Legislature(2005 - 2006)CAPITOL 120
04/11/2006 08:00 AM House OIL & GAS
| Audio | Topic |
|---|---|
| Start | |
| HB498 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | HB 498 | TELECONFERENCED | |
| + | TELECONFERENCED |
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON OIL AND GAS
April 11, 2006
8:05 a.m.
MEMBERS PRESENT
Representative Vic Kohring, Chair
Representative Lesil McGuire
Representative Norman Rokeberg
Representative Ralph Samuels
Representative Nancy Dahlstrom
Representative David Guttenberg
MEMBERS ABSENT
Representative Berta Gardner
OTHER LEGISLATORS PRESENT
Representative Jay Ramras
COMMITTEE CALENDAR
HOUSE BILL NO. 498
"An Act authorizing tax credits against the production tax on
oil and gas for qualified expenditures for challenged or
nonconventional oil or gas and for qualified expenditures for
nonconventional or renewable energy resources; giving the Act
contingent effect; and providing for an effective date."
- MOVED HB 498 OUT OF COMMITTEE
PREVIOUS COMMITTEE ACTION
BILL: HB 498
SHORT TITLE: TAX CREDITS NONCONVENTIONAL OIL/GAS
SPONSOR(S): RULES
04/03/06 (H) READ THE FIRST TIME - REFERRALS
04/03/06 (H) O&G, RES, FIN
04/11/06 (H) O&G AT 8:00 AM CAPITOL 120
WITNESS REGISTER
BRIAN R. WENZEL, Vice President
Finance and Administration
ConocoPhillips Alaska, Inc.
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 498 and
responded to questions.
JEFFREY A. SPENCER, Supervisor
Greater Kuparuk Area (GKA) Heavy Oil Development
ConocoPhillips Alaska, Inc.
Anchorage, Alaska
POSITION STATEMENT: During discussion of HB 498, indicated
support, provided comments, and responded to questions.
FRANK PASKVAN, Subsurface Team Lead
Western Prudhoe Bay
"BP"
(No address provided)
POSITION STATEMENT: Provided comments and responded to
questions during discussion of HB 498.
SAM W. FRENCH, PE, Project Lead
Lisburne field
"BP Exploration"
(No address provided)
POSITION STATEMENT: Provided comments and responded to
questions during discussion of HB 498.
SCOTT DIGERT, Subsurface Manager
"BP"
Anchorage, Alaska
POSITION STATEMENT: Testified in support of HB 498.
ROBERT B. HUNTER, Project Manager
Arctic Slope Regional Corporation (ASRC) Energy Services
Anchorage, Alaska
POSITION STATEMENT: Provided comments and responded to a
question during discussion of HB 498.
ROBYNN WILSON, Director
Tax Division
Department of Revenue (DOR)
Anchorage, Alaska
POSITION STATEMENT: During discussion of HB 498, expressed
concerns and responded to questions.
BILL VAN DYKE, Acting Director
Central Office
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: During discussion of HB 498, expressed
concerns and responded to questions.
ACTION NARRATIVE
CHAIR VIC KOHRING called the House Special Committee on Oil and
Gas meeting to order at 8:05:25 AM. Representatives Kohring,
Rokeberg, Samuels, and Dahlstrom were present at the call to
order. Representatives McGuire and Guttenberg arrived as the
meeting was in progress. Representative Ramras was also in
attendance.
HB 498 - TAX CREDITS NONCONVENTIONAL OIL/GAS
[Includes brief mention of HB 488 and SB 305.]
8:05:33 AM
CHAIR KOHRING announced that the only order of business would be
HOUSE BILL NO. 498, "An Act authorizing tax credits against the
production tax on oil and gas for qualified expenditures for
challenged or nonconventional oil or gas and for qualified
expenditures for nonconventional or renewable energy resources;
giving the Act contingent effect; and providing for an effective
date."
