Legislature(2015 - 2016)HOUSE FINANCE 519
03/31/2016 05:00 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE BILL NO. 247
"An Act relating to confidential information status
and public record status of information in the
possession of the Department of Revenue; relating to
interest applicable to delinquent tax; relating to
disclosure of oil and gas production tax credit
information; relating to refunds for the gas storage
facility tax credit, the liquefied natural gas storage
facility tax credit, and the qualified in-state oil
refinery infrastructure expenditures tax credit;
relating to the minimum tax for certain oil and gas
production; relating to the minimum tax calculation
for monthly installment payments of estimated tax;
relating to interest on monthly installment payments
of estimated tax; relating to limitations for the
application of tax credits; relating to oil and gas
production tax credits for certain losses and
expenditures; relating to limitations for
nontransferable oil and gas production tax credits
based on oil production and the alternative tax credit
for oil and gas exploration; relating to purchase of
tax credit certificates from the oil and gas tax
credit fund; relating to a minimum for gross value at
the point of production; relating to lease
expenditures and tax credits for municipal entities;
adding a definition for "qualified capital
expenditure"; adding a definition for "outstanding
liability to the state"; repealing oil and gas
exploration incentive credits; repealing the
limitation on the application of credits against tax
liability for lease expenditures incurred before
January 1, 2011; repealing provisions related to the
monthly installment payments for estimated tax for oil
and gas produced before January 1, 2014; repealing the
oil and gas production tax credit for qualified
capital expenditures and certain well expenditures;
repealing the calculation for certain lease
expenditures applicable before January 1, 2011; making
conforming amendments; and providing for an effective
date."
KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE,
asked if there were any questions on the fiscal note
section of the presentation.
Co-Chair Thompson informed the committee that Mr. Alper
would be available to visit each member's office to review
the presentation slides that were discussed in the 1:30pm
meeting.
5:11:06 PM
RANDALL HOFFBECK, COMMISSIONER, DEPARTMENT OF REVENUE,
introduced himself.
5:11:25 PM
Mr. Alper continued his presentation from the 1:30pm
meeting. He began with Slide 45:
Introduction to Scenario Analysis
· The Tax Division has developed a new model, looking
at project life cycles
· Cash flow over the 30-40 year life of a project, for
the state's production tax and credits, all state
revenue, the producer's cash flow, and discounted
(NPV)
· Scenarios Analyzed at $40, $60, $80, and Fall
Forecast oil price
· Status quo modeled vs. Governor's original bill
· Two full presentations on BASIS from previous
committee
Mr. Alper explained that when modeling credit and tax
changes in the past the tendency had been to look across
the North Slope as if it were one entity, which did not
capture the individuality of different projects. He
highlighted that the modeling reflected the life cycles of
specific projects. He said that House Resources Committee
had seen several presentations on the status quo model,
versus the Governor's Original bill, which were available
on BASIS.
5:12:55 PM
Mr. Alper turned to Slide 46:
Introduction to Scenario Analysis
Fields Analyzed:
North Slope Scenarios:
· 50 million barrel North Slope Oil
· 750 million barrel North Slope Oil (20% GVR)
Cook Inlet Scenarios
· 50 million barrel Cook Inlet Oil (with and
without tax caps)
Supplemental Scenarios
· 750 million barrel North Slope Oil (30% GVR)
· 750 million barrel North Slope Oil (50%
Private Royalty)
· 670 bcf Cook Inlet Gas
· 670 bcf Middle Earth Gas
Mr. Alper explained that the 50 million barrel North Slope
oil was analogous to the smaller, newer projects that had
developed 10 years ago at Oooguruk, Nikaitchuq, and
projects by Brooks Range Petroleum; the economics of the
smaller fields that existed among the bigger, older fields
in the North Slope. He relayed that the 750 million barrel
North Slope Oil economics were equivalent to projects by
Armstrong or Repsol. He said that for Cook Inlet, the
smaller oil field economics applied, as no one expected to
find large fields in that area. He highlighted that the
numbers had not been based on anyone's individual
economics, but on stylized projects, and the department had
examined what was perceived to be the typical and expected
economics of projects in those areas of the state. He
explained the supplemental scenarios. He relayed that under
SB 21, the GVR was a 20 percent tax reduction was standard,
but if the field in question was a very high royalty field,
with leases greater than 12.5 percent, the company would
receive a 30 percent GVR. He noted that there were
documents in committee packets that explained how royalty
sharing worked in different areas of the state. He said
that the state received the production tax anywhere in
Alaska; the royalty that was collected was very specific to
the state being the landowner. He said that the state had
been fortunate that past geologists had been thoughtful
enough to select the Central North Slope at statehood
securing Prudhoe Bay on state land. He noted thatHe said
that the royalties that the state collected were specific
He added that royalty sharing arrangements with the federal
government varied around the different areas of the state.
He revealed that the department had done a modeling run in
order to forecast what would happen if the North Slope
field were half state, and half private royalty. He
explained that the state did not receive private royalties;
for example, if there was an oil development on Native
Corporation land, they did not have any obligation to share
their royalties with the state. He said that the state did
have a tax on the royalty, which was 5 percent of their
gross royalty. He relayed that at 12.5 percent royalty the
state received the equivalent of six-tenths of 1 percent of
tax on the royalty. He furthered that if the royalty was
12.5 percent, whatever the royalty dollar was, the state
would collect a 5 percent tax on the royalty dollar;
effectively, the state's revenue would be 5 percent of the
12.5, slightly over six-tenths of 1 percent. He said that
gas fields in Cook Inlet and in Middle Earth had also been
modeled.
Mr. Alper turned to Slide 47, "Sample of Scenario Analysis:
North Slope- 50 mmbo Status Quo, $60/bbl." He said that the
slide reflected the status quo analysis of a North Slope
small oil field. He pointed to the slide on the upper left,
which charted the production tax cash flow. He relayed that
there had been 5 to 6 years of development of construction,
and as companies spent money they were eligible for tax
credits from the state. He stated that under the model the
North Slope was getting a 35 percent operating loss credit;
if the company was spending $125 million per year to
develop their field, they would earn a 35 percent operating
loss credit. He said that years of production were
represented in blue bars.
Mr. Alper spoke to the upper right hand bar graph, which
charted annual state net gains and losses at 20 percent GVR
at the $60 and price. The chart on the upper right
reflected the annual state net gains and losses at 20
percent GVR at the $60 ANS price. The green bars
represented the production tax, the blue bars represented
the royalties, the red bars represented property tax, and
the purple bars represented state corporate income tax. He
said that the lower left hand graph illustrated the total
producer cash flows at 20 percent GRV at the $60 ANS price.
