Legislature(2011 - 2012)SENATE FINANCE 532
03/27/2012 01:00 PM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| Presentation: Department of Natural Resources | |
| SB192 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 192 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 27, 2012
1:08 p.m.
1:08:58 PM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 1:08 p.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Lesil McGuire, Vice-Chair
Senator Johnny Ellis
Senator Dennis Egan
Senator Donny Olson
Senator Joe Thomas
MEMBERS ABSENT
None
ALSO PRESENT
William C. Barron, Director, Division of Oil and Gas,
Department of Natural Resources; Janak Mayer, Manager,
Upstream and Gas, PFC Energy; Senator Joe Paskvan; Senator
Cathy Giessel;
SUMMARY
SB 192 OIL AND GAS PRODUCTION TAX RATES
SB 192 was HEARD and HELD in committee for
further consideration.
PRESENTATION: DEPARTMENT OF NATURAL RESOURCES
William C. Barron, Director, Division of Oil and
Gas, Department of Natural Resources
Co-Chair Stedman discussed the meeting's agenda.
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
^PRESENTATION: DEPARTMENT OF NATURAL RESOURCES
1:10:32 PM
WILLIAM C. BARRON, DIRECTOR, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES, continued the Department
of Natural Resources' PowerPoint presentation titled
"Senate Finance Committee 26 March 2012" (copy on file)
from the previous meeting. He stated that during the
previous meeting, the presentation had covered the ways and
means of the state's ability to dispose of land and
furthered that the primary aspects of land disposition were
through the area wide lease sale. He noted that some of the
terms and conditions of the bonus and rental programs,
which were in place on the North Slope and Cook Inlet
areas, had also been discussed in the prior meeting.
Mr. Barron explained the slide on page 6 titled
"exploration licensing system." He stated that the
exploration licensing system was the other opportunity for
land disposition.
Exploration Licensing System:
· Areas not within area wide lease sales
· No rental fee or upfront bonus payment
· Term up to 10 years
· When work commitment is fulfilled, licensee
may convert part or all of license area to
leases (subject to $3/acre rental fee and,
when producing, no less than 12.5% royalty)
· State is provided all geological & geophysical
information acquired
· If competing proposals, highest bid for minimum
work commitment is selected
· Imposes financial work commitments (AS 38.05.131-
.134)
· Licensee must commit 25% of total specified work
commitment by fourth anniversary of license
issuance
Mr. Barron stated that the exploration licensing system
applied to areas that were not in the area wide lease sale
and that the two programs were distinct and separate. He
explained that the ten year term of an exploration license
operated on the basis that companies would come forward to
designate an area of interest and propose financial work
commitments. A company's license could be revoked if it had
not completed 25 percent of its fiscal commitment within
the first four years. After the ten year term expired, the
area within the exploration license could be converted to a
lease, or multiple leases, for another five year term; the
five year extension provided the program with additional
exploration and delineation, and would hopefully progress
the property into development. He stated that there were
only four areas participating in the exploration licensing
system and that the program was not widely utilized. He
concluded that the area wide lease sale was more honed for
the exploration of oil and gas in Alaska.
1:13:31 PM
Mr. Barron explained the slide on page 7 titled "current
status of state leases."
· Active leases: 1416 leases (largest tract: 9
square miles)
· Of these, 46% of leases are in units (producing)
· 0.5% are leases producing without being in units
· 46% of leases are in the hands of companies
currently actively exploring on part of their
lease hold*
· Apache, Buccaneer, Nordaq, LINC, Repsol,
Great Bear, Brooks Range, Anadarko
· Included in this number are Foothills leases
where lessees have conducted field work in
the past (gas-prone areas)
· The remaining 7.5% may or may not be under
exploration
· A majority of these leases (approximately
95%) are held by individuals or groups of
individuals, not major corporations
*The list is not extensive; this only includes companies
we know are currently actively exploring.
Mr. Barron explained that the slide did not include the
December 2011 lease sale on the North Slope; most of the
North Slope leases had yet to be adjudicated and were still
within the confines of the state's ownership. He stated
that the 9 square mile plot was included because it was the
largest lease that was allowed by statutes. He pointed out
that many of the international arenas used "blocks" and
that in these countries, a block could be a single lease
that was 180 to 190 square miles; a block this size was
roughly half the size of Prudhoe Bay. He stated that there
was a significant difference of understanding regarding
concessions in international regimes and what occurred in
Alaska. He explained that many countries packaged blocks
together and might have as many as six different blocks
that were offered at the same time. He referenced the 46
percent figure, which was in the fourth bullet point and
explained that Apache had acquired and explored a number of
tracts in the Cook Inlet lease sale the prior year. Apache
was doing seismic work and was systematically "shooting
seismic" that would eventually cover all of its tracts of
land. He stated that the 46 percent figure showed that
although companies might not be actively drilling or
shooting seismic on every single tract of land, they were
making progress through the activity.
Mr. Barron pointed out that Alaska's lease terms were
competitive based and that anyone who was 18 years of age
could own a lease in Alaska. He opined that there were many
different kinds companies in the oil industry; some
companies primarily focused on exploration, some had a
primary paradigm of development, while others had a primary
corporate function that was referred to as "brownfield
operations." He explained that explorers and early
developers represented "greenfield operations", while
activities on mature fields were referred to as "brownfield
operations."
Mr. Barron stated that speculators actively purchased and
marketed leases to other players and that they served a
critical function in lease sales. He offered that Armstrong
Alaska was a good example of company that was in a
speculator mode. He explained that Armstrong Alaska's
ability to market land had attracted companies like Repsol,
Pioneer Natural Resources Alaska, and ENI Petroleum;
furthermore, Armstrong was currently doing its own
development work in the Kenai Peninsula. He observed that
although a company like Armstrong tended to focus on land
management, it served a valuable function in the state's
development of oil and gas.
1:19:54 PM
Senator Thomas referenced the last bullet point on slide 6.
He inquired if pursuing the sale of a lease was considered
a "work commitment", or if the term meant that a company
must commit to some form of exploration and/or drilling.
Mr. Barron responded that slide 6 dealt with exploration
licenses, but that a work commitment was not necessarily
associated with the area wide lease sale. He offered that
work commitments can be part of a lease sale opportunity
and that the state had the ability to specify work
commitments, as part of the original bid, during the
exploration phase; work commitments were imposed in this
fashion as recently as last year in the case of the Cook
Inlet's Cosmopolitan Unit. He explained that for the
Cosmopolitan Unit, the state had required entities to bid
on leases that were packaged together and also required
that over a period of time, the companies must identify,
drill, and establish a participating area (PA) within the
lease area. He stated that requiring a work commitment as
part of bid might have some merit, but that it was
problematic to require a company to know what its plans
were before it had won the bid. He furthered that the
bidding system was competitive and that the problem facing
a company was how to put together a work plan without
knowing what it had won or the level of prospectivity in
the area that it was trying to develop.
