Legislature(2011 - 2012)HOUSE FINANCE 519
04/23/2012 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| HB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB3001 | TELECONFERENCED | |
HB 3001-OIL AND GAS PRODUCTION TAX
1:43:46 PM
CO-CHAIR SEATON announced that the only order of business would
be HOUSE BILL NO. 3001, "An Act relating to adjustments to oil
and gas production tax values based on a percentage of gross
value at the point of production for oil and gas produced from
leases or properties north of 68 degrees North latitude;
relating to monthly installment payments of the oil and gas
production tax; relating to the determinations of oil and gas
production tax values; relating to oil and gas production tax
credits including qualified capital credits for exploration,
development, or production; making conforming amendments; and
providing for an effective date." He noted that this was the
second meeting of the day. He pointed out that the minutes from
an earlier mentioned U.S. Senate meeting had been distributed to
members.
1:45:32 PM
WILLIAM BARRON, Director, Central Office, Division of Oil and
Gas, Department of Natural Resources, presented a PowerPoint
entitled "Decline Curves." Directing attention to slide 2
entitled "Decline Curve Shapes: Semilog Rate-Time," he stated
that decline analysis is a foundation of the oil and gas
industry and is used for rate projections and reserve
determinations. He explained that typically there are three
decline curves, which are exhibited on the graph on slide 2.
The curves reflect an exponential decline, a hyperbolic decline,
and a harmonic decline. The harmonic decline is special and not
seen very often, while the exponential decline is very typical,
and many people have suggested that Prudhoe Bay is exhibiting a
hyperbolic decline. However, he noted that [the decline curve]
changes over time.
1:47:27 PM
REPRESENTATIVE TUCK asked if it would be true to say that
Prudhoe Bay had been in an exponential decline, but progressed
into a hyperbolic decline.
MR. BARRON explained that decline analysis is a strong indicator
of future production and future cumulative recovery, but the
mechanisms are reservoir generated and focused. He clarified
that often it is not clear until later in the decline whether it
is a hyperbolic or exponential decline. As a field matures and
advances, the parameters can be changed based on EOR, water
flood, gas cap injection, and etcetera. Some would view Kuparuk
as an exponential decline and Prudhoe Bays as a hyperbolic
decline. However, such dialogue is "slicing thin hairs." Mr.
Barron specified that he merely wants to relate that there are
different declines and they are more representative on a semilog
plot than a Cartesian plot, which speaks to Co-Chair Feige's
question yesterday regarding whether the Prudhoe Bay curve is
flattening. The Prudhoe Bay curve looks as if it's flattening
due to an aberration with the Cartesian plot, which is
compounded because later in its life it looks like a hyperbolic
rather than a linear exponential [decline curve].
REPRESENTATIVE TUCK inquired as to the circumstances regarding
the rarely seen harmonic decline.
MR. BARRON offered to share more details at a later date.
REPRESENTATIVE HERRON asked if the proposed legislation,
HB 3001, is seeking a harmonic decline.
MR. BARRON said that is difficult to answer as the decline graph
is a reservoir delivery evaluation. The tie to a commercial
term is very vague and maybe not at all. He opined that the
legislation is attempting to flatten out the decline curve by
"bringing more production on." He noted that later in the
presentation he has an example that might help answer the
question in that when a certain amount of work is done and the
decline [curve] is changed, it will then return to the decline
after the work is complete.
REPRESENTATIVE SADDLER asked what conclusion should be drawn
from the first slide.
MR. BARRON, noting the formulas listed on the slide, said that
he wanted to illustrate that there is very sound math and
science associated with decline curve analysis.
1:51:44 PM
MR. BARRON moved on to slide 3 entitled "Items Affecting
Production" and listed well drilling, well maintenance, enhanced
oil recovery, new facilities and infrastructure,
debottlenecking, and new technologies as means for increasing
production. He stated that new technologies are introduced
every day and it is the blending of these new technologies that
bring advances that allow old fields to be maintained in the
future as well as bring on other fields.
REPRESENTATIVE GARDNER requested an explanation of
debottlenecking.
MR. BARRON explained that debottlenecking refers to changing the
size of pipes and valves to allow more production through the
system. Without debottlenecking, a decrease in production can
occur. He offered an example in which engineers and
geoscientists determine that a 1,000 barrel a day facility is
all that is necessary to produce an oil field and that facility
is built. Typically, at the inception of a 1,000 barrel of oil
field there would be 900 barrels of oil and 100 barrels of
water. As the field matures, the water to oil ratios could
change such that there could be 900 barrels of water and 100
barrels of oil. Such changes would require debottlenecking to
change the size of the pipes to allow the increased or decreased
amounts of oil and water to maintain the flow. For those large
processing facilities, pressure gauges are utilized throughout
the system to find major pressure drops and address them because
all pressure is more back pressure on the well that causes it to
be a lower producer. The aforementioned is another example of
debottlenecking.
1:55:34 PM
MR. BARRON, returning attention to slide 3, said that aging
infrastructure, gas and water handling facilities, well
failures, overall cost structure, and a decrease in new rate
production would all lead to decreasing production.