The box in the lower right hand corner summarized the three
data sets on the slide:
Life Cycle Totals $Millions
Production Tax Credits Cashed 162
Production Tax Paid 183
Net Production Tax 21
Production Tax NPV 6.15% -37
Total Annual State Losses 121
Total Annual State Gains 501
Net State Gain (Loss) 380
State NPV 6.15% 136
Total Producer Cash Out 327
Total Producer Cash In 731
Net Producer Cash Flow 404
Producer Cash NPV 6.15% 112
Mr. Alper said that scenarios had been run using $40/bbl
and that all resulted in lost money, which led the
administration to believe that no one would sanction a
substantial project in the state at $40/bbl. He noted that
at $60/bbl the state would break even, and things looked
more robust at $80/bbl.
5:22:05 PM
Co-Chair Thompson queried the most efficient way that the
committee could ask questions about the scenario slides.
Mr. Alper responded that the slide came in pairs: before HB
247, and after HB 247, and that now would be a good time
for questions.
Vice-Chair Saddler asked about the timeline of the
scenarios.
Mr. Alper responded that the timeline began when the
company started spending money on the project. He said that
the upper left box was unique to just the production tax
system, both taxes and credits, and did not capture the
lease bonus payment.
5:23:37 PM
Representative Gara spoke to the calculation of the gross
revenue exclusion for the bigger fields, and the gross
value reduction for the smaller fields. He asked whether a
gross value reduction field was represented in the top left
hand corner.
Mr. Alper answered that it was a gross reduction field. He
furthered that the assumption in all of the modeling was
that if it was a new field on the North Slope, where the
GVR was the law of the land, it would qualify for the GVR
because it was designed to benefit new fields.
5:24:30 PM
Representative Gara noted that he had a report from the
department that said that for production taxes on GVR
fields (post 2002) the state did not receive a production
tax until approximately $73/bbl. He wondered why the slides
reflected production tax revenue at $60/bbl.
Mr. Alper replied that he would get back to the committee
with the information. He noted that the numbers were not
particularly large for an entire oil field over the course
of a year, but that they were positive numbers. He
suggested that Mr. Stickle could further explain the
numbers.
5:26:14 PM
DAN STICKLE, CHIEF ECONOMIST, DEPARTMENT OF REVENUE,
explained that the analysis that had been previously
provided to the committee had looked at all GVR eligible
fields on the North Slope in the aggregate. He said that
the fields included a mix of companies that were operating,
as well as investing in capital expenditures. He stated
that the slide reflected a development scenario where most
of the capital expenditures took place up front, followed
by a period of time of spending only operating
expenditures. He relayed that the structure of the spending
profile brought the break-even down from the mid-70s level.
Representative Gara remained confused.
Mr. Alper offered to rephrase the response. He explained
that the field in the scenario was specific to a field
where the spending was "front loaded". He said it the
capital spending in the oil field was spread evenly over 30
years, there would be capital spending in 2010-13, which
would be enough to offset the tax and drive it down to
zero. He stated that when doing an aggregate analysis of
many different fields, in different stages of their life
cycle, one groups capital spending would always offset
another groups taxes. The slide did not reflect any capital
offsetting of the earnings for the later years, so taxes
were paid at a lower oil price.
Representative Gara understood that averaging out the early
spending and the later revenues would show negative returns
for the state in the beginning and positive returns later,
and a zero production tax over the life of the field.
Mr. Alper responded that the analysis included multiple
fields at multiple stages in their life cycles. He added
that some of the fields had a lot of capital spending that
when taken all together would offset the taxes from those
that were paying taxes.
5:29:43 PM
Mr. Alper scrolled to Slide 48. He stated that Slides 47
and 48 were the same exact field, but Slide 48 included the
changes that had been in the original version of HB 247. He
said that the most substantial change to the economics of
the projects was the per company cap of $25 million. He
pointed to the chart in the upper left, which showed that
the production tax credits cashed/payments did not go below
$25 million but they could be applied for more years. He
spoke to the chart in the lower right, which offered the
life cycle totals in millions:
Life Cycle Totals $Millions
Production Tax Credits Cashed 101
Production Tax Paid 155
Net Production Tax 54
Production Tax NPV 6.15% -10
Total Annual State Losses 59
Total Annual State Gains 470
Net State Gain (Loss) 412
State NPV 6.15% 163
Total Producer Cash Out 362
Total Producer Cash In 746
Net Producer Cash Flow 384
Producer Cash NPV 6.15% 93
Co-Chair Thompson requested that members to hold their
questions until the end of the presentation.
Mr. Alper turned to Slide 49, which reflected a sample
scenario of North Slope oil at 750 mmbo, under HB 247, and
Co-Chair Thompson $80/bbl. He said that the scenario on the
slide was analogous with the Armstrong field, and peaked at
roughly 120,000 barrels per day. He said that $80 oil had
been used because that was the price point needed to secure
the investment. He shared that spending by investors on a
new oil field was viewed in terms of capital expenditures
per dollar, per barrel of oil that would be produced. For
example, if the field was going to produce 750 million
barrels, at approximately $13 of capital expenditure per
barrel; the result was $10 billion worth of capital
spending on the North Slope to produce the field. He felt
that it was important that the committee understood the
state's commitment to investors under the status quo law.
He relayed that once spending was made in the range of $1
billion, or more, per year, the state would be spending
many hundreds of millions of dollars in refundable tax
credits. He said that was simply the way things worked
under the 35 percent operating loss credit. He pointed out
to the committee that the red bars in the upper left hand
graph reached over $800 million in peak years of
construction on the project. He indicated the slide on the
upper right of the slide, and relayed that once production
was underway, the state would receive over $1 billion, per
year, in revenue. He insisted that $80/bbl oil was
necessary for the state to get their $1 billion per year,
and that he held out hope that the price of oil would
bounce back. He added that the slide reflected a 40 year
time cycle, which meant that the time line would require
patience. He spoke to the box on the lower right, which
listed the life cycle totals related to the scenario on the
slide:
Life Cycle Totals $Millions
Production Tax Credits Cashed 2,830
Production Tax Paid 8,923
Net Production Tax 6,093
Production Tax NPV 6.15% 869
Total Annual State Losses 2,553
Total Annual State Gains 16,623
Net State Gain (Loss) 14,069
State NPV 6.15% 3,527
Total Producer Cash Out 5,247
Total Producer Cash In 17,933
Net Producer Cash Flow 12,686
Producer Cash NPV 6.15% 2,216
Mr. Alper turned to Slide 51, which incorporated into the
scenario the changes proposed by the legislation. He
revealed that the numbers indicated that the $25 million
cap on spending would greatly reduce the state's cash
outlay, and there would be a significant level of carry
forward credit. He said that once production began, the
built up, carry forward credits would cancel out production
taxes and would eventually result in the loss of operating
loss credits for companies. He highlighted that the total
production tax credits cashed would drop from $2.8 billion,
to $109 million, and the state's production tax discounted
cash flow would be double what it was under the scenario on
Slide 50. He pointed to the box on the lower right of the
slide, which reflected life cycle totals under the
scenario:
Life Cycle Totals $Millions
Production Tax Credits Cashed 109
Production Tax Paid 6,533
Net Production Tax 6,424
Production Tax NPV 6.15% 1,743
Total Annual State Losses 100
Total Annual State Gains 14,479
Net State Gain (Loss) 14,379
State NPV 6.15% 4,388
Total Producer Cash Out 7,832
Total Producer Cash In 20,317
Net Producer Cash Flow 12,485
Producer Cash NPV 6.15% 1,415
Mr. Alper admitted that the scenario was slightly
overstated; no single company was going to come to Alaska
and spend $10 billion. He furthered that any company
interested in a project of that size would seek out several
partners. He said that if 4 partners were to develop the
project, using the Governor's bill as the underlying
system, it would result in $100 million in credits per
year. He disclosed that the state had learned that the $25
million cap could work for smaller fields, but it would
need to be altered in order to accommodate larger fields.