Senator Thomas acknowledged that it was helpful to have
speculators, but pointed out that most of the people who
were looking to develop oil or gas properties would be at
the lease sale. He referenced a speculator's abilities to
bid, buy, and hold onto land and stated that he had assumed
that both the area wide lease sale and exploration license
systems had work commitment requirements. He queried what
the requirements were on potential buyer, and at what time
was the lease holder required to deliver a work or
development plan. Mr. Barron replied that with respect to
an exploration license, a company would identify what it
would spend on a property, but that it would not
necessarily define the type of work. In the state's area
wide leasing system, the state specified that companies pay
a rental tax for the first seven years that they owned the
property; if no or little work had been done by the seven
year point, the rental rates would go up significantly for
years eight, nine, and ten. He explained that the three
year period of increased rental rates was intended to
encourage companies of interest to develop. He observed
that there was a possibility of blending the area wide
lease sale and the exploration license systems, but that
"is not where we are today." He concluded that if the
state's area wide lease system required a bid and an
assured financial commitment from an entity, it could limit
the players that would be willing to participate in the oil
and gas sector in Alaska. He offered that DNR's goal was to
attract as many people or companies as possible to Alaska,
encourage and support the exploration efforts of companies,
and to quickly drive discoveries into development.
1:26:48 PM
Mr. Barron discussed the slide on page 8 titled "land
management: When is PA formed?" A "unit" was formed when a
discovery was proven to have moveable hydrocarbons. The
purpose of forming a unit was the protection of all parties
associated with the reservoir. He explained that some
reservoirs crossed over lease boundaries and that as a
result, multiple leases were sometimes formed into a unit.
· A PA is formed once the unitized reservoir is on
"sustained production": wells are producing into
a pipeline or other means of transportation to
market
· Separate PA required for each producing horizon
· Approval of a PA includes approval of allocation
factors
· Sets out proportions of costs and revenues
paid and received by working interest owners
· Approval meets 11 AAC 83.303: Protect all
parties
Mr. Barron explained the slide on page 9 titled "What is a
plan of development (POD)?"
· Once a PA is formed, a POD is required under 11
AAC 83.343
· Must be filed for approval if a PA is
proposed, or reservoir sufficiently
delineated to initiate development
activities
· POD is submitted annually for review and
approval
· If POD deemed insufficient for approval, DNR
may propose modifications. If Operator
agrees to modifications, POD approved.
· If not accepted by Operator, and no approved
POD, current POD may expire.
· Development activities must be conducted under an
approved POD
Co-Chair Stedman requested an accelerated run through of
the slides. He noted that the committee was focused on
budget issues, while some of the slides were more geared
towards resources.
Mr. Barron discussed the slide on page 11 titled "North
Slope units and PAs: February 2012. 18 existing SOA units,
42 PAs, 2 units proposed." Mr. Barron related that there
were 18 existing units, 42 PAs, and two proposed units on
the North Slope.
Mr. Barron discussed the slide on page 12 titled "POD
process" and explained that the process flow diagram was
for the committee's future reference.
Mr. Barron discussed the slide on page 13 titled
"evaluating PODs on a complex unit - DOG evaluation tools."
He stated that the state used the "score sheet" to compare
past PODs. The "bubble map" helped DNR identify areas of
concern or interest that it would like a company to target
closer.
Mr. Barron explained the slide on page 14 titled "Kuparuk
River Unit(KRU) bubble map." He stated that the slide
depicted Kuparuk and that the map showed a "classic line
drive waterflood" reservoir. He offered that the map very
clearly showed where the water was pushing the oil to
producers.
Mr. Barron discussed the slide on page 15 titled "southwest
portion Kuparuk River Unit (KRU)." He observed that the
lower left hand corner of the map was devoid of
developments and that the state had several dialogues with
ConocoPhillips, which had resulted in the well Sharks Tooth
being drilled in the area "this winter." Sharks Tooth was a
confidential well and DNR had not yet seen the logs from
the development.
Mr. Barron explained the slide on page 16 titled "Prudhoe
Bay Unit" and explained that the slide depicted how
reservoirs were stacked on top of each other. PAs could be
stacked on top of each other for every producing horizon.
1:31:21 PM
Mr. Barron discussed the slide on page 17. He stated that
DNR was in constant discussion with the operators in the
slide's the two mapped areas regarding future plans for
development, increased production, and development area
expansion.
Mr. Barron explained the slide on page 20 titled "Prudhoe
Bay Unit, oil and water production rates." He related that
there had been a lot of discussion regarding facilities,
facility constraints, future development, and future
operations. He offered that the perception was that there
was excess capacity in the Trans-Alaska Pipeline System
(TAPS). In the original development phase of any oil gas
property, facilities were designed to handle fluids in a
certain manner. He stated that in a 1,000 barrel per day
(bbl/d) facility, 900 of the barrels might be oil, while
100 barrels would be water; it was still considered a 1,000
bbl/d facility. He furthered that as the life of the field
neared its end, there may 100 bbl/d of oil and 900 bbl/d of
water being produced from the facility; this was also
considered a 1,000 bbl/d facility. He added that regardless
of the ratio of water to oil, a 1,000 bbl/d facility would
only be able to handle 1,000 bbl/d. He stated that the
slide showed that Prudhoe Bay's oil was declining.
Mr. Barron discussed the slide on page 21 titled "Prudhoe
Bay Unit, total fluid production and water injection
rates." The slide showed that the production total
throughput of oil and water had basically remained constant
since the year 2000. He added that after 2000, the rates
did drop a little and that the question was, what else
could be impacting the production. He added that there was
excess capacity in the Prudhoe Bay Unit, but that the
system was handling more gas.
Mr. Barron explained the slide on page 22 titled "Prudhoe
Bay water oil ratio, Prudhoe Bay gas oil ratio." He stated
that the water to oil ratio and the gas to oil ratio were
depicted on the slide's two graphs. As the Prudhoe Bay Unit
injected gas for pressure maintenance, more gas had to be
processed; furthermore, water was injected to maintain the
waterflood, which resulted in a higher demand for water
processing. He concluded that many of the Prudhoe Bay
facilities were limited in capacity by water or gas. He
related that Prudhoe Bay's reservoir engineers had done an
"amazing" job in the development and asset allocation for
the field. He added that originally, the field was expected
to have a 30 percent recovery rate, but that the current
rate was approaching 60 percent. He stated that the
engineers had sophisticated reservoir simulation tools and
that they were able to prognostic which wells would produce
more water or more gas; the engineers "shut in" the wells
with more gas. The engineers' process limited the amount of
investments that were needed for facility upgrades and
"debottlenecking", and enabled the engineers to predict and
control which wells to turn on or off; well work overs and
recompletions would then be conducted for the appropriate
wells.
Mr. Barron discussed the slide on page 23 titled "Kuparuk
River, oil and water production rates." He stated that
Kuparuk was experiencing the same curves for oil and water
as Prudhoe Bay.
1:35:32 PM
Co-Chair Stedman asked for a clarification on slide 20. He
observed that from 1987 and onwards, the green line fit the
definition of a parabolic curve and inquired if it appeared
to be flattening. Mr. Barron queried if Co-Chair Stedman
was referring to the last three years of the green line.
Co-Chair Stedman responded in the affirmative. Mr. Barron
stated that the plot, from an engineer's perspective, was
drawn incorrectly. He explained that the y axis for a
decline curve should be a "log curve" [logarithmic] instead
of a "Cartesian curve." He explained that in a semi-log
presentation, the line would be close to straight and that
although the decline appeared to be flattening, it was
almost straight; the curve was referred to as a "straight-
line depression."
Co-Chair Stedman requested that DNR's future charts reflect
the oil production in logarithmic and nominal scales. Mr.
Barron responded that DNR would be happy to do so.
Mr. Barron explained the slide on page 24 titled "Kuparuk
River, total fluid production and water injection rates."