REPRESENTATIVE TUCK inquired as to how much more oil production
would be associated with delivering 2 billion cubic feet (bcf)
of gas.
MR. BARRON explained that, for a field such as Prudhoe Bay, more
energy going in increases oil production. Therefore, an off
take of 2 bcf for gas production would result in a decrease in
oil production. The aforementioned is why the Alaska Oil and
Gas Conservation Commission (AOGCC) is concerned with any
withdrawals of gas from the Prudhoe Bay reservoirs. For all
systems, the more energy kept in the system the easier it is for
the oil production to come out.
CO-CHAIR FEIGE inquired as to the impact to the recovery of
Prudhoe Bay in a scenario in which another source of gas outside
the Prudhoe Bay field, such as Point Thomson, is found, it is
injected, and it raises the pressure of the Prudhoe Bay field.
MR. BARRON replied that anything, including gas from another
source or water, could be injected to fill the void left from
the withdrawal of oil, in order to re-build the pressure. In
fact, some of the initial modeling results he has reviewed from
the operators illustrate an uplift of oil production from a
Point Thomson injection. Again, it does not matter from where
the gas comes the goal is to maintain reservoir energy.
REPRESENTATIVE P. WILSON asked how this correlates to heavy oil.
MR. BARRON replied that the discussion focused on the recovery
of oil from the main body for Prudhoe Bay. A discussion
regarding viscous oil would revolve around the concern about the
ability of the oil to flow through the rock. Clearly,
maintaining reservoir energy in that regard is beneficial, but
it is less traumatic than it is to merely move and extract the
fluids from the rock in a viscous state.
2:00:00 PM
REPRESENTATIVE LYNN asked whether the injection gas is more
advantageous than the injection of water or vice versa, in terms
of oil recovery.
MR. BARRON replied yes. He explained that typically reservoirs
contain a gas column, an oil column, and a water column, and the
goal is to maintain the energy associated with the overall
reservoir. Therefore, normally one would inject gas into the
gas column and water into the water column to maintain full
pressure for oil recovery. He reported that it is easier to
push oil with water than it is to push oil with gas, but it is
necessary to simultaneously maintain the gas pressure.
REPRESENTATIVE LYNN asked what the best alternative is in the
context of HB 3001.
MR. BARRON answered that it is a combination of both gas and
water injection.
REPRESENTATIVE PETERSEN related his understanding that there can
be too much natural gas pressure, which makes a field difficult
to develop as is exhibited at Point Thomson.
MR. BARRON replied that Point Thomson is a very complicated
reservoir that those in the industry would describe as a
retrograde condensate, which requires a constant balancing of
the reservoir pressure. He explained that in a pressure-volume-
temperature phase envelope, which considers the component of the
product itself, at high pressure with constant temperature,
reservoir pressure can be decreased such that the product moves
from a gas phase to a liquid phase. For a retrograde
condensate, if the reservoir pressure continues to drop, the
product can return to a gas phase. Another problem with Point
Thomson is that a high pressure reservoir is extremely costly to
maintain the pressure at a level that keeps the gas in a gas
phase rather than a liquid phase or, in a gas cycle, drop the
pressure of the reservoir such that the liquids can be stripped
out at very elevated pressures through the surface facilities.
2:04:00 PM
MR. BARRON, returning to his presentation, directed attention to
slide 4 entitled "PBU Initial Participating Area," which depicts
the 9.9 percent annual exponential decline in Prudhoe Bay. He
explained that this graph reflects a work case decline, as
opposed to a no-work case, as it includes every well, piece of
equipment, work-over, and recompletion. He noted that some of
his team is reviewing how to peel those components in order to
determine the real decline of a no-work case.
2:06:02 PM
MR. BARRON moved on to slide 5, "PBU Initial Participating
Area," which indicates the resulting changes during the
timeframe when water is injected into the gas cap. Over two to
three years there is a 3.5 percent decline, which is why some
would say a hyperbolic decline is being exhibited in as much as
a lot of parameters of the field have been changed by doing a
lot of work. He pointed out that it took, starting in 2004,
almost four years to see any of the benefits to production from
that capitalization. He declared that, as the parameters of the
field were changed, the decline was altered. He stated that the
goal is to create a fiscal regime to encourage the overall
development and longevity of the field. However, one must be
mindful that recognizable results for these capital investments
can take five to seven years.
2:07:38 PM
REPRESENTATIVE GARDNER, directing attention to slide 5, asked
whether the green dots from 2007-2011 on the graph are the
result of funds spent in 2003 or earlier or from 2001 decisions.
MR. BARRON answered that the green dots are the direct result of
investments made in 2002-2003 by putting the facilities in to
put water in the gas cap at the IPA. The design, engineering,
and capital projects were done in 1999 - 2004, but the benefits
were not recognized until 2007. Some projects have a long lead
time in terms of seeing any benefit, he remarked.