5:37:49 PM
Mr. Alper continued to Slide 51, which offered a summary of
the North Slope scenarios. He said that field size and tax
regime numbers, the first two columns, had been modeled in
the scenarios on the previous slides. He reiterated the
numbers as they related to the taxes at $40, $60, and
$80/bbl oil, under both the status quo and HB 247, with the
varying field sizes. He relayed that the House Resources
Committee had heard the slide presentation in February
2016. He turned to Slide 52, which reflected the same
variables using the Cook Inlet scenarios. He opined that
the problem with Cook Inlet was that there would be an
impending moment in 2022, when the statutory zero taxes
went away, and a fork in the road was created. He said that
two different options were created: option A would have the
tax caps sunset and revert to the base tax of 35 percent,
with no per barrel credit or GVR; the alternate was that
the caps did not sunset and the future legislature chose to
maintain a zero tax in Cook Inlet. He said that the answer
would lie somewhere between the two scenarios. He continued
to the supplemental North Slope Scenario and the
Supplemental Cook Inlet and Middle Earth Scenarios on
Slides 53 and 54.
Co-Chair Thompson asked that the Department of Revenue
remain in the room until after the Department of Natural
Resources completed their presentation.
5:44:27 PM
PAUL DECKER, PETROLEUM GEOLOGIST, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, introduced the PowerPoint
Presentation: "Alaska's Oil and Gas Industry; Overview &
Activity Update." He turned to Slide 2, "Overview":
North Slope:
· Resources and Reserves
· Current Activity & New Developments
· Who's Working the North Slope?
· Leasing Activity
Cook Inlet:
· Resources and Reserves
· Current Activity & New Developments
· Who's Working the Cook Inlet?
· Leasing Activity
Frontier Basins:
· Resources and Reserves
· Current Activity & New Development
· Who's Working the Frontier Basins?
· Exploration Licensing & Lease Conversion
5:46:17 PM
Mr. Decker turned to Slide 3, "North Slope Resources
Overview." The slide provided an overview map of the North
Slope. He noted that the area shown on the map was
approximately 500 miles from west to east. He said that the
3 miles into the Chukchi and Beaufort Seas were federal
Outer Continental Shelf (OCS) and were managed by the
Bureau of Ocean Energy Management (BOEM). He pointed out
that the green areas to the south were permanently
protected federal land. He furthered that the National
Petroleum Reserve-Alaska (NPRA) was also federally owned
and run by the Bureau of Land Management (BLM). He said
that the Alaska National Wildlife Refuge (ANWR) 1002 was
not permanently protected, but could be by an act of
Congress.
5:47:30 PM
Representative Guttenberg pointed out that the OCS was
further than 3 miles out.
Mr. Decker agreed that the shelf extended much farther than
3 miles. He clarified that the state's ownership only
extended from the shoreline to 3 miles out. He returned to
the map on the slide. He spoke the central North Slope
state lands; the state's 3 area wide lease sales were
outlined in red on the slide. He said that there was a lot
of private ownership within the foothills. He stated that
the main oil fields were shown in green and were strung
along the shoreline of the Central North Slope. He added
that there were a number or oil and gas fields along the
coastline, mostly gas fields near the foothills. He spoke
to the black dots, which represented all of the exploration
wells that had been drilled, to date, on the slope. He
believed that the map showed a lot of room for growth in
the area of exploration.
5:49:54 PM
Representative Pruitt understood that the dark green area
on the map included oil accumulations that were known to
exist, but had not been produced.
Mr. Decker responded that there were several non-producing
fields contained within the dark green area, most notably
Hammerhead and Kuvlum in the eastern Beaufort Sea.
Representative Pruitt understood that the dark green areas
of the map were expected to increase.
Mr. Decker replied that if the projects became sanctioned
and went into development, the dark green area would be
expanded.
Representative Pruitt asked whether there were other areas
that held resources that were not in dark green on the map.
Mr. Decker responded that there were very few such
examples. He reiterated that the intent of the map was to
show land that had been "discovered by the drill bit".
Mr. Decker turned to Slide 4: "Arctic Alaska Oil & Gas
Resources." The slide offered a table of what the federal
government would estimate for undiscovered, technically
recoverable conventional resources in Arctic Alaska. He
said that the slide was not meant to indicate that all of
the volumes would be commercially recoverable, but rather,
would the volumes exist in accumulations that could be
recoverable given the technology in current practice. He
pointed out to the committee that the slide showed 40
billion barrels of oil, and 207 billion cubic feet of gas.
He furthered that the gas was equally distributed between
OCS waters and onshore state lands and waters. The mean oil
estimate reflected that there was more oil in the offshore
than in the onshore.
5:53:25 PM
Mr. Decker continued to Slide 5, "Arctic Alaska Oil & Gas
Resources":
Gas Reserves:
· Approximately 30 trillion cubic feet of
associated gas is estimated to be recoverable
from producing or developing North Slope fields,
mostly at Prudhoe Bay & Point Thomson. Without a
pipeline, most of that gas is best described as
contingent resource, not reserves.
· Approximately 5.9 trillion cubic feet of proved
associated gas reserves estimated in Alaska,
virtually all on North Slope (Energy Information
Administration(EIA),2014)
Oil Reserves:
· Approximately 2.8 BBO of proved oil reserves
estimated on the North Slope (EIA, 2014)
Mr. Decker stated that tis subset of gas would be used for
making natural gas liquids that could be sold to the Trans-
Alaska Pipeline System (TAPS), and minor gas sales thorough
local markets.