REPRESENTATIVE ROKEBERG, speaking as chair of the House Rules
Standing Committee, which sponsored HB 498, relayed that
although the bill is designed to mesh with HB 488 via the
inclusion of a conditional effect provision, it has been crafted
as a free-standing bill. He indicated that [the tax credits
provided for in Sections 1 and 2 of the bill can no longer be
claimed] after March 31, 2016; the reason for this is that newer
technologies might render the additional credits unjustified.
House Bill 498 provides for a 15 percent tax credit for
production of challenged or nonconventional oil and gas, and a
25 percent tax credit for investment in alternative energy
projects; both of these tax credits would be applied against
petroleum production taxes.
REPRESENTATIVE ROKEBERG explained that proposed AS 43.55.026(f)
defines the qualified expenditures to which the aforementioned
15 percent tax credit may be applied and is meant to be
consistent with HB 488; proposed AS 43.55.026(g) outlines what
constitutes challenged or nonconventional oil and gas as
follows:
(g) In this section,
(1) "challenged oil or gas" means
(A) oil that is produced from a reservoir
located, in whole or in part, north of 68 degrees, 15
minutes North latitude in this state, without regard
to its API gravity or depth, if the oil is produced
from
(i) the Ugnu Formation or West Sak -
Schrader Bluff Formation; or
(ii) a formation that is
stratigraphically equivalent to a formation described
in (i) of this subparagraph;
(B) oil that is produced from a reservoir
for which, as of January 1, 2006, one of the following
participating areas had been formed: the Orion or
Polaris participating area in the Prudhoe Bay Unit,
the West Sak participating area in the Kuparuk River
Unit, or the Schrader Bluff participating area in the
Milne Point Unit;
(C) oil that has an API gravity of 25 or
less produced from a reservoir or field located, in
whole or in part, north of 68 degrees, 15 minutes
North latitude in this state and at a true vertical
depth as measured from sea level of 5,500 feet or
less;
(D) oil that has an API gravity of 18 or
less, regardless of depth or location within this
state;
(E) oil produced from a reservoir whose
reservoir rock is primarily made up of carbonates;
(F) oil produced through the application of
one or more enhanced oil recovery techniques,
including
(i) steam injection;
(ii) microemulsion flooding;
(iii) in situ combustion;
(iv) polymer-augmented water-flooding;
(v) alkaline or caustic flooding;
(vi) immiscible nonhydrocarbon gas
displacement;
(vii) microbial;
(viii) low-salinity water flooding; or
(ix) any other method not described in
(i) - (viii) of this subparagraph that is certified by
the department to be a qualified enhanced oil recovery
technique or that is certified by the Alaska Oil and
Gas Conservation Commission for purposes of this
section;
(G) oil requiring ultra-extended reach
drilling where the total step-out of the well is
greater than 25,000 feet laterally away from the
surface hole location;
(H) oil production not described in (A) -
(F) of this paragraph that is inherently difficult and
expensive to produce and is certified by the
department to be challenged oil; and
(I) gas produced from or in association with
oil that is produced as described in (A) - (H) of this
paragraph;
(2) "nonconventional gas" means
(A) gas produced or recovered from or in
association with nonconventional oil;
(B) gas produced or recovered from or in
association with hydrates formed from hydrocarbons,
including free gas trapped beneath gas hydrates;
(C) gas manufactured from the gasification
of coal;
(D) tight gas produced from reservoirs with
average permeabilities less than 0.1 millidarcies; and
(E) gas not described in (A) - (D) of this
paragraph that is inherently difficult and expensive
to produce and is certified by the department to be
nonconventional gas;
(3) "nonconventional oil" means:
(A) oil produced or recovered from or
associated with tar sands;
(B) oil produced or recovered from or
associated with oil shale; and
(C) oil production not described in (A) or
(B) of this paragraph that is inherently difficult and
expensive to produce and is certified by the
department to be nonconventional oil.
REPRESENTATIVE ROKEBERG concluded by offering his belief that
the enhanced oil recovery (EOR) techniques outlined in proposed
AS 43.55.026(g)(1)(F) are all new, cutting edge technologies,
and relaying that the remaining bill sections provide for
transition regarding regulations and retroactivity of
regulations, and for the aforementioned conditional effect.