2:08:59 PM
MR. BARRON moved on to slide 7 entitled "Kuparuk River Unit -
Kuparuk Participating Area," declaring it to be the second
largest oil field in North America. He stated that this graph
clearly reveals a 10 percent exponential decline for the Kuparuk
River Unit. Moving on to slide 8, he reflected on the dramatic
change in the decline curve from 10.5 percent to 7.5 percent,
which he primarily attributed to increased infield drilling
activities. Kuparuk is a world class water flood field and the
company developing it is performing a great deal of reservoir
management as it determines where the oil has been pushed to by
the water, making work overs, drilling new wells, and performing
recompletions necessary to capture the product. More recent
additional drilling indicates a decrease in the decline curve to
5 percent. Therefore, it is important to understand the impacts
of capitalization relative to the original base curve of the
aggregate for all the wells.
CO-CHAIR SEATON said "We've got the AOGCC development service
wells and well bores for ConocoPhillips, which as operator,
presume that those are going to be Kuparuk. ... There didn't
seem to be any uptick in wells being drilled in that timeframe
over the other timeframes that we had. And so, how are we
attributing that rate of decline to the same number of wells,
basically, being drilled in those years that they were being
drilled in previous years."
MR. BARRON, in response to Co-Chair Seaton, said that it is not
necessarily the number of wells drilled, but the location of the
wells and the location to where they are recompleted. He posed
a scenario in which there is line drive water flood reservoir
and modeling to where the oil bank is being moved. Selective
wells in selective locations can be drilled or recompletion can
be performed such that a zone or part of a zone is shut off to
increase oil production. He declared that there has not been a
major drilling increase since 2000. In fact, he recalled a
curve that relates that there has been a continuous decline in
drilling on the North Slope, save one outlier in 2004. He
informed the committee that the aforementioned means the decline
is trying to be arrested by "attacking the reservoir at the
right location." Mr. Barron related that to his knowledge there
were no other major facilities installed or major change in
reservoir management of the field, and therefore it could only
be attributed to the increase in wells brought online at that
time. He noted that it may be only half a dozen to a dozen
wells every year.
2:13:33 PM
CO-CHAIR SEATON explained that he is trying to determine if the
rate of decline is being attributed to drilling the same number
of wells as had been drilled in the previous years. However, he
related his understanding that it is being attributed to
improved technology not to increased capital spending or any
other system since capital spending in Kuparuk was basically the
same throughout those years.
MR. BARRON said that he didn't know what the capital spending
was through that timeframe. He clarified that from the
information base he has the driving mechanism in this change of
decline is based on drilling technology and the number of wells
introduced. The multi-lateral coil tubing work and the
selective workovers on existing wells have been advantages in
Kuparuk. The point, he emphasized, is that as companies
continue to work the field, they become smarter and are able to
identify which wells to bring on and which wells to turn off.
For example, in Prudhoe Bay there is a very robust reservoir
simulator through which it's predicted where the gas will break
out, and therefore the companies try to shut those wells in to
conserve energy and free up the facilities. Mr. Barron stressed
that it is a dynamic process that is reviewed on a daily basis
by engineers and geoscientists of these companies.
CO-CHAIR SEATON, referring to proposed HB 3001, questioned how a
change in the tax system [is related to an increase in
production] if it is not related to the number of wells or
increased capital spending but rather to smarter drilling and
increased technology.
MR. BARRON replied that each of the examples mentioned including
every well drilled, workovers, and new technology, is capital
driven and requires a dollar infusion into the field. The
companies are trying to employ their capital in the most
efficient manner and manage the reservoirs as prudently as
possible.
CO-CHAIR SEATON surmised then that it is not about the amount of
increased capital expended but rather the use of the capital in
the field. Therefore, he questioned how a change in the tax
regime would result in smarter employment of capital.
MR. BARRON characterized this as a "circular logic discussion."
He countered that the current use of capital had decreased the
decline of the field from 10 percent to 5 percent. If the
companies received more money to perform more work because of a
change in fiscal regime that improved their net present value
(NPV) and internal rate of return (IRR) on any given project,
the counter logic is that more money results in a flatter
production profile. He clarified that he is pointing out that
if the company had performed no work there would be an elevated
decline rate. Therefore, clearly the more money companies
receive and the more advances in technology that are employed
that result in the reduction in the decline rate from 10 percent
to 5 percent, it is not much of "a leap of faith" that the
decline rate could be flattened or even reversed. He noted,
however, that it is related to whether the smaller projects are
available and economic as time passes. Again, the Prudhoe Bay
example was a five- to seven-year project waiting for the true
value to come to the company and the state. During that time,
the oil companies were taking the risk with the product price.
He shared that the design and conceptual work is being done
today for projects that will hopefully come into play in the
next several years and those projects are still very capital
intensive. As time passes more gas and water has to be handled
for a lower return of oil production for these two major fields.
Therefore, anything the state can do to decrease costs for the
oil companies is an advantage for the state in terms of
increased production as well as more capital infusion and
expense infusion in the field. "It's how you spin it," he said.
He expressed concern with recent discussion regarding reviewing
the decline over the last two years and making that the base
because it is not the true base decline of the field, rather it
is an aberration attributable to ongoing capital work that has
had a positive impact on the life of the field.