He stated that the Kuparuk curves were similar to Prudhoe
Bay's curves and that the gas to oil and water to oil
ratios were elevating. He offered that the curves on the
slide were very similar to any other primary, conventional
oil and gas field in the world; he added that shale oil was
an exception to the similarity. He concluded that the
decline curve analysis, the oil decreasing with the gas
increasing, and the water increasing with waterflooding
were typical of other fields around the world.
Co-Chair Stedman asked how long ago DNR would have been
able to "draw that conclusion." Mr. Barron stated that
Prudhoe Bay's decline could have been predicted as early as
1989 to 1990.
Co-Chair Stedman inquired whether the decline curve would
have been expected when the basin was opened. Mr. Barron
replied that the curve was predictable in a conventional,
sandstone reservoir. He added that the field would manage
itself and that the exact rate of decline would be
determined later on. He stated that a "type curve match"
analysis, which used models of similar fields, could have
predicted the flat section, the plateau, and some sort of a
rate of decline.
Co-Chair Stedman inquired if the analysis in question was
referred to as a "type curve analysis." Mr. Barron
responded in the affirmative.
1:39:30 PM
Co-Chair Stedman observed that some people were surprised
about where the rate of decline was today. Mr. Barron
voiced his agreement.
Senator Thomas referenced slides 21 and 24. He stated that
in 1993, the total liquids production from Prudhoe Bay and
Kuparuk combined was approximately 3.2 million bbl/d. Mr.
Barron replied that he would not argue the numbers. Senator
Thomas inquired if gas handling issues were limiting the
maximum level of the fluid production and water injections
rates in the two fields. Mr. Barron responded in the
affirmative. He referenced slide 22 and stated that gas
handling limitations were indicative to some of the
facilities.
Senator Thomas queried if the facilities in Prudhoe Bay and
Kuparuk had a maximum level of oil and water production of
about 3.2 million bbl/d. Mr. Barron agreed that 3.2 million
bbl/d was probably a good number to use.
Mr. Barron explained the slide on page 25 titled "Kuparuk
River water oil ratio, Kuparuk River gas oil ratio." He
clarified that if DNR were examining shale oil, it would
look at similar models, such as the Bakken, Eagleford, or
Marcellus shale plays. He explained that DNR would examine
the production profiles of different shale developments in
order to form predictive models for shale oil in Alaska. He
pointed out that in a new field, engineers typically
examined the type and size the reservoir, as well as how
many wells would need to be drilled. He concluded that
originally, engineers had reservoir models, but that they
were very simplistic; even still, the plateau and the
inception of the decline curve could have been predicted.
He reiterated that slides 21 through 25 represented a
typical exhibit of a major oil field's decline curve.
Mr. Barron discussed the slide on page 26. General
production facilities were listed on the slide. He stated
that the table depicted information that the Division of
Oil and Gas had gathered from various companies. He added
that the information on the table might not be fully up to
date. There were red and green bars on the far right hand
side of the slide; the red bars indicated that there were
limitations on the unit, while the green bars meant that
there were no limitations. He observed that the red and
green bars did not render very clearly on the slide. He
pointed out that the North Star Unit had a red bar and
discussed the unit's limitations. He stated that DNR used
the slide's information to assess the limitations on
producers and that some of the information would be part of
a company's POD. He stated that DNR wanted to know if
companies were installing more facilities, if they were
modeling efforts to control gas, if gas handling facilities
were needed, and how the pressure maintenance was going. He
pointed out that very few of the facilities had a green bar
associated with it. He offered that the Badami Unit was an
underutilized asset and that companies in the area would
likely be open to a production sharing and processing
facility sharing agreement. He stated that Oooguruk and
Nikaitchug had no limitations; however, the CPF-3 Unit,
which did have limitations, was processing Oooguruk's oil.
Mr. Barron explained the slide on page 27 titled
"facilities access agreements." He explained that DNR's
dialogue had tended to revolve around facilities access
agreements and that the agreements were "incredibly
complicated" and were between players that were sometimes
competitive.
1:45:38 PM
Senator Thomas asked for a clarification of the chart on
page 26. He inquired if flow stations 1, 2, and 3, as well
as gathering centers 1, 2, and 3 all had gas or water
handling limitations. Mr. Barron responded in the
affirmative.
Senator Thomas queried if the stations and centers were
limited to a total production capacity regardless of the
makeup of what flowed through them. Mr. Barron responded in
the affirmative.
Mr. Barron continued to discuss the slide on page 27.
· Facility access agreements are complicated
commercial agreements between multiple parties
· Facility access agreements impact
· Reservoir management
· Process management
· Influence and impact PODS, which in turn has
an impact on expense and capital exposure in
the state
Mr. Barron stated that it became legally and commercially
complicated when a new player joined a facility. He listed
possible complications in the case of a facility shut down
as follows: who was responsible for the loss or deferred
production, who gets backed out of the facility first, who
has the right to first access back in to the facility, are
there penalty clauses involved, and would the state declare
a loss of revenue; all of the eventualities needed to be
considered from the perspectives of commerciality and their
impact on companies' overall asset management. Many
companies had an internal corporate culture, which dictated
that it would build its own self-sufficient facilities. He
pointed out that some companies preferred to ship oil via
the existing pipeline network and have smaller production
facilities rather than relying on someone else to process
fluids; he offered that this model worked well in a number
of areas. He stated that in Norway, using an existing
offshore structure for the common good of many players was
part of the program. He explained that Norway did not want
to construct new platforms, but that it wanted to utilize
the facilities that were in place; in that regard, Norway
leased space on the platform for new facilities.
Mr. Barron explained a slide on page 28 titled "facilities
summary."
· The Prudhoe and Kuparuk units are experiencing
typical reservoir depletion which requires
handling and processing of increasing amounts of
water and gas, decisions on facility management,
effective well utilization, and complex reservoir
management.
· Facilities are designed to meet a wide range of
production profiles with varying water-oil and
gas-oil ratios (WOR and GOR, respectively). As
the reservoir matures, reservoir management and
facility debottlenecking for water and gas
handling, water and/or gas injection to maintain
reservoir pressure, well workovers, and new
infield development drilling is required.
· Pipeline capacity is available throughout most of
the North Slope, thus companies with new oil
discoveries will need to negotiate to share the
existing transport facilities.
· Corporate culture and size of a discovery
typically dictate decisions whether to build new
process facilities or enter into commercial
agreements to access existing facilities.
Mr. Barron related that Prudhoe Bay and Kuparuk were well
managed properties and that the two areas' gas reinjection,
waterflood, and miscible flood activities had all benefited
the state. Companies were managing Prudhoe Bay and Kuparuk
by turning wells on and off, examining which wells would
have too much water or gas, moving the water and gas
around, maintaining reservoir pressure, and knowing the
location of the gas fronts and water fronts. He furthered
that retrofits, debottlenecking, well workovers and
recompletions, and the water and gas shutoff program were
all done on a well by well and area by area assessment
basis. He added that the pipeline capacity on the North
Slope was robust and that new players should not have a
problem entering into the existing pipeline networks.
1:50:30 PM
Co-Chair Stedman remarked that oil still had to be brought
to the pipeline. Mr. Barron replied that on any new
development, the producer could lay its own line from its
own production facility that would tie into existing
infrastructure; this was similar to how Alpine had tied
into Kuparuk in order to get to Pump Station 1. He offered
that if Repsol had a discovery on a well that it was
drilling, it would install its own production facilities
that tied into an existing line. He related that every
field was managed differently, but that in general, every
well had to be hooked up to a production system. He
concluded that oil cannot flow from a well straight into
the pipeline because of the water, gas, sand, or debris
that was produced along with the oil.
