top graph
represented several gas reserves surveys that had been
conducted over a number of years. He observed that updates
to studies showed the total estimated production out of the
Cook Inlet basin over its expected life. The grey bars
represented the amount of gas produced to date. He noted
that there was fluctuation in the graphs as the studies
used different methodologies or different assumptions. The
blue bars at the top represented the estimated remaining
amount of gas reserves in Cook Inlet.
He observed that from the 2009 to 2018 studies there was
somewhere between 700 billion cubic feet to 1.1 trillion
cubic feet was the estimated remaining reserves and
expected to be produced out of existing fields, absent
reserves replacement due to further exploration activity.
Using information from the graph depicting demand, he
estimated that there was somewhere between 10 to 15 years
gas demand that was able to be supplied out of the Cook
Inlet Basin.
Mr. Fitzpatrick continued to address the slide. He
explained that the exploration activity contributed to the
total gas remaining reserves, which was part of the reason
for change over time over the total expected production
from the inlet in studies. He cited that starting in 2009,
studies showed 8.9 trillion cubic feet of gas expected to
be produced out of the basin, up to the most recent study
that showed 9.3 trillion cubic feet of gas. He explained
that DNR was going through the process of updating the
study with current market conditions and technology.
Co-Chair Stedman asked to advance to the next slide to
address exploration and development.
10:24:43 AM
Mr. Fitzpatrick addressed slide 10, "EXPLORATION &
DEVELOPMENT IN COOK INLET: COOK INLET UNDISCOVERED
RESOURCE":
? Undiscovered, Technically Recoverable
Oil & Gas (USGS, 2011):
? mean conventional oil 599 MMBO
? mean conventional gas 13.7 TCF
? mean unconventional gas 5.3 TCF
? Undiscovered, Technically Recoverable
Gas:
? 1.2 TCF additional mean resource assessed in
Southern Cook Inlet OCS (BOEM, 2011)
? In general, access to additional area provides
opportunities for locating and commercializing
currently undiscovered resources.
Mr. Fitzpatrick explained that the slide showed some
estimates of the remaining undiscovered or potential oil
and gas reserves in Cook Inlet. He reviewed the numbers on
the slide and noted that the Bureau of Energy Management
primarily looked at offshore gas reserves in federal
waters. He summarized that there was the potential for
additional gas exploration, development, and production
into the Southcentral market, based on resources the
studies indicated were yet undiscovered.
Co-Chair Stedman did not think "technically recoverable"
was necessarily the same as "financially recoverable. He
asked Mr. Fitzpatrick to comment.
Mr. Fitzpatrick agreed that "technically recoverable"
affirmed that the gas was recoverable using existing
technology, however the concept did not apply an economic
filter to the potential reserves. Although it was possible
to technically recover the resource, the cost might be more
than the current price of gas the Southcentral market would
be able to bear. He pondered that prices over time would be
expected to rise as gas was produced from smaller and more
difficult reservoirs that cost more to produce.
Mr. Fitzpatrick explained that it was not possible to
quantify the cost to produce undiscovered resources until
discovered and quantified with a plan of development. He
thought it was possible that there was an undiscovered
resource that was large and very cheap to produce, however
over time the likelihood was that the gas resources tended
to be in smaller or more difficult to produce reservoirs.
Co-Chair Stedman thanked the departments for presenting. He
intended to schedule time for the remainder of the
presentation.
Mr. Fitzpatrick relayed that the majority of the remaining
slides either dealt with the bill that the committee
removed from the agenda or were appendices.
Co-Chair Stedman avowed to be in communication on the
matter.
ADJOURNMENT
10:29:56 AM
The meeting was adjourned at 10:29 a.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 62 Sponsor Statement 1.28.2021.pdf |
SFIN 2/1/2022 1:00:00 PM SFIN 3/18/2022 9:00:00 AM SRES 3/10/2021 3:30:00 PM |
SB 62 |
| SB 62 SFIN DNR Gas Leases; Renewable Energy Grant 2.1.22.pdf |
SFIN 2/1/2022 1:00:00 PM SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Mouw.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Kachemak Bay Conservation Society.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Irwin.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Gill.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Christiansen.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 DNR 2022-02-17_SB62_SFIN Response to Questions.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Fletcher.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Olson.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Berg.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Sigman.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Friends of Kachemak Bay State Park.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Leutwyler.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| Cook Inlet Update SFIN_2022(draft)_2022.03.15 (002).pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 DNR 2022-03-18_Cook Inlet for SFIN.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Archibald.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition McCarthy.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Knight.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Lavrakas.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Fedora.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Brooks.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Perry.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Brann.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Whytal.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Handy.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Hillstrand.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposoition Hinnant.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposotion Schuster.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Pariyar.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Banks.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 Opposition Kachemak Bay Conservation Society letter and petition.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |
| SB 62 DOR Response to SFIN Cook Inlet Presentation 2022.04.12.pdf |
SFIN 3/18/2022 9:00:00 AM |
SB 62 |