CO-CHAIR SEATON opined that he did not believe anyone disagrees,
but indicated concern when increased drilling is specified
without the number of wells increasing and attributing it to
technological changes to production.
MR. BARRON clarified that his reference to additional drilling
simply means that work, drilling wells, is being performed, but
does not necessarily mean there has been an increase in the rate
of drilling or the number of wells. Simply put, "additional
drilling" means that more drilling occurred and more wells were
added; this is a work case rather than a no-work case.
2:21:58 PM
REPRESENTATIVE P. WILSON reflected on the pipeline shut down
during the cold weather two years ago, which is when the
producers realized how serious low production is during a very
cold period. She then asked if Mr. Barron is saying the results
of work [done by the producers] at that time might still not be
evident [in the production].
MR. BARRON explained that the concern at that time, as it was so
cold, was that it would be difficult to re-initiate production
through static line. He clarified that the problem was not with
the oil fields rather it was the re-initiation of throughput
through the pipeline. He declared that, as there is not a good
benchmark to establish a "no-work" decline in the oil fields, it
is difficult to establish any base decline rate as all the
decline curves include ongoing work. However, he noted that he
has a couple of examples of individual wells that might provide
a glimmer of what a no-work case in Kuparuk might be, which he
mentioned would be reviewed shortly.
REPRESENTATIVE TUCK opined that although a goal is to reverse
the decline, it appears that the best result would be to slow
the decline, unless new oil fields were brought online. He
asked if there is any possibility of reversing the decline in
these existing fields, or is the best scenario to slow the
decline.
MR. BARRON replied "hold that thought."
CO-CHAIR FEIGE offered his belief that any additional oil
production extends the revenue to the state. He asked if there
is a technological limit for the amount of capital investment
which would generate a corresponding increase in revenue.
MR. BARRON replied that the oil companies could offer a better
answer as they better understand the cost structure and the
benefit and reward system in their well productivity. He
expressed agreement that there is "a point of diminishing
returns."
2:26:45 PM
REPRESENTATIVE MUNOZ asked whether any current investments aim
to reduce the decline.
MR. BARRON replied yes, and characterized the work with viscous
oil as an investment in future production. For example, the
ConocoPhillips drilled well in the southwestern part of Kuparuk,
called Shark's Tooth, is an expansion of some of ConocoPhillips'
work that is an investment today that would be future
production. Furthermore, some of ConocoPhillips' gas handling
and processing facilities for debottlenecking that are being
designed today will be capitalization for future production;
this ongoing design, modeling, and engineering work is a routine
project for companies' process and product engineers. He said
the reservoir management skills of these companies are
exceptional. He offered further examples such as electrical
submersible pumps versus gas lift, location of water injection,
amount of water to inject or not inject as investments that
could be made "today" for future benefit. He emphasized that
the aforementioned are long-term projects "and this is not an
immediate gratification kind of process."
2:30:06 PM
CO-CHAIR SEATON inquired as to why the natural rate of decline
for an oil field is important to the [state]. He noted that the
committee is considering the bill to change the tax system to
provide incentives to additional economic projects beyond the
current invested capital for those already economic projects.
He requested an explanation as to why the natural rate of
decline is being reviewed since he understood that they are
already reviewing the rate of decline above what is currently
economically feasible and sanctioned.
MR. BARRON replied that his desire is for everyone to have the
same fundamental understanding with regard to what the decline
of the field is. For example, he wanted to ensure that the
decline at Kuparuk River Unit at 5 percent is the direct result
of a great deal of work and that if the case had been a no-work
scenario, the decline might have been 23 percent. Mr. Barron
reiterated the importance of recognizing the amount of work over
time as all the work is aggregated together to obtain a sense of
the magnitude of it and whether [the current decline] could be
reversed.
MR. BARRON directed attention to the graphs on slide 10 entitled
"Large Lower 48 Field, Mid Size North Slope Field," which
address an economic situation by which there is early shut in
and [the project] is no longer economic, whether it is due to
the fiscal regime, product price, or lifting costs. With regard
to the question of whether the aforementioned is a negative
impact on the field, he explained that the top graph is the
decline curve and the blue line represents 5,000 barrels a day
and a field of that size could easily contain 100 oil wells,
which amounts to 50 barrels of oil per day and 100-150 barrels
of water each day. [In the second graph on slide 10], the curve
is the cumulative production. He explained that if the economic
limit is changed by 50 percent, the total recovery would
slightly increase from 254,000 to 271,000. However, the life of
the field would be extended by over 10 years. The graphs
illustrate the impact of early shut in of a well due to
economics, which is a loss of resource in terms of total
recovery and the early termination.