8:13:24 AM
REPRESENTATIVE ROKEBERG, in response to a question, indicated
that language in proposed AS 43.55.026(f) might present somewhat
of a problem.
REPRESENTATIVE SAMUELS opined that the higher costs for heavy
oil should be incorporated without extra credit because [those]
costs are going to be recovered before taxes are paid.
REPRESENTATIVE ROKEBERG offered his understanding that the tax
credits have a valuation of approximately 300 basis points,
under the 15 percent tax credit, against the tax rate itself on
a ratio of 5:1 at $60 per barrel. He mentioned that he's had an
amendment drafted that would include carbon dioxide injection as
one of the listed EOR technologies because it's in use now, and
that "some of these costs are going to be assumed and credited
anyway." Another portion of the aforementioned amendment would
account for all the oil that is lifted; the aforementioned
amendment was labeled 24-LS1817\F.1, Chenoweth, 4/10/06, and
read:
Page 4, line 12, following "flooding;":
Insert
"(ix) carbon dioxide (CO) injection;"
2
Renumber the following sub-subparagraph accordingly.
Page 4, line 13:
Delete "(i) - (viii)"
Insert "(i) - (ix)"
Page 4, line 22, following "oil;"
Insert
"(I) all oil recovered from a separate and
distinct zone or geological horizon that is produced
as described in (A) - (H) of this paragraph, but only
if the average API gravity of the oil produced from
that zone or geological horizon does not exceed the
API gravity limits set in (C) and (D) of this
paragraph, as appropriate;"
Reletter the following subparagraph accordingly.
Page 4, line 24:
Delete "(A) - (H)"
Insert "(A) - (I)"
CHAIR KOHRING asked whether there is any overlap or redundancy
between HB 498 and HB 488.
REPRESENTATIVE ROKEBERG reiterated that currently HB 498 is
designed to dovetail with HB 488. However, the legislature
could either pass HB 498 as a stand-alone bill - by removing the
conditional effect clause - redesign the tax credit slightly, or
use it as an amendment to [HB 488]. He indicated that one of
the distinctions between HB 498 and HB 488 is that HB 498 limits
the transfer of credits to only affiliates.
CHAIR KOHRING characterized HB 498 as another way for the
industry to help offset taxes.
8:20:14 AM
BRIAN R. WENZEL, Vice President, Finance and Administration,
ConocoPhillips Alaska, Inc. ("ConocoPhillips"), testified in
support of HB 498 and its conditional effect clause, adding,
however, that HB 498 will not have its intended effect unless
the right balance in HB 488 is arrived at.
8:21:42 AM
JEFFREY A. SPENCER, Supervisor, Greater Kuparuk Area (GKA) Heavy
Oil Development, ConocoPhillips Alaska, Inc., via a PowerPoint
presentation, relayed that the North Slope has very large, heavy
oil resources, as well as currently-developed light oil
reservoirs. The viscous oil resource is contained in five
fields - "West Sak field, Milne Point [Unit], Orion, Polaris,
and the shallower horizon in the Ugnu ... [formation]" - and
there are approximately 23-24 billion barrels of heavy oil about
evenly split between "the West Sak - or Schrader Bluff formation
- and the shallower Ugnu horizon." Within the ConocoPhillips-
operated Kuparuk River Unit itself, there are approximately 16
billion barrels of oil in place, also somewhat evenly split
between the West Sak and Ugnu formations.
MR. SPENSER stated that these viscous oil resources are located
below the permafrost in the shallow reservoirs from
approximately 3,000 to 4,500 feet; the shallow depths and thick
permafrost result in low reservoir temperatures and this in turn
results in high viscosities, which makes the oil very difficult
to produce and can result in lower rates of recovery as compared
to light oil or gas.