5:55:00 PM
Mr. Decker discussed Slide 6, "North Slope Current Activity
and New Developments":
· Accumulate Energy
· Franklin Bluffs area shale play evaluation
· Drilled Icewine #1 well in October-December
2015
· Seismic survey of lease area this winter
· AEX (ASRC)
· Placer Unit
· Currently drilling Placer #3 well -spud in
late January 2016
· BP
· Prudhoe Bay Unit
· Completed 8 new wells, 46 new sidetracks,
~420 well workovers in Initial Participating
Area (IPA), 2015
· Completed first wells in Lisburne PA in 9
years, 2015
· Completed 3D seismic program in North
Prudhoe, 2015
5:56:51 PM
Mr. Decker advanced to Slide 7, "North Slope Current
Activity & New Developments":
· Caelus Natural Resources
· Oooguruk Unit
· On-going development (4-5 wells/year; all
long-reach & frac'd)
· Nuna
· First production from Nuna Torok Phase 1 in
late 2018(?)
· No construction activity this winter
· Smith Bay Exploration (shallow water ice pad)
· Second of two exploration wells nearly
complete
· Conoco Phillips
· Colville River Unit
· Initiated first production at CD5 in 2015
· Plan for a total of 8 new wells in 2016
· Greater Mooses Tooth Unit (Federal/NPRA)
· Approved funding for $900MM GMT1 project
· Plan to drill two Tinmiaq exploration wells
in western part of unit
Mr. Decker elaborated that PA meant participating area; the
subset of the leases within a unit that were actively
contributing to production. He added that MI stood for
miscible injection, a method used for enhanced oil recovery
purposes. He said that Caelus had slowed the development of
the Nuna project due to the slump in oil prices.
He went on to explain Conoco Phillips' activity on slide 8,
"North Slope Current Activity and New Developments":
· Conoco Phillips
· Kuparuk River Unit
· First wells came online at Kuparuk DS-2S in
2015
· Significant drilling planned in 2016 for
Kuparuk PA, Tarn PA and West SakPA during
2015-16
· ExxonMobil
· Point Thomson Unit
· Completion of Initial Production System in
2016
· Completed 22 mile liquid hydrocarbon
pipeline from Point Thomson to Badami Field,
which connects to TAPS
· Start-up expected by mid-May 2016 (10,000
bpd condensate)
· Great Bear Petroleum
· Currently acquiring large 3D seismic dataset
(~450 sq miles)
· Planning for additional work at Alkaid #1 in
2017
6:01:43 PM
Mr. Decker discussed Slide 9, "North Slope Current Activity
and New Developments":
· Hilcorp
· Northstar Unit
· Returned 2 wells to production
· Milne Point Unit
· Drilled 3 new wells, started new G&I plant
construction in 2015
· Plan to drill 10 new wells and complete 16
workovers in 2016
· Repsol/Armstrong
· Pikka Unit (Nanushuk Project Development)
· Drilled 3 exploration wells & sidetracked 1
in 2015 (total of 12 wells & sidetracks
since 2012)
· Commenced the project EIS under NEPA in June
2015
· Plan to drill 1 additional exploration well
in 2017
6:03:12 PM
Mr. Decker turned to Slide 10, "North Slope Wells Drilled
and Seismic Acquired":
· New Exploration and Development Wells Drilled 2004-
2014
· 110 Exploratory Wells and Well Branches
· 1,646 Development & Service Wells and Well
Branches
· 2D & 3D Seismic Data Acquired (Tax Credit Data) 2004-
2014
· Line Miles 2D (onshore/shorezoneice)~ 870
· Square Miles 3D (onshore/shorezoneice)~ 9,945
Mr. Decker categorized the activity on the North Slope as
steady over the past decade.
6:04:20 PM
Mr. Decker advanced to Slide 11, "Who's Working North
Slope?":
Large Majors (>$40B Market Cap):
· BP Exploration, Inc.
· Chevron USA, Inc.
· ConocoPhillips Alaska
· Eni
· Exxon Mobil Corporation
· Shell Offshore, Inc.
Large Independents & Mid-Sized Companies:
· Armstrong Oil and Gas/70 & 148 LLC
· Anadarko E&P Onshore LLC
· BG Alaska E&P Inc.
· Caelus Natural Resources Alaska LLC
· Halliburton Energy Services
· Hilcorp Alaska, LLC
· Repsol
Mr. Decker relayed that there were three categories of
companies working on the North Slope: large majors, large
independents & mid-sized companies, and small independents.
6:05:35 PM
Mr. Alper advanced to Slide 12, which listed the small
independent companies on the slope:
· Small Independents:
· Accumulate Energy Alaska, Inc.
· Alaska, LLC
· Alaskan Crude Corp.
· ASRC Exploration LLC
· Aubris Resources, LP
· AVCG, LLC
· Brooks Range Development Corporation
· Burgundy Xploration LLC
· Caracol Petroleum LLC
· Chap-KDL, Ltd.
· Colt Alaska LLC
· Dewline Petroleum LLC
· Donkel Oil & Gas, LLC
· Eastland Property and Minerals
· GMT Exploration Company LLC
· Great Bear Petroleum Ventures
· MEP Alaska, LLC
· Mustang Operations Center 1, LLC
· NordAq Energy Inc.
· Pacific Lighting Gas Development
· Petro-Hunt, LLC
· Pinta Real Development, LLC
· Petro-Hunt, LLC
· Pinta Real Development, LLC
· Ramshorn Investments, Inc.
· Red Technology Alliance, LLC
· Renaissance Umiat, LLC
· Royale Energy, Inc.
· Samson Offshore, LLC
· Savant Alaska, LLC
· Sunlite International Inc.
· The Eastland Oil Company
· TP North Slope Development, LLC
· Transworld Oil & Gas Ltd.
· Ultrastar Exploration LLC
· URSA Major Holdings LLC
· Woodbine Petroleum, Inc.
· Woodstone Resources, LLC
Mr. Decker explained that 7 or 8 of the companies listed on
the slide were actively exploring on the slope, but most
were lease holders waiting for activity to occur and were
not leading in the exploration of their leases.
6:05:58 PM
Representative Gara pointed out that there were companies
listed, but not listed as having any activity.
Mr. Decker replied that the activity slides were not
entirely comprehensive. He admitted that the slide did not
reflect Eni's continuing development at Nikaitchuq. He said
that they were actively expanding in the area, doing
"prudent operator" work.
6:06:43 PM
Mr. Decker turned to Slides 13, 14, and 15, "North Slope
Leasing Activity Trends." Each slide contained a bar graph
that illustrated the number of tracts that had received
either single or multiple bids on area wide lease sales in
the North Slope, Beaufort Sea, and Foothills areas. He said
that the area were held open for area wide leasing and that
everything that was open came up for lease every year. He
referred to Slide 13, which pertained to the North Slope.
He pointed out to the committee that there had been
aggressive leasing activity in 2014; Caelus had put in over
100 bids for leases along the Barrow Arch, and Armstrong
had purchased approximately 100 leases in the same lease
sale.
6:08:14 PM
Representative Wilson whether the companied were required
to act on the leases in a certain amount of time, or could
they bide their time while paying a fee to retain the
leases.
Mr. Decker stated that some of the leases that had been
issued had been accompanied by certain work commitments.