2:36:11 PM
MR. BARRON moved on to slide 11 entitled "Cook Inlet Oil Well,"
which depicts graphs of decline curves in Cook Inlet and
Kuparuk. He highlighted the graph for a Cook Inlet well that
exhibits a 7 percent decline per year and informed the committee
that this well was shut in at the end of its life due to high
water cut. The well was shut in when it was at about 40-50
barrels per day, which is similar to the previous example. He
then turned attention to the second graph that is a sample
Kuparuk oil well, a single well, that has moved from its plateau
to its decline of about 23 percent. Mr. Barron clarified that
he is trying to illustrate the kind of work necessary to
maintain a level of non-decline if the cumulative Kuparuk River
Unit is in a 5 percent decline and every well drilled is in a 23
percent decline. The third graph depicts a recent application
of the new coil tubing and multi-lateral drilling technology,
which is designed to drill horizontally and capture more net pay
per well. The aforementioned [technology] exhibits about a 7
percent decline and is a well for which the new technology was
able to capture more product cost effectively than drilling
multiple wells.
REPRESENTATIVE TUCK, referring to the Cook Inlet Oil Well graph,
related his understanding that the single well was cut off at 50
barrels of oil per day over a 215-month period and was due to
the amount of water.
MR. BARRON expressed his agreement.
2:39:06 PM
MR. BARRON, returning to his presentation, said that slides 12
and 13 relate to earlier questions from Representatives Kawasaki
and Tuck. The graph on slide 12 entitled "Kenai Gas Field Daily
Production in mcf/d" exhibits actual data for the Kenai gas
field, which has a lot of natural seasonal swing due to
deliveries of gas to Anchorage. He then highlighted the
negative decline between 1991 and 1999, after which there is a
marked reversal of the decline as a result of increased drilling
in the gas field that was primarily necessary to satisfy
contractual obligations with the supply companies, Anchorage,
and the liquefied natural gas (LNG) market. He characterized
the Kenai gas field as a local exhibit of where the decline can
be reversed. Moving on to the graph on slide 13 entitled
"Forties Field, North Sea, production," he declared this curve
to be an even more pronounced example for a new operator
initiated program that reversed the decline. In response to an
earlier question by Representative Gardner, he stated that there
are over several hundred drilling rigs operating in the Permian
Basin in Texas, which are not drilling into shale. More
specifically, the Spraberry Field is experiencing a "robust
renaissance" in an area that is not shale driven. He declared
that all of these are tangible examples of areas experiencing a
"robust uptick in production."
REPRESENTATIVE TUCK, referring to slide 12, asked if the reverse
of the decline in the Kenai gas field was due to recent
exploration for gas, as opposed to the earlier exploration
solely for oil. He asked if gas and oil decline curves are
comparable.
MR. BARRON replied that gas decline analysis could also be done,
and he clarified that the initial Kenai exploration history had
been for gas, not oil, to supply the local market. He reported
that the particular operator in the Kenai gas field targeted
most of its exploration dollars associated with gas rather than
oil. However, during the last lease sale in Cook Inlet, Apache
obtained a tremendous amount of acreage as Apache believes it is
an unbelievably unexplored oil province. In fact, Apache is
going to penetrate deep for oil and the notion is that as one
seeks deep oil, one will penetrate shallow gas. In the last 20
years gas not oil has been the target in the Cook Inlet.
REPRESENTATIVE TUCK recalled in 2009 and 2010 when Pioneer
sought exploration credits for gas and presented similar
testimony.
MR. BARRON clarified that there is a difference between
exploration work and development work. The Kenai gas field is
an example of a known quantity in an existing field. He held
the Kenai gas field as an example in which focused and
concentrated effort can change a field's natural decline with
capitalization and drilling.
REPRESENTATIVE KAWASAKI asked if there are any large, mature
fields, similar to Kuparuk River Unit or Prudhoe Bay, which have
had an adjustment to their decline curve. Referring to the
Forties Field, North Sea, production graph, he inquired as to
the amount of capital investment and circumstances required to
get the uptick. He noted that the overall design of the curve
is not changed.
MR. BARRON replied that he did not have the cost figures, but he
offered to forward some information. He said that capital
improvements could improve the decline, at least for a period of
time, but that it would eventually return to the natural
decline. The point is that the Forties Field is an example in
which the influx of capital and facility modifications did
reverse the decline, at least for five to six years.
REPRESENTATIVE DICK, describing a level of futility in the
discussion, offered his belief that the legislature has the
following choices: do nothing; offer some help and hope it does
some good; get involved with details that are better understood
by the industry; or, have a good conversation regarding
incentives to get beyond the decline curve.
2:51:29 PM
MR. BARRON presented slide 15 entitled "What will it take to
reach the goal?" which, he opined, echoes what Representative
Dick has said. He declared that it is important to have a
collaborative and competitive environment with a clear
understanding for all the barriers and to define ways to
increase access to all fields, at all locations, at all times.
REPRESENTATIVE PETERSEN reminded the committee that Alaska is
competing with other oil fields. He asked if the proposed
legislation, with its accelerated depreciation, is enough of an
incentive for the oil companies to invest in Alaska sooner than
in other areas.
MR. BARRON said that he did know how much one piece of tax
legislation would work. He explained that the focus of the
Division of Oil and Gas is to "be the technical repository for
the state of oil and gas." He declared that economic levers
which increase the net present value or the rate of return are
generally viewed as favorable and could bring a project forward
to operation. He informed the committee that he has had the
good fortune to work as an operator, a contractor, and now as an
owner over the course of his 35-38 years in the oil industry.