MR. SPENCER briefly outlined the GKA heavy oil development
history and the various well designs that are being used, and
explained that all of the North Slope heavy oil developments are
subject to certain operating conditions - harsh arctic
conditions, minimal footprint, limited contractor resources, and
pushing limits of drilling technology; to geologic complexity -
shallow depths and permafrost issues, unconsolidated formations,
low reservoir temperature, and highly faulted; and to viscous
oil properties - artificial lift required, fluid separation
difficulties, solids handling and disposal issues, and lower
quality crude. This translates into higher cost, lower rate
wells, lower overall recovery, and lower price per barrel. He
posited that if it weren't for the rapid advances in horizontal
drilling and multi-lateral technologies made over the last
several years, the vast North Slope heavy oil resources would
likely remain fallow.
MR. SPENCER, in response to questions, explained that vertical
wells average 200-300 barrels of oil per day, whereas horizontal
multi-lateral wells average 1,500-2,000 barrels per day. He
added that well costs average between $8 million and $10
million. In response to further questions, he said that light
oil would make higher oil rates and have less producing problems
with solids production.
MR. SPENSER, returning to his PowerPoint presentation, relayed
that there have been some expensive lessons as [ConocoPhillips]
continues to push the technical limits regarding drilling on the
North Slope. He discussed a typical West Sak tri-lateral
producer with horizontal laterals from 4,500-8,500 feet in the
D, B, and A sands. In the A sands, ConocoPhillips tends to
undulate between the upper and lower sands to try to contact
more reservoir rock and increase its recovery from the
formation. Furthermore, ConocoPhillips changed the well types -
from vertical to multi-lateral - the recovery mechanisms, the
sand control, the well spacing, and drilling mud systems.
8:30:45 AM
MR. SPENCER, referring to PowerPoint slides, explained that
ConocoPhillips usually has to cross multiple faults and yet
remain within a tiny window of the reservoir rock, from 20-50
feet, while reaching out to lengths of nearly 13,000 feet from a
surface location. Once the wells are drilled and the oil is
brought to the surface - usually by means of downhole pumps or
other artificial lift methods - other issues remain regarding
production of heavy and viscous oils. He said that higher
operating costs are also a result of having to use more heat
and/or chemicals to separate the water from the entrained oil
from Central Production Facility (CPF) 1, where the West Sak
developments are taking place. Essentially, the total cost for
heavy oil is double what it is for light oil because of the
requirement for artificial lift, the additional separation
problems, the handling of the solids, and waste disposal.
CHAIR KOHRING, returning to the comparisons made on an earlier
PowerPoint slide, asked, "Are these improvements in technology
or are you just simply trying different techniques in order to
increase production?"
MR. SPENCER informed the committee that there was a rapid
advance in technology between 1998 and 2004, both in the
extended reach drilling as well as in multi-lateral technology;
for example, ConocoPhillips was able to go to tri-laterals and
beyond. In response to another question, he posited that the
past tax credits granted by the legislature have been
instrumental in encouraging that technological change and
growth.
CHAIR KOHRING, in response to a question, indicated that he is
pondering how the tax credits provided for in HB 498 might
affect the future development of heavy oil, the use of new
technologies, and further advances in technology.
8:34:07 AM
MR. SPENCER relayed that in addition to fluid separation, there
are also solids production problems related to producing heavy
and viscous oils from shallow unconsolidated reservoirs. He
further described the viscous nature of the oil, how it creates
a lot of drag and frictional forces in the reservoir, and how
that tends to pluck sand grains off from the reservoir thus
bringing them to the surface. He stated that the solids in the
tanks generally have the consistency of glacial mud or silt, and
are transported in trucks to the grind and inject facilities in
Prudhoe Bay. This increases the operating costs, relative to
light oil developments. In response to a question, he explained
that the photos in the PowerPoint slide are of solids after the
oil has been separated.