Co-Chair Hoffman asked what involvement DNR had with the
facilities agreements. Mr. Barron replied that DNR had very
little involvement and that the agreements were between the
two parties; if asked by either party, DNR could "lean in"
to encourage facilities agreements. He concluded that DNR
was very seldom engaged in those sorts of negotiations.
Co-Chair Stedman inquired if DNR had an idea of what it
would take for facility upgrades in order to increase
production. Mr. Barron replied that DNR did not. Co-Chair
Stedman queried if DNR ever looked at that aspect of
facilities. Mr. Barron responded that during the POD
process, DNR examined companies' proposed activities
relative to wells and facilities; this opportunity allowed
DNR to assess whether companies would be making upgrades or
modifications to the existing systems.
Co-Chair Stedman queried if DNR could provide information,
which could be used to increase production, regarding the
separation of "below ground" and "above ground" issues. He
observed that a lot of time was spent discussing below
ground well workovers or infill drilling, but that very
little time was spent discussing facilities. He inquired if
the state was dealing with facility constraints, below
ground constraints, or a combination of both. He further
inquired if DNR knew what it would take to stabilize
production at 600,000 bbl/d. Mr. Barron replied that it
would take a combination of new exploration and new infill
drilling. He stated that infill drilling work had arrested
the state's decline curve over time; the decline was
occurring at a lesser pace because of the companies'
investments, infield drilling, well workovers, and facility
modifications. He stated that in order to further flatten
the decline, all the parties involved would have to install
more wells and facilities. He furthered that the state
needed new entries into the market and cited the potential
entrants as follows: Brooks Range Petroleum, Repsol,
Pioneer Natural Resources, ENI Petroleum, the Schrader
Bluff heavy oil, as well as Great Bear Petroleum's and
Royale Energy Inc.'s shale oil; he stated that "all of
those would be part of the play" and would need new
facilities.
Co-Chair Stedman asked if DNR had recommendation or advice
for the committee regarding potential costs. Mr. Barron
replied that he did not.
1:55:22 PM
Co-Chair Hoffman stated that given the inevitable decline,
it would potentially take hundreds of millions of dollars
to increase facilities for new oil. He inquired if it would
be more financially prudent for the state to keep the
status quo rather than having the industry incur such a
large investment. He observed that the question might be
one that the committee or DNR would be unable to answer.
Mr. Barron replied that the North Slope basin was still a
robust and rich oil basin. He referenced British
Petroleum's (BP) heavy oil development at Milne Point,
which had a recent well test of 650 bbl/d in production; he
indicated that this production level was "beyond world
class" in terms of heavy oil production from a single well.
He stated that developments like Milne Point, in aggregate
across the state, are what would drive development beyond
where it was today. He opined that the decline curve could
be flattened and reversed, but that it would take a
"tremendous effort" by industry beyond what it was
currently spending. He added that the new development plays
and new exploration work were critical to get to where the
state wanted to be.
Senator Thomas asked for clarification on page 28 and
inquired if the third bullet point was referring to
"downstream" pipeline capacity. Mr. Barron responded in the
affirmative. Senator Thomas queried if the non-downstream
capacity was being used for water and gas handling. Mr.
Barron replied in the affirmative. Senator Thomas asked if
the water and gas injection was required to maintain well
pressure, or whether gas and water were in the system
because there was nothing else to do with it. Mr. Barron
replied that water and gas injection was needed. He
referenced slide 14's bubble map, which depicted the line
drive waterflood in Kuparuk and stated that waterflooding
was a viable technique for maintaining reservoir pressure;
the water was used to "sweep" oil away from an injector and
bring it closer to a producer. He stated that the
reinjection of gas into the gas cap had greatly benefited
Prudhoe Bay and that it resulted in oil moving from the
upper elevations of the reservoir into the lower producing
horizon. He pointed that water and gas injections were very
viable techniques and mentioned that both Prudhoe Bay and
Kuparuk were experimenting with new reservoir management
techniques.
2:00:01 PM
Senator Thomas observed that the only solution seemed to be
to build more facilities that could process water and gas.
He pointed out that gas and water were needed, but that the
facilities which processed them were currently at capacity
limits. Mr. Barron responded that areas of development that
were west of the heart of the existing Prudhoe Bay area
still had some prospectivity; the prospectivity in these
areas would involve new wells and facilities. He stated
that water and gas came out of the wells naturally and that
additional water was introduced in the general waterflood.
He explained that in order to maintain the pressure, every
barrel of oil that was taken needed to be replaced by a
barrel of water. He concluded that in the case of the North
Slope, the water came from the ocean and was re-injected;
needing more facilities for water and gas processing was a
"self-fulfilling prophecy."
Co-Chair Hoffman referenced the Society of Petroleum
Engineers' western regional meeting in May of 1993 and
quoted engineers from BP and ConocoPhillips, who had
reported that,
"Prudhoe Bay is seen by many as a mature oil field on
an inevitable and irreversible decline … The field's
oil production capacity dropped below 1.5 MMSTB/D in
1988 *officially* signaling the start of decline. The
onset of decline was a direct result of limited gas
handling capacity as opposed to limited oil production
capacity."(copy on file) [The quote can be found in
the backup document titled "gas and water handling
constraints on Alaska's North Slope."]
Co-Chair Hoffman inquired if Mr. Barron agreed with the
quoted statements. Mr. Barron replied that he tended to
agree and that gas handling facilities seemed to be the
bottleneck at the current time. He added that it was
important to remember the necessity of being able to
process and re-inject gas in order to maintain reservoir
pressure and "sweep."
Co-Chair Stedman noted that ConocoPhillips had stated in
prior testimony that increasing production to 700,000 bbl/d
or 1 million bbl/d would be technically impossible. He
observed that there was a technical issue versus a tax
issue and that the committee was struggling with the
balance between the technology constraints and the impact
of the tax system. He furthered that the committee was
trying to separate what was technically feasible, what
would be feasible under a zero tax structure, what was
feasible under the current tax structure, and "where are we
between that zero and where we are today." He pointed out
that the state would not get to 1 million bbl/d in
production and that some felt that it would difficult
achieve 700,000 bbl/d. Mr. Barron responded that testimony
tended to get misconstrued in the overall dialogue. He
opined that it was unlikely that the decline could be
arrested and reversed to 1 million bbl/d in the existing
Prudhoe Bay and Kuparuk fields.
Mr. Barron related that there was still a lot of oil left
to be discovered in the North Slope and that it was still a
target rich environment. He stated that when Prudhoe Bay
was discovered, the expectation was that it would have a 30
percent recovery rate and that the pipeline would be empty
by the year 2000. He observed that in 2012, the North Slope
was still producing 600,000 bbl/d, which was well beyond
the original concepts of what was technically achievable at
the time. He pointed out that 60 percent recovery from a
reservoir was "astonishing" and that he did not discount
scientists' and engineers' abilities to create new ways to
develop oil and gas. He opined that it would possible to
arrest the six percent decline in Prudhoe Bay and bring it
down to four percent for a period of time. He furthered
that it was possible to flat line Prudhoe Bay and Kuparuk,
but that new technologies, new development concepts, new
conventional fields, as well as heavy and shale oil needed
to come on line and be brought to bear. He stated that
Kuparuk and Prudhoe Bay could not be considered in
singularity regarding the future development on the North
Slope. He concluded the work of Savant Alaska LLC at
Badami, the work of Repsol, ENI Petroleum, Pioneer Natural
Resources Alaska, Brooks Range Petroleum, and Great Bear
Petroleum all needed to be part of the equation regarding
overall development on the North Slope; the opportunities
in these areas were "robust" and "tremendous."