From his years as an operator he learned that he wanted the
contractors to be financially successful because it meant the
contractor would have longevity and would lead to the contractor
having better staff and equipment. That situation is really no
different than what the state is in as the owner of the oil
fields; it is necessary for the oil producers to have success in
order to continue to invest in the fields. He declared that it
is a balance between the oil producers having success and
protecting the state's rights as the owner.
2:56:31 PM
REPRESENTATIVE OLSON asked Mr. Barron if there are any
differences between his testimony to the House Resources
Standing Committee and his earlier testimony to the Senate
Resources Standing Committee.
MR. BARRON replied no, but added that the Senate Resources
Standing Committee testimony did include discussion regarding
the capacity of facilities, facility limitations, and the use of
excess capacity by third parties.
CO-CHAIR FEIGE observed that there is a perception that newer
oil producers face a barrier in terms of access to facilities.
He asked how it works for a small producer that enters on the
fringe of a larger field and wants to use existing facilities.
He also inquired as to the impact on the new producer as well as
the facility owner.
MR. BARRON replied that it is sometimes a corporate philosophy
to piggyback on existing facilities to lower operational costs
and decrease the necessary capital, whereas other companies want
to stand alone with no impact from facility owners. The
negotiation between the facility owner and the producer seeking
use of an existing facility is a very complicated and integrated
dialogue that will revolve around the cost and the priority of
the product in the facility in the near- and the long-term.
Therefore, most operators prefer the ability to stand alone.
CO-CHAIR FEIGE, acknowledging the suggestion for the state to
mandate that facility owners accept oil from any producers,
asked if that is an appropriate policy.
MR. BARRON related his belief that should not be under the
purview of the legislature, as such a broad mandate could be
very detrimental to the existing fields in Alaska.
3:02:36 PM
CO-CHAIR SEATON, pointing out that the independent oil and gas
producers such as Brooks Range needed capital to build
production facilities, asked if the Division of Oil and Gas has
the expertise to assess a reservoir for potential reserves prior
to the state making a loan to an independent producer.
MR. BARRON replied yes.
CO-CHAIR SEATON asked if the Division of Oil and Gas could
estimate the potential for production in new fields and legacy
fields and the timeframe in which it would occur.
MR. BARRON replied that any such information would be highly
speculative. He reflected on earlier testimony regarding the
impacts of truncating the life of shale oil wells from 20 years
to 5 years, and added that such variables would be unknown and
would require a technical estimation. Brooks Range is a good
example in that the division does not know the results of the
Repsol drilling to date. Any discussions on such developments
would be broad with no specifics. On the other hand, the plans
of development for the legacy fields are available for review
and those projects that are on a plan of development are almost
always economic. The Division of Oil and Gas, however, would be
researching opportunities that are not currently on a plan of
development and are not yet recognized. He offered to
coordinate with the Department of Revenue for more information.
CO-CHAIR SEATON requested a chart for speculative information to
"new fields and potential probabilities," as that was better
than zero information. He also requested the current plans of
development, including the estimate for barrels per day of
production, for both legacy fields and new fields.
3:11:26 PM
REPRESENTATIVE HERRON, referring to slide 15, asked if there is
a priority for "minimizing these barriers."
MR. BARRON responded that each oil company would have its own
priorities for the removal of barriers. He opined that across
the board permit reform would be a priority, especially in terms
of reducing the time between issuance of the lease, exploration,
and first production, because it would have the largest impact
on the state and the companies. Therefore, barriers to
exploration and first production would likely be on the top of
the list for review.
3:13:24 PM
REPRESENTATIVE KAWASAKI requested that the forward-looking
capital expenditure forecasts be included with the request from
Representative Seaton. He expressed interest in how DNR works
with DOR in determining the five-year forward forecasts.
MR. BARRON offered to include that information.
CO-CHAIR FEIGE pointed out that statutory incentives could be
applied at different points, and asked whether a North Slope-
wide incentive for collective production targets had the
potential to encourage cooperation among the operators.
MR. BARRON replied that it is "an intriguing idea." He surmised
that the notion is to build a system in which greater production
would result in a lower tax. He offered his belief that the
idea is worthy of more dialogue as it could create an
environment of cooperation between the major oil producers, the
new players, and independent producers.
CO-CHAIR FEIGE inquired as to the best method to establish a
framework for a statutory decline curve.
MR. BARRON clarified that part of the goal with his presentation
is to relate that the decline curves cannot be interpreted
solely over the prior few years, as the decline curve has been
impacted by earlier work and investments. Therefore, it is
important to review fields over a broader timeframe to account
for the earlier work in fields that have been dynamically
managed. For example, to say that the field decline of Kuparuk
would be based on 5 percent, when an individual well in Kuparuk
might be at 20 percent may result in the creation of an
environment in which not doing anything for two years and
forcing the decline rate could result in incremental work
providing an advantage. Mr. Barron opined that introduction of
the aforementioned type of gamesmanship is not desirable.
Therefore, it is necessary to have active dialogue between the
operators and the owners.