MR. SPENCER relayed that another problem with transporting
solids along with the fluids is that it can greatly increase the
wear on equipment, particularly on rotating equipment such as
downhole pumps and surface pumps. He summarized that with the
North Slope operating conditions, the geologic complexities, and
the viscous nature of the oil leading to the high costs, lower
rate wells, lower overall recovery, and the lower price per
barrel, the development of heavy oil on the [North] Slope is
economically challenged. He mentioned that ConocoPhillips would
like to continue development of the eastern West Sak area, and -
assuming a stable fiscal environment and pushing the limits of
technology - development in the northeast West Sak area; this
series of developments could total over $1 billion over the next
five to seven years. Beyond that, to develop the western West
Sak and the Ugnu resources would require new technology
applications because viscosity and, hence, production
difficulty, is greater.
8:37:49 AM
MR. SPENCER expressed his hope that ConocoPhillips and its
partners can move forward with these projects and the
development of North Slope heavy oil resources, which are vast;
development of those resources is key to minimizing Alaska North
Slope production decline. In conclusion, he remarked,
ConocoPhillips supports HB 498 and believes it could be
beneficial in accelerating investment.
MR. SPENCER, in response to questions, said that typically the
wells that are producing in the viscous fields are dedicated
viscous oil wells; that he is not sure ConocoPhillips has a
cutoff regarding acceptable API gravity; that thermal
stimulation is used in Canada to improve the ability of oil to
flow; and that dedicated wells are used for heavy oil
development; and that some EOR techniques possibly could be used
within the West Sak reservoir itself.
MR. WENZEL, in response to other questions, said that
ConocoPhillips looks at HB 498 as an incremental incentive for
developing both the heavy oil resource and the necessary
technology, though the still-evolving PPT legislation will
provide additional recognition of the higher costs of developing
"resources like this"; HB 498 is intended to incentivize the
development of a number of new technologies for the long term in
Alaska. He added, "I don't think we are looking at this
provision as the way to get gas for the pipeline necessarily."
REPRESENTATIVE SAMUELS expressed disfavor with providing a tax
credit for hydrate research.
MR. WENZEL opined that doing so would still be good for Alaska.
In response to further questions, he indicated that there is
support, among the large producers and the industry in general,
for the balance proposed in the original PPT legislation, with
that balance being a foundation for HB 498.
8:49:25 AM
FRANK PASKVAN, Subsurface Team Lead, Western Prudhoe Bay, "BP",
relayed that he would be speaking to the provision of HB 498
regarding credits for expenditures for challenged oil as it
pertains to viscous oil. He said that based on the knowledge he
gained from working on a number of fields on the North Slope, he
believes that the "challenged oil bill" would materially impact
whether the oil industry will remain in Alaska in the future,
and that viscous oil development in Alaska is the next big
development target. However, it won't be easy, he added,
referring to the economics of the upcoming Western Region
Development project in Western Prudhoe Bay that will focus on
developing viscous oil resources that lie above the "main
Prudhoe accumulation."
MR. PASKVAN characterized viscous oil as a huge resource for the
state, referred to a chart illustrating the shallow fields
challenged by high viscosity, and described various viscosity
ratings. Shallower reservoirs have thicker oil because the
crude is colder and has a heavier API gravity, and such fields
are just starting to be developed because of investments in
technology, and such investments are really just a step towards
really high viscosity targets - even targets with a tar-like
consistency.
MR. PASKVAN relayed that the bottom part of the aforementioned
chart characterizes the size of the target for future
development, that being about one half of the known North Slope
oil remaining; however, that oil is "challenged by high
viscosity," and requires drilling multi-lateral wells, which is
costly in terms of time and money even though such wells make
less than the oil rate of "a decent light oil producer." That's
why BP needs HB 498's incentives Consider also that one out of
every eight barrels belongs to Alaska. He mentioned that some
wells have low production rates and that sometimes more
injectors per producer must be drilled, and relayed that viscous
oil development is difficult because of having to separate oil
from water at lower temperatures. The various challenges of
producing viscous oil result in higher operating costs. He
remarked that BP would like to keep the pipeline full and is
encouraged by the introduction of HB 498.