Generally, the lease hold in Alaska required an annual
rental fee that escalated considerably after several years,
which worked as an incentive to either develop or drop the
leases in a timely manner.
6:09:19 PM
Mr. Decker moved to Slide 14. He noted that 2006 had been a
big year for leasing in the area, and in 2011.
Mr. Decker spoke to Slide 15. He noted that in 2001 and
2002, there had been a burst of activity that coincided
with interest in natural gas potential in the area. He
noted the next burst in 2006, but felt that since then
investors had decided to wait until further progress was
made on the gasline. He informed the committee that the
area was gas prone, and not oil prone, and that its
fortunes would be linked to a gasline.
6:11:25 PM
Mr. Decker pointed to Slide 16, "Cook Inlet Resource &
Reserves Overview." The slide pictured a map showing where
the U.S. Geological Survey had assess the resources. He
said that the federal estimates were the undiscovered,
technically recoverable resource of oil and gas:
· Undiscovered, Technically Recoverable Oil and Gas
(USGS, 2011):
· mean conventional oil 599 MMBO
· mean conventional gas 13.7 TCF
· mean unconventional gas 5.3 TCF
· Natural Gas Reserves (ADNR, 2015)
1.18 TCF (Proved and Probable)
· 1.2 TCF additional mean resource assessed in OCS
waters (BOEM, 2011)
Mr. Decker elaborated on the unconventional gas areas.
6:13:08 PM
Representative Pruitt asked how much gas the state was
expected to produce in the future in Cook Inlet. He also
queried how much gas had been produced out of Cook Inlet
over the past 40 years.
Mr. Decker believed that approximately 8 TCF had been
produced in Cook Inlet to-date. He said that the 1.18 TCF
remaining proved and probably reserve was a significant
fraction of the available gas. He added that the number had
not dropped, and was higher than previous estimates from
2010. He said that with activity, exploration, and
aggressive development companies had been able to book
additional reserves. He was encouraged that there was still
a significant lifespan of resource, but that it would
depend on the rate of investment in getting it out of the
ground.
Mr. Decker addressed Slide 17, "Cook Inlet Current Activity
& New Developments":
Apache Alaska Corporation:
· Ceasing all seismic acquisition and other
exploration activity in Alaska
· Intend to hold leases until expiration
Conoco Phillips:
· Recent sale of interest in Beluga River Unit
Furie Operating Alaska
· Kitchen Lights Unit:
· Set monopod platform in 2015;
· Completed onshore gas facilities & pipeline
in 2015
· Commenced production in December 2015
· Randolf Yost, 2ndjack-up rig, arrived in
Homer early March, plan to drill two
development wells in 2016
BlueCrest Energy, Inc.
· Cosmo Unit:
· Planned arrival of new land-based drill rig
for oil development in 2016
· Plan 1st oil in mid-2016 (oil production
will be from onshore)
· Possible offshore drilling for gas (Spartan
151 jack-up rig) in 2016
Mr. Decker stated that Apache Alaska Corporation had hoped
to develop prospects to be drilled in the next few years,
but were ceasing exploration activity in the state due to
low oil prices. He said that a skeleton crew would remain
in Anchorage offices in order to maintain their assets. He
said that Conoco Phillips had been slowly exiting the basin
gradually. They had sold their share of the interest in the
Beluga River Unit to Chugach Electric and the Anchorage
Municipal Light and Power (ML&P), increasing ML&Ps share
making them the dominant owner. He furthered that Furie was
currently selling gas to Homer Electric and had plans to
drill more wells within the coming year.
6:18:05 PM
Representative Wilson asked whether companies were relying
on tax credits when securing financing for exploration and
whether the department knew when the credits switched from
exploration to development credits.
Mr. Decker replied that there were different types of tax
credits. He said that in Cook Inlet most of the credits
that had been used had applied to both exploration and
development; the 023(l) well lease expenditure credits. He
added that many companies were dependent on receiving
timely reimbursements from credits in order to use that
money in the next phase of exploration or development.
Representative Wilson assumed that companies filed plans
with DNR before beginning their process. She asked whether
part of the plan covered financing, or if finance
discussion were limited to DOR.
Mr. Decker answered that the main plans that were submitted
to the state had to do with obtaining permits to use the
land, or in a unitized area the Division of Oil and Gas
would be tasked with overseeing a plan of development. He
said that DOR would had additional insight into the
financial aspects.
6:20:35 PM
Mr. Decker moved to Slide 18, "Cook Inlet Current Activity
& New Developments":
Hilcorp Alaska, LLC:
· Cannery Loop Unit:
· Completed 2 new wells in 2015
· Planned 2 workovers in 2016
· Deep Creek Unit:
· Drilled 1 new well in 2015 and 2nd is
planned for 2016
· Ninilchik Unit:
· Completed 3 new gas wells in 2015 and 7 new
gas wells in 2014
· Trading Bay Unit:
· 19 workover jobs in 2015 and 3 new wells in
2016
· Purchased XTO Energy, Inc. assets in southern
Cook Inlet
· Projected ~$120 MM investment in Cook Inlet in
2016
Mr. Decker said that Hilcorp Alaska was the dominant
operator in the Cook Inlet basin. He stated that there
would not be as much progress witnessed in the Cannery Loop
Unit had a less assertive and ambitious producer taken over
the fields when they came up for sale. He said that Hilcorp
projected spend for 2016 was $120 million.
Mr. Decker advanced to Slide 19, "Cook Inlet Wells Drilled
& Seismic Acquired":
New Exploration & Development Wells Drilled 2010-2014
· 24 Exploratory Wells and Well Branches
· 65 Development & Service Wells and Well Branches
2D & 3D Seismic Data Acquired (Tax Credit Data) 2004-
2014
· Line Miles 2D (onshore/offshore) ~ 725
· Square Miles 3D (onshore/offshore) ~ 660
Mr. Decker noted that the time window used on the slide had
been used because that was a time when the basin had been
perceived to be in crisis.
Mr. Decker scrolled to Slide 20, "Who's Working Cook
Inlet":
· Large Majors (>$40B Market Cap):
o ConocoPhillips Alaska
· Mid-Sized Independents:
o Hilcorp Alaska, LLC
o Apache Alaska Corp.
· Small Independents & LLCs:
o Alaska Energy Alliance Inc.
o AIX Energy LLC
o Alaska LLC
o Aurora Gas LLC
o Aurora Exploration LLC
o BlueCrest Energy Inc.
o CIRI Production Company
o Cook Inlet Energy LLC
o Cornucopia Oil & Gas Company LLC
o Corsair Oil & Gas Company LLC
o Furie Operating Alaska LLC
o New Alaska Energy LLC
o NordAq Energy LLC
o Taylor Minerals LLC
o Woodstone Resources LLC
Mr. Decker relayed that Hilcorp would remain active, but
that Apache would not. He reiterated that some of the small
independents were actively exploring, but most were holding
their lease positions and waiting to see what happened with
the price of oil. He turned to Slide 22, which contained a
bar graph of Cook Inlet area wide lease sale results, 1999
through 2015. The slide reflected 2011 as the biggest year,
since then participation had declined.