CO-CHAIR FEIGE asked about the equation in the proposed Senate
bill. He further asked whether it is best to have the state and
industry try to agree on something.
MR. BARRON, highlighting the individuality of each decline curve
he presented today, replied that having a collaborative dialogue
is probably better than using an equation because it is not
straightforward.
3:21:03 PM
CO-CHAIR SEATON, reflecting on the small producer tax credit
that would sunset in 2016, asked if companies felt that the time
window is now too short to invest capital. He asked if there is
any opposition to a 10-year extension of this tax credit.
MR. BARRON said that he has not heard of any such concerns.
3:23:19 PM
JANAK MAYER, Manager, Upstream & Gas, PFC Energy, reminded the
committee that he had been contracted by the Legislative Budget
and Audit Committee to be the project manager for the analysis
of the fiscal term reform project.
REPRESENTATIVE TUCK recalled that Mr. Mayer has presented the
committee with the following three options: the uniform
lowering of government take, differentiation between old and new
production, and enhancements to the cost progressivity of ACES.
He further recalled that in Texas there is a reserves tax and
that the Iraqi model to increase production is unique.
Representative Tuck then requested an explanation of the Iraqi
model to increase production as that seems to be a possible goal
for the state, whereas the goal for oil companies seems to
typically be profit.
MR. MAYER, referring to the reserves tax in Texas, acknowledged
that a very small component of the Texas fiscal regime levies a
charge based on the net present value of what is left in the
ground. He said that he has never seen such a reserves tax
applied other than as a very small component of a fiscal regime.
Furthermore, he said he was not aware of anywhere that it
provides a significant incentive to develop reserves that would
otherwise be undeveloped, particularly compared to
relinquishment provisions, for instance, in contracts. He then
turned to the Iraqi service contract, which he characterized as
a relatively unique situation. The Iraqi service contract is
for large, existing fields previously owned and run by the
government who is now inviting international companies to
provide capital, technology, and service to increase production.
The contracts are structured to reward production beyond
existing production, which is usually based on a negotiated
plateau production figure, and possibly a decline, with a fee
per barrel for production above [the plateau]. He said a lot of
the terms [in the near-term] have not been favorable, but have
been engaged by companies seeking a strategic foothold in a very
large and significant reserve position in the future.
REPRESENTATIVE TUCK asked if the Iraqi government's offer for
contracts to boost new production is limited in scope to this
situation.
MR. MAYER replied that offering incentives for production above
a decline curve is a similar idea.
3:29:03 PM
REPRESENTATIVE KAWASAKI recalled that slide 28 entitled "Key
Issues" from Mr. Mayer's PowerPoint said, "Across-the-board
reduction in government take is the simplest approach, but
requires foregoing significant revenues on activities that are
currently economic." He requested an explanation for this
statement.
MR. MAYER replied that any approach in the legacy producing
assets that seeks to differentiate between base production and
something incremental, however defined, would immediately face a
host of complex questions for administration of the system and
the incentives, not to mention that ACES is already a complex
system. Therefore, there is a cost and tradeoff. On the other
hand, simply lowering government take across the board involves
serious cash in terms of more than $1 billion in fiscal year
2013. He acknowledged that the greater cost and the difficulty
of tackling some of those things are worthwhile in terms of
maintaining as much revenue for the state as possible.
REPRESENTATIVE KAWASAKI asked for suggestions to increase
production, local jobs, and capital expenditures within the
state.
MR. MAYER offered his belief that a reduction in government take
can add new production, even significant new production.
However, the question is whether it would add sufficient new
production to account for the lost revenue in doing so. He
opined that in the short term it might not be sufficient enough
production to make up for the revenue lost, but in the medium to
long term it is possible if there are significant production
increases. To avoid the risk, one would take an approach that
differentiates between existing and incremental production.
REPRESENTATIVE KAWASAKI presented a decline curve of production
compared with the production tax rate at Kuparuk River Unit,
which he declared is similar to every other legacy field in
Alaska. [The illustration] points out that even under the
Economic Limit Factor (ELF), which varied from 12 percent tax on
the gross to the almost zero tax in 2006, production still
declined. He then expressed disagreement with the argument that
tax reform is the only means for a production increase, and
offered his agreement with the Division of Oil & Gas that there
are other means to improve the economics of an oil field.
MR. MAYER expressed agreement that taxes are only one lever and
they have a certain and limited impact, particularly in the
context of high costs and other things that are outside of the
state's control.
3:34:14 PM
REPRESENTATIVE PRUITT asked if the defeat of the reserves tax in
2006 was the correct decision.
MR. MAYER said that he would need more information about the
specific reserves tax put before the voters prior to offering
any judgment.
REPRESENTATIVE PRUITT inquired as to Mr. Mayer's view on some
form of a reserves tax.
MR. MAYER replied that if an activity is fundamentally
uneconomic or so marginal as to be noncompetitive for capital,
simply punishing not doing it will not make it happen.
3:35:20 PM
CO-CHAIR FEIGE returned to the situation in Iraqi, where there
are fairly sizable reserves with porous, permeable rocks, and
lots of oil. Upon the conclusion of the war in Iraqi, the oil
production technology in Iraqi was relatively primitive.