MR. PASKVAN, in response to questions, said that as part of the
Western Region Development project, BP is spending over $100
million in infrastructure modifications; that there will also be
somewhat higher operating costs, though he didn't have an exact
figure per barrel; that viscous oil is separated into different
depths, with the shallower fields being thicker; that those
wells being drilled are specifically targeted to "those
horizons"; and that there shouldn't be too much overlap between
light oil and heavy oil targets.
MR. PASKVAN, in response to further questions, relayed that the
lighter the oil, the more associated gas there is; that HB 498
"clearly demarks the different bands"; that the API gravity is a
measurement that can be made at the surface very accurately;
that the data represented in his charts pertains to reservoir
viscosity as calculated from a sample taken downhole via an
expensive sampling methodology but which is difficult to acquire
on a well-by-well basis; that BP wouldn't recommend any change
to the bill regarding its terminology; and that to date BP has
not run into any viscous oil reservoir that also has light oil.
MR. PASKVAN, in response to other questions, said it is possible
that BP could discover a deeper heavy oil that might meet the
"18 API criteria", but such would need specific technologies to
develop; that an injector well is used to inject water or gas in
order to help coral the oil and push it to production; that BP
is doing research on the potential applicability of CO2 for
viscous oil reservoirs, though it is difficult to say whether
such will be advantageous to ultimate recovery; that in the
Orion reservoir, BP is using immiscible injection gas EOR from
the "Prudhoe central gas facility"; that each reservoir is a
separate formation and so injectants - of any kind - into one
reservoir won't affect others; and that polymer augmented water
flooding constitutes an area of research.
9:09:02 AM
SAM W. FRENCH, PE, Project Lead, Lisburne field, "BP
Exploration", relayed that the Lisburne field has a lot of
potential in a large resource space, and that BP is focused on
redevelopment of that field in order to increase recovery. The
Lisburne reservoir is adjacent to the Prudhoe Bay reservoir; the
top of the Lisburne reservoir is about 100 feet deeper than the
bottom of the Prudhoe Bay reservoir; the Lisburne reservoir, a
fractured carbonate reservoir, is the only producing carbonate
field in Alaska; and the majority of the other fields are
sandstone reservoirs.
MR. FRENCH explained that carbonate reservoirs throughout the
world are known to be some of the most complex reservoirs from
which to produce oil and gas because the rock is very dense and
thus it is difficult to get oil to flow through it. What helps
BP get commercial production rates at the Lisburne field are
drilling wells that intersect the fractures, which have higher
permeability - the oil seeps into those fractures and then moves
at a higher rate to BP's wells - but the key is being able to
locate the reservoir's fractures. However, not only do the
fractures vary throughout the reservoir, the reservoir's quality
of rock and permeability varies significantly, both vertically
and laterally.
MR. FRENCH posited that the Lisburne field would qualify for the
tax credits proposed by HB 498, and relayed that the original
oil in place (OOIP) in the zones that BP is currently producing
from is estimated to be 2 billion barrels, with a recovery
factor of about 8 percent based on BP's current cumulative
production. Without new technology, BP probably won't recover
significantly more than that, even though the statistical mean
recovery factor in oil carbonate reservoirs worldwide is about
36 percent. A key to attaining that global benchmark is new
technology, and any tax credits will help BP get new technology
projects approved. He noted that currently, BP can't predict
the location of the fractures in the Lisburne field, and thus
there is no guarantee that any new wells drilled in that field
will be successful; furthermore, with conventional drilling
technology, fractures are typically damaged by drilling fluids.
9:16:04 AM
MR. FRENCH indicated that this is another area where new
technology can help - both in terms of prevention and fixing the
problem after it occurs - because production rate depends on the
fractures. He pointed out that the Lisburne field is located in
a high cost environment; not only does it have the costs
associated with all oil fields in the arctic environment, but it
is also deeper than many other fields and the rock is so hard
that there is a low rate of penetration while drilling and that
too increases costs. The potential for recovering additional
oil from the Lisburne field lies in the application of new
technology because currently some of the projects are marginal.
In conclusion, he said that BP supports HB 498, and believes it
will help the Lisburne field.