6:24:39 PM
Mr. Decker turned to Slide 23: "Frontier Basins Tax Credit
Areas." He relayed that the basins were sometimes referred
to as "Middle Earth". He said that the terms could be
confused and were not always interchangeable. He detailed
that the map showed the 5 regions in which the Frontier
Basin Tax Credit [43.55.025(a)(6-7)], a form of super-
credit for seismic and well drilling, could be claimed.
Under current statute the credits would sunset in 2016.
6:26:12 PM
Mr. Decker turned to Slide 24, "Statewide Resource
Assessments -Undiscovered, Technically recoverable
resource."
Region Mean Oil Estimate Mean Gas Estimate
(Million Barrels) (Billion Cubic Feet)
Onshore Arctic 15,908 98,960
Offshore Arctic 23,750 108,180
Interior Basins* 234 5,641
(only partially
assessed)
Upper Cook Inlet 599 19,037
Other Southern Alaska** 2,859 23,458
TOTAL 43 BBO 255 TCF
*Includes Yukon Flats and Kandik basins (Nenana,
Kotzebue, Copper River, Holitna, & Susitna basins not
assessed)
**Mainly federal OCS waters, minor AK Peninsula
onshore
6:27:12 PM
Mr. Decker scrolled to Slide 25, "Exploration License
Program":
· The program supplements the state's oil and gas
leasing efforts & encourages exploration outside of
known oil & gas provinces
· Every April, DNR accepts proposals to conduct
exploratory activity outside existing leasing areas
· The DNR Commissioner may issue a notice requesting
proposals to explore a designated area (encourages
competition)
· The applicant has up to 90 days to submit their
proposal
· Three exploration licenses have been converted to
lease: Susitna II, Copper River, & Nenana
6:28:17 PM
Mr. Decker advanced to Slide 26: "Who's Working The
Frontier Basins?":
Ahtna
· Copper River Basin, Tolsona Exploration License:
· Reprocessed 2D seismic data & acquired new
Tolsona 2D seismic in spring 2014
· Plan to drill Tolsona #1 gas exploration
well in early 2016; follow up to the Ahtna
#1-19 well drilled in 2007-2009 (Rutter &
Wilbanks)
Doyon
· Nenana Basin:
· Drilled Nunivak #1 and #2 exploratory wells,
2009-2013
· Acquired 2D and 3D seismic, gravity,
magnetics, and lakebed geochemical surveys,
2005 -2014
· Converted exploration license to leases
between 2013 & 2014
· Additional 2D seismic in progress
· Plan to spud Toghotthele #1 this June
Mr. Decker continued to Slide 27, "Who's Working The
Frontier Basins?":
Doyon
· Yukon Flats Basin:
· Acquired 2D seismic, gravity, magnetics, and
lakebed geochemical surveys
NANA
· Kotzebue Basin:
· Evaluating and marketing prospects based on
legacy industry seismic
Usibelli Coal Mine Inc.
· Healy Basin Gas-Only Exploration License:
· Drilled one shallow exploration well in 2014
Mr. Decker stated that Doyon had not drilled any wells, but
had conducted geophysical and geochemical surveys. Doyon
owned much of the land, which meant that there would be no
expiration license in the Yukon Flats.
6:30:28 PM
Mr. Decker moved on to Slide 28: "Frontier Basins Wells
Drilled & Seismic Acquired":
New Exploration Wells Drilled 2004-2014
· 7 Exploratory Wells and Well Branches
2D & 3D Seismic Data Acquired (Tax Credit Data) 2004-
2014
· Line Miles 2D (onshore)~ 1,220
· Square Miles 3D (onshore)~ 340
Mr. Decker believed that 3 of the 7 exploratory wells had
been in the Nenana Basin, 3 in the Copper River Basin, and
1 in Healy.
6:31:13 PM
Mr. Decker reviewed Slide 29, "Frontier Basin Exploration
Licenses", which listed the 5 locations for each license
and the details of: ADL file number, acres, commitment,
effective date, term, and status. He revealed that Cook
Inlet Energy had relinquished their Susitna 5 license due
to bankruptcy.
6:32:38 PM
CORRI FEIGE, DIRECTOR, DIVISION OF OIL AND GAS, DEPARTMENT
OF NATURAL RESOURCES (via teleconference), pointed out that
the slides that showed the smaller companies working in
Cook Inlet and on the North Slope had business models that
differed greatly from the models of the lager and major
companies. She noted that on the North Slope, several small
companies at a time could join together on a single
project. She said that companies often bundled together in
groups in order to spread the investment and raise the
capital necessary to undertake the project.
6:34:32 PM
AT EASE
6:42:28 PM
RECONVENED
Co-Chair Thompson indicated that Mr. Alper and Commissioner
Hoffbeck were available for questions.
Mr. Alper stated that the remainder of the slides had to do
with implementation of the legislation. He turned to Slide
56, "Implementation: Transition":
· Original bill was written with an effective date of
7/1/16 for nearly all changes
· CS moves most changes to 1/1/17, with the full
repeal of the Well Lease Expenditure credit on
1/1/18
· The bill's original fiscal note included a fund
capitalization for $926,575.0 to the .028 fund.
· This is the difference between what is in the
operating budget and $1 billion.
· This would have covered all expected credit
liability before the effective date.
· With the changes made in the CS, additional
appropriation will be needed
6:45:35 PM
Mr. Alper discussed Slide 57: "Implementation: Connection
to Fiscal Plan":
· HB247 was introduced as one of 10 bills that
comprised the governor's fiscal plan.
· All the bills taken together, with anticipated
budget cuts, proposed a balanced budget by FY19
· The broader fiscal package, and the specific tax
credit bill, are intended to add certainty to
industry regarding what support the state can
provide and how we're going to continue to pay for
government
· Original bill also assumed companion "AIDEA Loan"
bill to help with projects that lost funding with
credit changes
· HB246 would create a new "fourth fund" at AIDEA to
concentrate on oil and gas development loans, for
proven reserves
· Envisioned $200 million initial fund capitalization
Mr. Alper relayed that in the first committees of referral
for the initial hearings on all of the governor's bills the
administration had worked to put the bills in context of
each other. HB 247 was one of 10 bills that comprised the
governor's overall fiscal plan: the Permanent Fund
Protection Act (SB 128), the income tax bill(SB 134/HB
250), the AIDEA loan bill(SB 129/HB 246), the three
consumption tax bills - alcohol, tobacco, and motor fuel(SB
131/HB 248; SB 133/HB 248; SB 132/HB 249, and the three
business tax bills - mining, fisheries, and the cruise ship
head tax(SB 137/HB 253; SB 135/HB 251; SB 136/HB 252). He
solicited questions from committee members.