2:07:34 PM
Co-Chair Stedman queried if the magnitude of a one percent
or two percent recovery rate would be much greater in
Prudhoe Bay than it would be in other areas. Mr. Barron
responded in the affirmative and related that changing the
decline profile of Prudhoe Bay by one percent, even for a
period of time, would be an "amazing feat." He concluded
that Prudhoe Bay was a huge field and that trying to drill
the right number of wells, in the right locations, with the
appropriate production facilities, and doing so at the
right time were all part of the dynamics of reservoir and
production management.
2:08:28 PM
AT EASE
2:18:21 PM
RECONVENED
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
Co-Chair Stedman discussed the meeting's agenda. He stated
that the PFC Energy presentation would discuss
progressivity options. He observed that after the meeting,
the committee should have a general idea of which options
it would focus on and which ones would be taken off the
table.
Co-Chair Stedman asked for a brief description of PFC
Energy.
2:19:37 PM
JANAK MAYER, MANAGER, UPSTREAM AND GAS, PFC ENERGY, began a
PowerPoint presentation titled "discussion slides: Alaska
Senate Finance Committee." (copy on file) He stated that
PFC Energy was a global consultancy that was focused solely
on "upstream" and "downstream" oil and gas issues; upstream
referred to all activities associated with getting oil out
of the ground, while downstream was reflective of the
refining, marketing, and retail sectors. PFC Energy had a
particular expertise in above ground issues, such as
understanding markets and market analysis, political risk
assessments, understanding fiscal terms, and how a
government set its rules for oil and gas. He added that
companies needed to understand the rules that a government
set in order to be able to do business. He concluded that
PFC Energy worked at the nexus between international oil
companies, national oil companies, and governments.
Mr. Mayer explained the slide on page 2 of the presentation
titled "assessing 10 different fiscal regime options." He
stated that the slide summarized, in terms of revenue to
the state, the different fiscal options that had been
discussed in a previous meeting; the options were presented
in the context of Alaska's Clear and Equitable Share
(ACES), HB 110, as well as other permutations. He explained
that under PFC Energy's model and at an oil price of $100
per barrel, ACES netted the state $3.686 billion in
production revenue; by contrast, HB 110 netted the state
$2.721 billion at the same price level. The core of the
slide's analysis focused on options for base levels of
taxation and progressivity that slightly reduced government
take at given price levels, but did not dramatically reduce
revenue to the state; furthermore, the options would
significantly reduce progressivity "beyond that point" in
order to even the split of revenue between companies and
government. He related that the committee had examined how
CSSB 192 might look if the maximum rate was capped 50
percent instead of 60 percent. He stated that the committee
had also looked at CSSB 192 with a base rate of 30 percent
and a progressivity rate of .2 percent. He added that CSSB
192 with a cap of 40 percent on the maximum rate was also
discussed; without a change to the base rate, this option
did not necessarily generate a significant change in
numbers from the current bill. He related that another
option on the slide was taking progressivity out of
production tax and instead instituting a severance tax. He
explained that a severance tax was a tax on gross oil
production and that it reflected the gross value at the
point of production. He stated that there were a number of
advantages to removing progressivity. He offered that the
issue of "decoupling" had arisen specifically due to the
inclusion of progressivity in the production tax. He
observed that if the production tax was a flat tax,
decoupling would not be an issue. He stated that using a
flat severance tax and incorporating progressivity at the
gross level solved the problem of decoupling without having
to undergo the administratively more complex solution that
was in CSSB 192. Currently, CSSB 192 specified that
production and costs for oil and gas had to be separated
and presumably required companies to submit two different
tax returns. He reiterated that a progressive severance tax
referred to when progressivity was taken out of the
production tax and was instead levied on the gross level.
He added that a second benefit of having a progressive
severance tax was that it allowed for more flexibility in
incentivizing new production; however, as long as
progressivity remained part of the profit-based production
tax, incentivizing new production was significantly more
difficult. He explained that under the existing system,
there were few options for incentivizing new production;
one incentive could be a dollar amount allowance that would
be subtracted from the production tax value for "new oil."
He discussed the different ways of defining what new oil
was. He stated that regardless of how new oil was defined,
the mechanism in the existing system that provided
incentives for new production was complex; taking
progressivity of the base production tax and levying it on
a gross level created greater flexibility with incentives.
He offered that if an entity wanted to provide a very high
level of incentives for production from new areas, the
severance tax could be structured to only apply to existing
fields; new fields could have a zero severance tax and
would only pay the 25 percent flat base tax. A lower level
of severance tax could also be applied to new areas or to
production over the base level. He shared that the HB 110
(new), the six percent severance tax, and the 25 percent
flat tax options represented hypothetical exercises and
that while they served an analytical purpose, the dollar
values might not reflect reality; the three options were
included to provide different ways of structuring a system
in order to incentivize new production.
2:29:48 PM
Co-Chair Stedman asked for a clarification on slide 2 and
inquired if the "total federal take" reflected the total
government take in dollars. Mr. Mayer responded in the
affirmative. Co-Chair Stedman queried why the industry take
was not included on the table. Mr. Mayer responded that PFC
Energy would include the requested information in the
future. Co-Chair Stedman queried if the slide's revenue
comparisons represented the current production in legacy
fields, the aggregate of all production, or new production.
Mr. Mayer replied that the slide's revenue reflected FY 13
data, including the production and cost levels, after it
was run through PFC Energy's model. He added that anytime
revenue figures were presented, the information reflected
FY 13 data. Co-Chair Stedman remarked that the slide used
the "homogenized" FY 13 data from the Revenue Sources Book.
He inquired if the values of the legacy fields and smaller
producers would reflect a different set of numbers than the
aggregated numbers on the slide. Mr. Mayer responded that
Co-Chair Stedman was correct.
Co-Chair Stedman inquired what direction the presentation
would go later in the meeting. Mr. Mayer replied that the
presentation would examine the regimes on slide 2 in terms
of their levels of government take and revenue to the
state. He added that the presentation would conclude with
an analysis of the marginal rates in the same regimes.
Mr. Mayer discussed the slide on page 3 titled "ACES
(existing producer)." He stated that the upper left graph
depicted a cash flow analysis for a 200,000 bbl/d producer,
under the existing system, with recent cost levels and a
six percent decline curve; it also showed different
economic metrics regarding the Net Present Value (NPV) at
different prices. He stated that the top right graph showed
the level of government take at different price levels; the
red showed the total government take and the blue reflected
the total state share. Based on a price spread from $100 to
$230 per barrel, the slide's scenario had total government
takes ranging from 75 percent to 83 percent. The
percentages on the top right table represented the
divisible income and were added horizontally to the get the
total state or government takes. He related that the bottom
right chart depicted the percentage levels of government
take, while the bottom left chart showed the percentages in
terms of dollars.
2:35:03 PM
Mr. Mayer discussed the slide on page 4 titled "HB 110
(existing producer)" and offered that companies had
referred to HB 110 as the "threshold for meaningful
reform." He observed that at a price of $100 per barrel, HB
110 would have a government take of about 67 percent; at
higher price ranges, it had a maximum level of government
take of 71 percent. He explained that the slide's lower
government take resulted in a corresponding effect of the
cash flow line rising and the NPV going up.