MR. FRENCH, in response to questions, relayed that the
aforementioned fractures are naturally occurring; that attempts
to artificially create fractures have not been successful; that
conventional water flooding has not been successful; that BP is
studying some other options for injecting water such as low-
salinity water flooding.
MR. PASKVAN, in response to a question, said that the Liberty
field is a sandstone reservoir similar to the Endicott
formation.
9:20:43 AM
SCOTT DIGERT, Subsurface Manager, "BP", relayed that the Milne
Point field has been at the forefront of BP's viscous oil
development on the North Slope, and that over the past four
years viscous oil production has been pushed as high as 20,000
barrels a day - approximately 40 [percent] of Milne Point's
total production - and this has been accomplished via heavy
investment in new drilling technology and facility upgrades.
This investment has been enabled by the current favorable fiscal
framework; BP was also able to take advantage of the upturn in
oil prices, which allowed good returns on its viscous oil
development. He indicated that BP is in support of HB 498 -
which he hopes will encourage ongoing viscous oil development to
the benefit of both the industry and the citizens of Alaska -
and intends to invest "for a 50-year future in Alaska."
MR. DIGERT relayed that a key element in that investment plan is
the Alaska gas pipeline project; that project needs to be built
on a strong and stable foundation for BP's oil business, because
it is that oil business that will provide the bridge to gas.
His company is striving to maximize recovery of its substantial
known oil resources in Alaska, and should be fully aligned with
the state in seeking to maximize production. Production from
BP's fields is steadily declining, and in order to stabilize
that decline steps must be taken to bring on new production of
the viscous oil reservoirs. However, it will be costly to
develop those reservoirs, requiring innovation, advances in
technology, and a tolerance for increased risk; the wells
required are complex and costly, and existing production
facilities require substantial retrofitting to handle cold,
viscous oil.
MR. DIGERT spoke of the need for Alaska to remain competitive in
the global marketplace [in order for producers to] continue
developing the aforementioned reserves, and noted that BP is
developing Schrader Bluff and West Sak reservoirs, has mapped 5
billion to 10 billion barrels of OOIP in those reservoirs, and
hopes to recover up to 20 percent of the oil in the best
performing areas. To date, however, BP has only recovered about
1 percent of the total available and that's after investing
several hundred million dollars, so major continued investment
will be needed as will further technological advances. The risk
of such must be balanced by the opportunity to obtain attractive
returns; BP's viscous oil business needs to be robust enough to
survive a low-price oil cycle, and be positioned to thrive when
prices are favorable. House Bill 498 will help offset some of
the tax burden, and is very welcome.
MR. DIGERT characterized the bill's definitions of challenged
and nonconventional oil and gas as appropriate and suitable for
encouraging further development. He encouraged the committee to
pass HB 498 and seek its inclusion in a broader PPT package as
it moves forward. In conclusion he said, "I remain very
concerned about the future investment climate in Alaska; I
strongly encourage the legislature to continue to seek a fair
and balanced tax package which fundamentally continues to
attract investment [and] provides the opportunities for
innovation and developing our resources."
9:26:34 AM
ROBERT B. HUNTER, Project Manager, Arctic Slope Regional
Corporation (ASRC) Energy Services, relayed that for the past
four years he has managed a joint U.S. Department of Energy
(DOE) and "BP" cooperative research project to study gas
hydrates on the Alaska North Slope. This research is designed
to determine the resource potential of gas hydrates; the Alaska
North Slope may provide a relatively accessible and natural
laboratory to help determine the technical feasibility of
recovering natural gas from gas hydrates and associated free
gas. A gas hydrate is a solid combination of gas and water -
called a clathrate - that occurs within distinct pressure,
temperature, and stability regions within porous and permeable
reservoirs; gas hydrates can occur in sufficient concentrations
to potentially become a significant resource if the clathrates
can be changed, within the reservoir, into liquid water and
natural gas components by modifying the pressure, temperature,
and/or the chemistry of the system.