6:48:25 PM
Vice-Chair Saddler queried the required criteria for loans
from the AIDEA development fund.
Mr. Alper responded that the loan would be for up to 50
percent of a projects value. He said that there would need
to be a proven reserve and a resource evaluation obtained
by AIDEA from an external consulting service that would
prove the legitimacy of the project. He added that the cost
of the services would be rolled into the loan and would be
paid back. He deferred further explanation to an AIDEA
representative.
Co-Chair Thompson understood that a proven reserve needed
to exist in an effort to move toward development and
production.
Mr. Alper explained that to the extent that the state was
still providing credits, those credits could focus on
exploration work; the state should not be lending money
against a project that might not be able to pay it back.
Vice-Chair Saddler clarified that Mr. Alper had been
speaking to 50 percent of the project cost.
Mr. Alper replied in the affirmative.
6:50:14 PM
Representative Guttenberg about the relevance of the AIDEA
loan concept to the version of the bill that came out of
House Resources Committee.
Commissioner Hoffbeck responded that it would be less
relevant because of the intent that it would replace some
of the cash credits with a loan program. He said that the
credits were being used to leverage loans for projects. He
said that the legislation would make for a more direct
loan, at rates that were competitive. He stated that the
state would not expect repayment on the debt until actual
production began, which would be attractive to developers.
He expressed the desire to see companies move toward the
loan program, versus direct credits. He relayed that
initial provisions in HB 246 stipulated that if a company
took the loans then they would no longer be eligible for
the credits.
6:51:46 PM
Representative Guttenberg surmised that the original
version of HB 247 had included the loans, but that they had
been replaced by the direct credits.
Mr. Alper clarified that the original HB 247 had not
directly referenced the loan program, they had been
introduced as a package. He said that the original bill
greatly reduced the expected credit support, which prompted
the need for the new loan program.
Representative Guttenberg probed the difference between a
loan package and a direct payout. He wondered how the
state's fiscal situation would be affected if there was no
return to the state with a direct payout, and if the loan
package would became a revolving loan fund.
Commissioner Hoffbeck commented that that administration
had viewed the legislation as a long-term solution to the
fiscal crisis. He said that the revolving loan fund would
need to be endowed to begin with, and additional
appropriation would be necessary depending on the
popularity of the program. He stated that the capital would
return to the state eventually, and then could be re-
loaned. He noted that a direct cash payout would require
continual appropriations.
Co-Chair Thompson reminded the committee that HB 247 was on
the meeting agenda and that HB 246 would be debated during
a different committee meeting.
Representative Guttenberg rebutted that the evolution of
the bills was relevant to discussion on HB 247 and direct
credits. He said that he was curious about the solvency of
the state with money "going out the door with no return on
it."
6:55:01 PM
Representative Gara understood that the governor's
intention in Cook Inlet was to allow the net operating loss
to continue for companies that had not made money in order
to encourage them to explore, but to eliminate the capital
expenditure and well lease expenditure credits for
companies that were making a profit and were not paying
production taxes. He summarized that credits would be given
to companies that were not making money and no credits to
companies that were making money.
Mr. Alper explained that the credits were not meant as
encouragement for exploration, but more of a support to the
companies while they were under development. He added that
as originally proposed the net operating loss credit meant
that the state would be refunding 25 percent of a company's
costs up to the point of profitable production.
6:56:28 PM
Representative Gara surmised that companies that were doing
work, but not making money, would be supported by a credit
in Cook Inlet; companies that were producing, but were not
paying production taxes in Cook Inlet, would lose the
capital and well lease expenditure credits.
Mr. Alper responded in the affirmative.
Representative Gara understood that the governor had
proposed limiting the annual credit payment to $25 million
per company.
Mr. Alper responded yes. He added that current statute did
not contain a defined limit.
Representative Gara summarized that the other proposal from
the governor was to have a hard minimum tax floor for
fields that paid the minimum tax. He contended that there
was currently no minimum tax for GVR fields, but that the
pre-2003 fields would floor that could not be lowered using
the net operating loss credit.
Mr. Alper replied that for new oil that enjoyed the gross
value reduction, and could currently pay at zero, the
intention was to make them pay at zero. The administration
hoped to harden the floor so that an operating loss credit
would not result in reducing payments to below the floor
for the legacy fields that already paid at the floor.
Representative Gara continued to interpret the legislation.
Mr. Alper responded that Representative Gara seemed to
understand the major provisions of the legislation.
Representative Gara asked whether there would be any
ongoing costs to the state related to the AIDEA loans.
Mr. Alper did not believe that any ongoing costs would be
added by passage of the legislation. He furthered that the
bill would create the statutory authority for a new fund,
with separate management, and a fourth parallel structure
inside the governing AIDEA law. He said that the fiscal
note attached to the bill would establish the initial $200
million to begin issuing loans.
7:00:07 PM
Representative Gara spoke of what the state could expect in
production taxes over the next several years if the bill
did not pass. He asked, if the bill did not pass, what the
state was projected to receive in production taxes after
tax credits were deducted.
Mr. Alper responded that the production taxes were quite
low at present, and were expected to drop further. He said
that it was expected that all of the major producers would
have operating losses in 2016, and the production tax would
drop to zero by 2018. He said that there was $825 million
in estimated production tax cost for FY 17, updated from
the spring forecast; $450 million in FY 18; $375 in FY 19.
7:01:26 PM
Representative Gara wondered whether tax credit payments
would exceed all oil revenue if thing remained the status
quo.
Mr. Alper clarified that when the governor released the
spring forecast the revenue for unrestricted general fund
of all oil and gas sources added up to a number that was
expected to be less than the anticipated credit spend. He
added that this was unique to FY 17, in FY 18 the state
would again be in the black.
7:02:42 PM
Co-Chair Thompson understood that the current version of
the bill had a $200 million credit limit per company.
Mr. Alper responded in the affirmative.
Co-Chair Thompson hypothesized that 4 companies could come
together to work on one project, on one pad, and could each
receive the $200 million credit, totaling $800 million in
credits.
Mr. Alper replied yes. He added that in order for that to
happen the companies would have to be spending over $2
billion.
7:03:16 PM
Representative Wilson understood that the governor's
original bill would eliminate gas tax credits in Cook
Inlet.
Mr. Alper responded that the governor's bill would have
eliminated the 20 percent capital credit (QCE) and the 40
percent well lease expenditure credit (WLE). He said that
those were the credits tied to expenditure that could be
stacked with the operating loss credit. The operating loss
credit was left intact at 25 percent. He explained that
from the point of view of a company that was under
development, the current 60 percent level of state support
would be reduced to 25 percent state support. He furthered
that the company that was generating profit would be
receiving no credit support from the state.
Representative Wilson asked whether any of the credit
expenditures had been written into SB 21.
Mr. Alper replied that SB 21 did not touch upon any of the
credits outside of the North Slope.