Mr. Mayer discussed the slide on page 5 titled "CSSB 192
(existing producer)." He stated that under this scenario,
there was very little difference in the government take
below the $100 per barrel price level and that the 75
percent government take had dropped to 74 percent [Both
statements were made in comparison to slide 3.]. He offered
that the slide's one percent drop in government take was
probably a function of rounding and that in reality the
change was even smaller than the slide showed. He stated
that the scenario did see changes to the government take at
higher price levels and that its maximum level of
government take flattened out at 79 percent to 80 percent.
He added that the slide depicted a life cycle analysis and
that it reflected the effect of inflation on some of the
nominal thresholds; PFC Energy factored in the inflation
and saw the government take flattening out at an oil price
around the mid-$100s per barrel. He furthered that if the
slide had been forecasted solely on FY 13 basis, the
flattening effect would probably not occur until the $230
per barrel level; in that respect, there was relatively
little difference between CSSB 192 and ACES as it currently
stood.
Mr. Mayer explained the slide on page 6 titled "CSSB 192
with 50 % cap (existing producer)." He stated that if a
maximum rate cap of 50 percent were put in place of the 60
percent cap, the levels of government take were "very
slightly" reduced at a price of $100 per barrel. He offered
that under a 50 percent cap, the levels of government take
remained flat in the mid-70 percent range, whereas the
current form of CSSB 192 was projected to have almost an 80
percent government take at higher price levels. He stated
that lowering the cap to 50 percent minimized the extent to
which upside was reduced at high oil prices, such as prices
above the $120 to $130 per barrel level; however, the 50
percent cap did not have a large effect at price levels
below $120 per barrel.
Mr. Mayer explained the slide on page 7 titled "CSSB 192
with 40 % (existing producer)." He stated that if the
maximum rate cap was lowered even further to 40 percent,
there would be a flattening of out of government take
"altogether". He furthered that the 40 percent cap would
result in a more neutral system that had a 69 percent to 70
percent government take at almost all of the price levels.
He concluded that "correspondingly, in each of these cases
we see the net present value for each of these portfolios
rising."
Co-Chair Stedman asked for a clarification on slide 7. He
noted that at $40 per barrel, the slide's NPV was $2.588
billion in comparison to ACES' NPV of $2.812 billion at the
same price level. He requested an explanation of the
slide's NPV table. Mr. Mayer stated that at $40 per barrel,
the value of the portfolio was reduced under CSSB 192 in
comparison to ACES; he added that the reduction was a
function of CSSB 192's higher minimum level of tax. He
explained that while current regime had a four percent
minimum tax at lower price levels, CSSB 192 set a minimum
tax of ten percent for certain larger producing assets. He
concluded that at $40 per barrel, the NP was lower in all
of the CSSB 192 options than it was under ACES. By
contrast, the NPVs of ACES and the CSSB 192 were similar at
$60 per barrel; the similarity was a function of
progressivity not coming into play at the $60 per barrel
price level, given the costs. He stated that at the $100
per barrel level, there were modest differences in NPV
between ACES and the CSSB 192 options.
2:40:24 PM
Mr. Mayer explained the slide on page 8 titled "30% base
rate, 0.02% progressivity, 40% cap (existing producer)." He
shared that the slide presented an option that had
previously been discussed in the committee. The slide's
option proposed to raise the base rate in CSSB 192 to 30
percent from 25 percent and to substantially lower
progressivity to 0.2 percent from 0.4 percent. He pointed
out that the slide had a typographic error and that the
0.02 percent figure, which was in the title of the slide,
should be at 0.2 percent. The scenario also instituted a 40
percent cap on the minimum rate. The slide's analysis
showed that compared to slide 7, reducing the progressivity
to .2 percent and adjusting the base rate to 30 percent had
relatively little difference at most price levels; he
offered that the NPVs on slides 7 and 8 were almost
identical at prices above the $100 per barrel level. He
observed that at $60 per barrel, slide 8's addition of the
increased base rate and the lower progressivity feature
resulted in a "notably reduced" NPV in comparison to slide
7, which only had the 40 percent cap; by contrast, there
was relatively little difference between the NPV of slides
7 and 8 at even lower price levels, such as $40 per barrel.
He stated that at $40 per barrel level, the "floor binds"
and that it was the floor, and not the progressivity scale,
that ultimately set the government take at that price
level.
Co-Chair Stedman inquired if the $50 to $70 dollar per
barrel price range was the point at which the 30 percent
base rate began "pushing the present values under water."
Mr. Mayer responded that Co-Chair Stedman was correct.
Mr. Mayer offered that a possible benefit of increasing the
base rate to 30 percent was a reduction to the marginal
rates under the production tax system. He added that high
marginal rates had been perceived as a problem with the
production tax system. He warned that addressing marginal
rates with a solution that worked in the $50 to $70 per
barrel range would worsen the economics on projects and
would be a solution with a worse impact than the problem
that it solved. He added that the next several slides would
examine the 50 percent cap, the 40 percent cap, and the 30
percent base rate options as they would apply for new
developments and that the 30 percent base rate option
experienced a notable worsening of the NPV at the $40 to
$60 per barrel price level for new developments.
Mr. Mayer discussed the slides on pages 9, 10, and 11. The
three slides simulated the same options as slides 6, 7, and
8 but for new developments. He offered that slides 9, 10,
and 11 showed the same "significant worsening" of NPV at
lower price ranges that could be seen on slides 6, 7, and
8; this was particularly true at around a price of $60 per
barrel. The drop in NPV also occurred at the $40 per barrel
level because the language in CSSB 192 specified that the
floor level of production value only applied to large
existing fields, as opposed to smaller new developments. He
concluded that for new developments, the negative impact of
the higher base rate extended to the lowest price ranges
because the floor level of taxation was not an issue.
2:46:11 PM
Mr. Mayer explained the slide on page 12 titled "severance
tax- 20% maximum (existing producer) .25 % progressivity
from $70 to $130, then .10% progressivity to 180." He
stated that the slide showed what SB 192 would look like if
progressivity were removed from the production tax and a
severance tax was implemented. He explained that a
severance tax was based solely on production volumes and
that it was progressive over price. He related that he had
spent some time examining how the different progressivity
thresholds and rates for a severance tax would work. He
explained that the slide modeled a severance tax that was
levied on the gross value at the point of production; all
the prices quoted on the slide were under the definition in
the legislation of the gross value at the point of
production. He furthered that the gross volume and the net
of royalties were what was being taxed on the slide. He
stated that model's tax started at a zero rate and that it
did not kick in until the $70 per barrel price level; with
each $1 increase above $70 per barrel, progressivity
increased by .25 percent. He furthered that the
progressivity in the tax reached a local maximum of about
16 percent at $130 per barrel, and that for every $1 price
increase from $130 to $180 per barrel, the progressivity
increased at a lower rate of .1 percent; the progressivity
reached its maximum rate of 20 percent at $180 per barrel.
He explained that the model had a similar government take
profile as the two 40 percent cap options on slides 7 and
8, but that it enabled an easier method of addressing the
decoupling issue and allowed for particular incentives to
be made for new production. The purple bar represented the
severance tax and the yellow bar represented the production
tax. The yellow of the production tax had a flat profile
because the model had a flat 25 percent production tax. He
stated that the model would normally be a slightly
regressive regime because of the impact of the fixed
royalty, but that the severance tax made it slightly
progressive. He added that the model was "ever so slightly
progressive," but that it was largely fixed around the 70
percent government take level.