Therefore, offering contracts to outside companies was done
primarily to raise production to a more profitable level and
obtain outside expertise.
MR. MAYER expressed his agreement.
CO-CHAIR FEIGE related his understanding that Alaska does not
have primitive oil production facilities.
MR. MAYER again expressed his agreement.
3:36:39 PM
REPRESENTATIVE TUCK offered his understanding that the reserves
tax on the Alaska ballot had been a gas reserves tax, modeled
after an oil reserves tax that had been instrumental in the
startup of the pipeline. He then redirected attention to slide
28 of Mr. Mayer's PowerPoint and inquired as to whether there is
any [guarantee] as to more production due to passage of the
proposed legislation and if so, how much more production would
it generate.
MR. MAYER said that he could not answer that question at the
moment, but offered that it is not inconceivable that there will
be the desire to lower taxes across the board and that over a
significant amount of time one could reach a point at which
sufficient new production is stimulated such that revenues
exceed what they would absent that. However, the aforementioned
is highly speculative as there are no guarantees.
3:38:52 PM
REPRESENTATIVE HERRON, referring to slide 5 of Mr. Mayer's
PowerPoint, inquired as to the number of regimes similar to the
State of Alaska.
MR. MAYER said it would depend upon the definition of similar.
REPRESENTATIVE HERRON described Alaska as a hands-off sovereign
state with no direct benefit or investment.
MR. MAYER explained that Alaska is not similar to most developed
countries with hydrocarbon resources. He said although much is
made of the contrast of state ownership in Alaska versus private
ownership in the Lower 48, in both cases someone owns the
resource and receives a royalty. Therefore, in that sense he
said he was not convinced that it is a defining feature in
Alaska. He acknowledged that Alaska is similar to the tax
royalty regimes in which the fixed royalty is extended to a
profit based tax. For example, Australia has done the most in
terms of moving from pure royalty to pure taxation "as a more
intelligent way to go about taxing the resource." In that
sense, the contrast is between tax royalty jurisdictions and
production sharing contract jurisdictions. Production sharing
contract jurisdictions are jurisdictions in which oil and gas is
produced as a result of direct contracting between the state and
the private sector in which revenue accrues to the state through
a deliberately negotiated contract that provides for long-term
stability, and thus may require no terms be changed over the
next 20-30 years. The principle dividing line between tax
royalty regimes, particularly in most of the developed world, is
the government taking a more hands-off approach and setting a
playing field to let the private sector enter versus those
regimes that seek to get the most from their assets by directly
negotiating contracts with the private sector, usually involving
a bidding process regarding the amount of government take.
REPRESENTATIVE HERRON suggested the idea that the State of
Alaska should become an investor instead of changing the tax
structure and giving money to the oil producers. He asked for
any "cautions to that thought process."
MR. MAYER cautioned that the investors understand in what they
are investing and the risks being taken with the taxpayers'
dollar. He said that he would need to study the dynamics of the
private sector players in Alaska before he could offer any
further advice.
CO-CHAIR SEATON inquired as to whether there is a downside to
the State of Alaska offering commercial terms on loans to the
smaller operators in order to stimulate oil production into the
pipeline.
MR. MAYER reiterated that the state needs to understand the
risks, especially if, for any reason, the loans are not
available commercially. Furthermore, the state should
understand the risk the private sector is not willing to bear
that the state is and accurately judging that.
CO-CHAIR SEATON surmised then that differences in interest rate,
timing, and whether there are adequate reserves should be
reviewed in terms of the risk.
MR. MAYER agreed.
3:45:20 PM
REPRESENTATIVE PETERSEN, noting that proposed HB 3001 allows
companies accelerated expense depreciation, asked if any other
oil regimes have successfully implemented such to accelerate
development and investment in the oil fields.
MR. MAYER replied that Alaska royalty, through the production
tax, already has the ability to write off expenses immediately
in terms of the production tax. However, the timeframe over
which one claims capital credits that go with spending and
enabling them to be claimed in a single year rather than
stretching it over two years. Suddenly, Alaska is a high level
of government take, notwithstanding more generous regimes, in
terms of the timeframe over which those claims are allowed.
There are many jurisdictions that have similar allowances or
approaches to credits, but require them to be claimed from
future production rather than in the current year or coming year
or two. Therefore, Alaska's Clear and Equitable Share (ACES)
works at the moment for the legacy lower cost assets, despite
the high government take, is some of the upfront loading of take
to contractors. The change from the two-year to one-year is a
small change, but a positive one from the perspective of
economics. However, alone it does not "move the dial."
3:48:53 PM
CO-CHAIR FEIGE offered that PFC could do any analysis that
committee members requested.
REPRESENTATIVE KAWASAKI asked if any information has been
received from the administration.
CO-CHAIR SEATON said that everything currently received has been
distributed to the committee.
[HB 3001 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| Decline Curves HRes Energy 4.23.12.pdf |
HRES 4/23/2012 1:00:00 PM |
HB3001 |