Representative Wilson thought that now could be a good time
to review the credits. She noted that there would be
another review in 2022.
Mr. Alper responded that he had spoken to Senator Giessel's
resource working group over the interim about the idea of,
"maybe in Cook Inlet it's time to declare victory and move
on." He said that there had been push back regarding the
sentiment. He believed that Representative Wilson made a
valid point; the issues of supply anxiety were less severe
than they had been 7 years ago, and the sponsors of SB 21
had admitted that enhanced credits for Cook Inlet had been
an extreme measure, meant to sound an alarm. He thought
that the mission had been partially accomplished because it
had spurred conversation about ramping down the credits.
7:05:52 PM
Representative Wilson wondered how much money further
ramping down of the credits would save the state.
Mr. Alper believed that the original fiscal note had
reflected approximately $150 million.
Representative Wilson requested a chart that would show the
tax credits that were in SB 21 that would be affected by
the legislation, versus how the credits that had not been
in SB 21 would be affected.
Mr. Alper pointed out that the department had presented to
the Joint Resources Committee in June, a document that had
the information that Representative Wilson sought. He said
he would supply the document to the committee. He believed
he had sent it to the Co-Chair's office the previous
evening.
7:06:59 PM
Vice-Chair Saddler referred to Slide 47. He requested that
the department provide the analysis to $20, $30, $110, and
$120/bbl.
Mr. Alper clarified that the information could be provided.
He asked whether Vice-Chair Saddler wanted the Cook Inlet,
small field scenario, or a wider range of scenarios.
Vice-Chair Saddler referred to Slide 51. He thought
modeling of the same could be done using the numbers he had
requested.
Mr. Alper agreed to provide the information. He added that
just a $40/bbl showed red on the chart, $20 and $30/bbl
would reflect even less optimistic numbers.
Vice-Chair Saddler asked whether the capital expenditure of
$18/bbl was averaged over the 30 year lifespan used in the
models.
Mr. Alper responded that the numbers were drawn from model
fields that provided known information. He said that any
new oil field would had a lot of capital spending in the
first several years. He continued to say that the operating
expenditures tended to be ongoing as the field was in
production, and was attached to the per barrel charge, from
year to year. He stated that each of the sets of scenarios
had a full slide of assumptions. He clarified that what was
being looked at, specific to the field on Slide 47, was a
field where all of the oil produced over the entire 30 year
lifespan would add up to 50 million barrels of oil. He
added that 50 multiplied by $18/bbl would be equal to $900
million dollars, which meant that the total capital spend
to get the project going was $900 million.
Vice-Chair Saddler confirmed that the net state gain
reflected on the slide included royalties, property tax,
production tax, and corporate income tax.
Mr. Alper responded in the affirmative.
7:11:03 PM
Vice-Chair Saddler asked about the first bullet under
"Interest Rate Reform" on Slide 34. He asked why the error
was considered technical.
Mr. Alper answered that the original version of SB 21 that
had been proposed by Governor Parnell intended to reduce
the interest rate from 11 percent to 3 percent over the
federal discount rate. He added that previous law had
compound interest, and the original version of SB 21 kept
the compound interest. He stated that when the bill made it
to the Senate Floor, and passed with the 3 percent, over
discount rate, compound interest. He relayed that the
contentious legislation failed to garner an effective date
vote on the Senate Floor. The bill made its way to the
House Resources Committee, which crafted a committee
substitute that included work around language to deal with
the lack of an effective date. He summarized that drafting
errors pertaining to the interest rate and compound
interest would be changes to better reflect the original
intent of the legislation.
7:13:57 PM
Representative Pruitt wondered whether the department had
communicated with other oil resource states about how they
were addressing the downturn in oil prices.
Commissioner Hoffbeck replied that tax structures in
various states had been examined. He said that Alaska was
unique in its net tax, other states were on a gross tax
basis. He relayed that the Oil and Gas Competitiveness
Review Board had not spoken to the issue to-date, and that
some provision changes had occurred in other states.
Mr. Alper explained that the other states that produced oil
in America were all on the gross, Alaska was the only state
on the net. He added that Alaska was also the only state
that offered refundable cash credits. He said that
companied were losing money in Oklahoma, North Dakota, and
Texas right now because that price of oil was the same
there as it was in Alaska, and they were paying a gross
severance tax to those state of up to 11 percent. He
asserted that Alaska had a 4 percent gross tax at the
current oil price, the net tax was a theoretical upside
should prices recover.
7:15:50 PM
Representative Pruitt stated that effectively the state was
increasing its tax by reducing the tax credit. He wondered
which other states were increasing taxes during this time
of low oil prices.
Commissioner Hoffbeck contended that there was a
fundamental disagreement on whether the removal of a
subsidy should be considered an increase of the tax. He
asserted that a tax was a demand from a government entity
for repayment, but in this case the state was paying money
out and reducing the amount of subsidy that it paid. He did
not believe it should be classified as an increased tax,
rather a subsidy reduction.
Representative Pruitt argued that the bill would not only
adjust the credits but would also increase to 5 percent,
and harden, the floor. He asked his question again.
Commissioner Hoffbeck stated that he did not believe any
other state was raising the tax. He admitted that the
hardening of the floor at 5 percent could be categorized as
a tax increase.
Mr. Alper continued to Slide 59: "Implementation:
Administration":
· The changes anticipated in this bill still require
somewhat substantial reprogramming of the Tax
Revenue Management System (TRMS) and Revenue Online
(ROL) which allows a taxpayer to file a return
online and update the current tax return forms
· We have received a preliminary estimate from the
software developer, and currently assume a one-time
cost of about $1.2 million to accomplish this
· We do not anticipate any additional costs to
administer the tax program
· There will also be a need for substantial amendments
to existing regulations to fully implement the
changes
SB 247 was HEARD and HELD in committee for further
consideration.
7:19:58 PM
Representative Gara pointed out that there was a statutory
formula for what the state was required to pay on all tax
credits, under current law. He requested documentation of
what the state was statutorily required to pay on tax
credits.
Mr. Alper agreed to provide the information to the
committee.
Co-Chair Thompson discussed housekeeping
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 247 NEW FN DOR TT 032916.pdf |
HFIN 3/31/2016 5:00:00 PM |
HB 247 |
| HB 247 20160331_Oil&GasIndustryInAlaska_HFIN.PDF |
HFIN 3/31/2016 5:00:00 PM |
HB 247 |
| HB 247 Fiscal Impact of Cook Inlet Production Tax Limitations 2007 to 2013_20150327.pdf |
HFIN 3/31/2016 5:00:00 PM |
HB 247 |
| HB 247 Copy of credit table basic 6-15 (003).pdf |
HFIN 3/31/2016 5:00:00 PM |
HB 247 |
| HB 247 credit table basic 3-16.pdf |
HFIN 3/31/2016 5:00:00 PM |
HB 247 |