Co-Chair Stedman asked for a clarification on slide 12. He
observed that at a price of $40 per barrel, the slide's NPV
was lower than the NPV in the ACES existing producer
scenario, which was on slide 3. Mr. Mayer responded that in
the case of a $40 per barrel price, the NPV on slide 12
should be similar to NPV under CSSB 192, which was on slide
5. Co-Chair Stedman queried what basis slides 3, 5, and 12
were run on. Mr. Meyer responded that slides 3, 5, and 12
had all used 200,000 bbl/d as the basis for production. He
stated that at $40 per barrel, the NPV on slide 12 should
be identical to the NPV on slide 5. He related that there
was a decrease to the NPV when you compared, at $40 per
barrel, the NPV of slide 12 to the NPV of ACES on slide 3.
He stated that slides 5 and 12 were modeled on CSSB 192,
which had a higher price floor; the reduction in NPV at $40
per barrel was a direct result of the higher price floor.
2:51:42 PM
Co-Chair Stedman clarified that the effect of the floor was
responsible for moving slide 3's NPV of $2.812 billion down
to $2.587 billion, which was the NPV on slide 12. Mr. Mayer
responded that Co-Chair Stedman was correct.
Co-Chair Stedman inquired if PFC Energy could run the
models with the NPV displayed in $10 increments from $40
per barrel upwards. Mr. Mayer responded that PFC could
accommodate the request.
Co-Chair Stedman requested a clarification regarding the
lower right hand chart on page 12 and inquired if the chart
implied that the split of profit oil between the producers
and the state remained constant at $130 per barrel and
onwards. Mr. Mayer responded that Co-Chair Stedman was
correct. Co-Chair Stedman queried if this meant that "both
dollars increase as the price advances, and/or decrease."
Mr. Mayer responded in the affirmative.
Co-Chair Stedman related that how do deal with the split of
profit oil when oil prices were high was major issue that
the committee had been struggling with.
Mr. Mayer stated that one of the advantages of taking
progressivity out of the production tax and instituting a
gross progressive tax was that it made the issue of
decoupling easier to deal with; the other advantage was in
regard to the ways new production could be incentivized. He
noted that the following two slides would cover options for
incentivizing new production and that it was useful to
think of the slides in the context of regimes that might be
put in place for entirely new areas and new producers.
Mr. Mayer discussed the slide on page 13 titled "severance
tax - 6 % maximum (existing producer) .05 percent
progressivity from $70 to $190." He stated that for new
production, the severance tax could be reduced to have a
maximum rate of six percent. He added that the tax would
start with a zero base and have .05 percent progressivity
for each $1 price increase from $70 to $190 per barrel; the
maximum rate would remain flat at six percent at prices
over $190 per barrel. He stated that the government take
figures for this scenario would be around the mid-60
percent range.
Mr. Mayer explained the slide on page 14 titled "25 percent
production tax." He related that if the state wanted to
incentivize entirely new developments, it could take out
the progressive severance tax and institute nothing but the
25 percent flat production tax; this scenario would see a
reduction in government take to the 63 percent or 62
percent level. He explained that the 25 percent flat tax
option could be instituted on an indefinite basis or it
could be for particular time period, such as the first ten
years of production. He stated that production from new
areas, production from particular initiatives' agreed plans
and development, and oil production that was above a set
decline curve were three types of new production that an
entity might wanted to incentivize. He added that for any
of those three options, incentivizing could involve
tweaking and a combination of the two options on slides 13
and 14, and that how this would be done depended on how
great an incentive one wanted to provide. He concluded that
removing progressivity and instead levying a gross
production tax enabled incentivizing because it simplified
the accounting that went into the production tax; under
this system, it was simply a question of how many barrels
were produced and what the oil price was.
2:56:49 PM
Mr. Mayer explained the slide on page 15 titled "assessing
10 different fiscal regime options." He stated that the
slide showed the dollar figures that were associated with
the options. He related that in terms of production tax
revenue and at a $100 per barrel basis, ACES generated
about $3.7 billion in comparison to the $2.7 billion
generated by HB 110. He reiterated that industry had
testified that HB 110 was "threshold for meaningful
reform." The three options that were modeled on CSSB 192
reduced the production tax revenue from ACES to just over
$3.5 billion. He related that the two CSSB 192 options that
kept the base level the same had identical results to ACES
at the $60 per barrel level, higher results at $40 per
barrel, and generated significantly less revenue at
"extremely high" price levels. He stated that the severance
tax could be reworked to determine at what point it should
kick in, whether it should have a zero or small base, and
what its progressivity coefficient would be. He stated that
at the $40 and $60 per barrel price levels, the options
that used a 25 percent base rate had identical results
because the only thing occurring at those price levels was
the base rate. In the 20 percent severance tax option,
revenue was reduced to a little above $3 billion at $100
per barrel; at the prices of $150 and $200 per barrel, the
option had similar revenue in comparison to some of the
capped CSSB 192 variants. He related that for particular
fields that were being incentivized through the six percent
lowered severance tax and the 25 percent flat tax options,
it was not accurate to think of the figures in terms of
revenue to the state; these options showed what the reduced
numbers would look like and how they would compare to the
15 percent reduced rate for new production, which was in HB
110.
Co-Chair Stedman discussed slide 15 and pointed out that at
a price of $100 per barrel, there was a significant spread
between the $7.2 billion in state take that was generated
by ACES and the $6.6 billion in state take that the 20
percent severance tax option generated. He inquired how the
severance tax model could be changed in order to get close
to the $100 per barrel cash position of ACES. He noted that
the 20 percent severance option "deteriorated" above $100
per barrel and got "even worse" at extremely high prices.
He requested Mr. Mayer to run the 20 percent severance
scenario with a progressivity rate that was north of .25
percent. Mr. Mayer responded that he would do so. He added
that the 20 percent severance option was the closest
structure that he had found in terms of matching the
percentage of government take figures, but that through
further manipulation, the option could be adjusted to get
closer to the levels of revenue the state currently had at
$100 per barrel; one way of doing this was to impose a
small base on the severance tax instead of having a zero
base rate, as well making other changes to progressivity.
3:01:52 PM
Co-Chair Stedman pointed out that the steeper the
progressivity was, the more it impacted marginal tax
structure. Mr. Mayer responded that Co-Chair Stedman was
correct. He added that there were a number of factors that
had led him to start with the 20 percent severance option,
but that it could be refined.
Co-Chair Hoffman requested that future slides show $10
increments between the price levels of $100 and $150 per
barrel.
Co-Chair Stedman observed that the split of profit oil
would probably be frozen at prices north of $150 per
barrel. He requested that future slides show $10 increments
from $60 to $150 per barrel. Mr. Mayer responded that he
would provide the requested information.
Mr. Mayer discussed the slide on page 16 titled "revenue
from production tax under different options" and stated
that the slide graphically depicted the dollar figures from
the previous slide. He related that the top two lines
reflected ACES and CSSB 192 and that the two regimes had
little difference between them. The next line down, which
was navy blue with diagonal crosses on it, was the CSSB 192
50 percent cap option; this option was identical to CSSB
192 at the $140 per barrel level, but "diverges" from that
point onward. He noted that the CSSB 192 40 percent cap
option, which was represented by the pink line with the
vertical bar, was also identical to CSSB 192 until about
the $110 per barrel level, but that it diverged from that
point onward. He observed that the CSSB 192 40 percent cap
option generated significantly higher revenue than HB 110
at the $110 per barrel level, but had slightly less revenue
than HB 110 from the $180 per barrel level and onward. He
related that the 20 percent severance tax option, which was
reflected by the light pink line, was a little above HB 110
at high price levels, but that it converged with HB 110 at
the "top of the deck"; at the $100 per barrel level, the 20
percent severance option was much closer to CSSB 192 than
HB 110 was. The bottom three lines represented what some of
the incentives for new production could look like. The
electric blue line with the triangle marker represented
what HB 110 would look like with the incentive for new
production. The lighter blue line represented the six
percent severance tax option. He related that at around the
$160 per barrel level, the six percent severance option
generated higher revenue than HB 110 because of HB 110's
low 15 percent base rate for new production; however, at
the highest price levels, the six percent severance option
was below HB 110 in terms of revenue. He related that from
$130 per barrel and upwards, the 25 percent flat tax option
had a lower level of taxation than HB 110's new production.
3:06:55 PM
Co-Chair Stedman inquired if the chart was based on 200,000
bbl/d in production. Mr. Mayer responded that any analysis
that included dollar figures would be based on the FY 2013
numbers. Co-Chair Stedman clarified that the chart was
based on FY 2013 numbers. Mr. Mayer responded that Co-Chair
Stedman was correct.
3:07:18 PM
AT EASE
3:20:41 PM
RECONVENED
Mr. Mayer discussed the slide on page 17 titled "total
state take under different options" and stated that it
depicted the data equivalent to slide 16 in total state
take. He explained that slide 17 was similar to slide 16,
but that it had less differentiation because of the other
sources of revenue that accrued to the state.
Mr. Mayer stated that the next set of slides would examine
the marginal take under each of the regimes that had been
examined.
Mr. Mayer explained the slide on page 18 titled "ACES -
marginal take (FY 2013 data)." He noted that one of the
criticisms of the existing ACES system was how high the
marginal government take could be, particularly at the
current prices levels. He added that the slide included not
just the production tax, but that it also calculated all
the components of the regime combined. He observed that
ACES generated a peak in marginal government take of more
than 90 percent at the current price levels of ANS west
coast crude; currently, for every $1 increase to the price
of ANS west coast crude, the state was retaining 90
percent. Co-Chair Stedman commented that the rate would
decline soon.
Co-Chair Stedman requested that the effective tax rates be
represented on the charts when future options were
presented to the committee. Mr. Mayer replied that he would
provide the requested information.
Mr. Mayer discussed the slide on page 19 titled "HB 110 -
marginal government take (FY 2013 data)." He stated that HB
110 would put a bracketing system in place that would
enable it to substantially reduce the marginal levels of
government take; this scenario had a marginal government
take below 70 percent for all price ranges.
Mr. Mayer explained the slide on page 20 titled "CSSB 192 -
marginal government take (FY 2013 data)." He stated that
CSSB 192 looked very similar to ACES and that it also had a
marginal government take that peaked above 90 percent. The
peak occurred at slightly higher price range in comparison
to ACES because of the .35 coefficient.
Mr. Mayer discussed the slide on page 21 titled "CSSB 192
with 50% cap - marginal government take (FY 2013 Data)" and
observed that it did not have a significant difference in
comparison to ACES regarding the peak of the marginal
rates. After the 50 percent cap option's marginal peak,
which was around the $130 per barrel level, the marginal
take flattened out because the progressivity did not
increase past the 50 percent rate.
Mr. Mayer explained the slide on page 22 titled "CSSB 192
with a 40 % cap - marginal government take (FY 2013 data)."
He stated that reducing the maximum rate to 40 percent
would, in part, address areas of the marginal take issue;
the system still had a peak that was characteristic of a
non-bracketed progressivity system, but the peak occurred
at the low-80 percent level instead of at 90 percent and
above; the change to where the system's marginal take
peaked was a result of lowering the maximum rate to 40
percent.
Mr. Mayer discussed the slide on page 23 titled "30 percent
base rate, 0.02 % progressivity, 40 % cap - marginal
government take (FY 2013 data)."[Mr. Mayer had previously
pointed out that the .02 percent in the slides was a typo
and that it should be .2 percent instead.] He stated that
this scenario reduced the peak of the marginal government
take to the mid-70 percent range. He pointed out that the
scenario had worsened project economics for all assets,
particularly at around the $60 per barrel level and for
small high cost developments. He added that under this
model, small high cost developments might not trigger
progressivity, even at higher prices, because of their high
cost structure.
3:25:51 PM
Mr. Mayer explained the slide on page 24 titled "severance
tax - 20 percent maximum - marginal government take (FY
2013 data)" and stated that following this structure
resulted in a peak of marginal tax rates around the 80
percent rate.
Mr. Mayer discussed the slide on pages 25 titled "severance
tax - 6 % maximum - marginal government take (FY 2013
data)." He explained that the six percent maximum severance
tax rate was for incentivizing new production and that the
marginal rates dropped even further on this slide in
comparison to previous slides.
Mr. Mayer explained the slide on page 26 titled "25% flat
production tax - marginal government take (FY 2013 data)."
He stated that the slide's flat 25 percent production tax
for particular categories of new production resulted in a
flat marginal government take that was slightly over the 60
percent level.
Mr. Mayer discussed the slide on page 27 titled "regime
competiveness: average government take." He pointed out
that there was an error in one of the data points and that
he would provide a correction. He explained that HB 110 was
represented too low on the slide because the 15 percent
base rate for new production, rather than the 25 percent
rate, had been applied; HB 110 should be around the 67
percent rate on the slide rather than the low-60 percent
range. He apologized for the error.
Co-Chair Stedman noted that the slide could be reprinted in
the future and that there were other modifications that
needed to be done to several slides.
Co-Chair Stedman requested that PFC Energy tweak the
numbers in the 20 percent severance option in order to work
with the balance between the marginal and effective tax
rates; He furthered that he wanted the option worked so
that the state's current cash position did not change at a
price of $100 per barrel. Mr. Mayer responded in the
affirmative.
Mr. Mayer continued to speak to slide 27 and stated that an
ACES existing producer was only a little below Norway,
which was the slide's highest taxing OECD jurisdiction. He
stated that as the caps of 50 percent and 40 percent were
implemented on progressivity, the government take levels
dropped closer to the 70 percent mark. He furthered that as
it was currently structured, the 20 percent maximum
severance tax option put Alaska just above Haynesville,
which was the highest of the slide's North American onshore
producers. He explained that under the slide,
unconventional production from Haynesville, Louisiana had
a government take in the high-60 percent range and that the
20 percent severance tax option reached 69 percent. He
pointed out that potential changes to the 20 percent
severance option could increase the expected maximum rate
slightly. He related that if the 25 percent flat production
tax was offered as an incentive for incremental production
from new and existing fields, the government take could be
in the low-60 percent range for that increment and would be
competitive.
3:30:30 PM
Co-Chair Stedman pointed out that the flat tax option also
showed the effect of a 25 percent base tax, which had no
progressivity, in order to show a comparison of tax
structures. He requested that PFC Energy change the x axis
and "bring it in" to $150 per barrel, tweak the 20 percent
severance option, and show comparisons of the marginal and
effective tax rates in percentages and dollars.
Co-Chair Stedman discussed the following meeting's agenda.
SB 192 was HEARD and HELD in committee for further
consideration.
ADJOURNMENT
3:32:14 PM
The meeting was adjourned at 3:32 PM.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 192 PFC Alaska Senate Finance - March 27, 2012.pdf |
SFIN 3/27/2012 1:00:00 PM |
SB 192 |