MR. HUNTER said that although 44-100 trillion cubic feet (Tcf)
of in-place gas hydrates are estimated to be on the Alaska North
Slope by the United States Geological Survey (USGS), the
potential recoverable resource remains unproven and unknown at
present. This uncertainty is reflected in studies from
reservoir modeling that estimate that 0-12 Tcf of this type of
gas could potentially be recovered from the 33 Tcf in place
within the Eileen Trend; additional data is required to narrow
this uncertainty and learn more about gas-hydrate-bearing
reservoir properties, and BP and the DOE look forward to
continuing this gas hydrate research, and have recently approved
drilling of a dedicated North Slope stratographic test to that
end. There are many remaining technical challenges to be
addressed in this project before potential gas hydrate
productivity is better understood, and although it is too early
to tell, this research may contribute to determining whether
this large, potential gas resource might one day become part of
the overall U.S. gas supply portfolio.
MR. HUNTER, in response to a question, said that typically
reservoir units contain both hydrates and free gas, with free
gas being at or just below the gas hydrate's stability zone
depth, which is commonly around 3,500 feet "in the subsurface"
though it can be deeper.
9:33:11 AM
ROBYNN WILSON, Director, Tax Division, Department of Revenue
(DOR), relayed that the division has concerns about
administering HB 498, which provides a [tax] incentive in three
areas - certain oils and areas, certain methods of EOR, and the
development or use of renewable energy. For each of these
categories, the DOR thinks it is very important to define the
time, the place, and the allowable costs; that is: the time
when the costs that will be creditable are incurred, the place
where the activities that would be creditable are taking place,
and what the allowable costs are. Some of those points are not
as clear as they could be. For example, are costs allowable if
a project is already underway on the effective date of the bill?
Also, in terms of place, research and development of new
technology are eligible activities even if they occur in
Venezuela, for example, and therefore the bill should clarify
exactly what is creditable.
MS. WILSON said it would also be helpful if HB 498 were clearer
with respect to the locations of EOR projects; for example,
would BP's "Liberty project," which is located on the federal
outer continental shelf but would likely have surface facilities
on state land, qualify for the bill's credit. She noted also
that some of the EOR activities listed in the bill appear to be
"piggybacked" off of federal rules, which are very specific that
a project needs to be on federal land or adjacent seabed. In
terms of allowable costs, she said, the division is concerned
that HB 498 is not clear regarding what types of costs qualify
or the scope of those costs. Furthermore, the bill uses the
term "qualified expenditure", but does not define that term; and
so although the intent might be to mesh HB 498 with the PPT
bill, that legislation uses the term "qualified capital
expenditure", which encompasses exploration and items that are
capitalized for federal purposes.
MS. WILSON said that if the intention is to allow the same kinds
of costs that the federal government allows for EOR projects,
there are some federal costs which are normally expensed that
would be subject to the federal EOR credit; for example, the
cost of the injectant is expensed federally, not capitalized,
and so would not fit under the PPT legislation's term,
"qualified capital expenditure". She encouraged the committee to
be very clear about what kind of costs it intends to be covered
under HB 498. Also, in the area of allowable costs, the
language on page 5, lines 17-18, that speaks to the development
or use of renewable energy is pretty broad. She reiterated that
she simply wants to be certain regarding what costs the
committee envisions as being qualifying.
9:40:32 AM
MS. WILSON posited that the issue of cost allocation also needs
to be addressed in the bill; for example, cost allocation may be
necessary when two grades of oil are pulled up, and for any
jointly-owned facilities or shared operations. In response to a
question, she indicated that in requesting that the committee be
specific regarding what costs should qualify, she is pointing
out that she is not sure what the intention is regarding
overhead, adding that although she has not thought through a
specific allocation methodology, the department would be willing
to assist the committee on that issue.
MS. WILSON remarked that defining challenged oil as having an
API gravity of 25 degrees or less for depths of less than 5,500
feet subsurface is generous, and suggested that the committee
consider using 20 degrees as the threshold instead. Also, API
gravity is not the ideal parameter to use, she opined; a more
appropriate parameter would be oil viscosity, which is measured
in units called centipoise (cP) and refers to the ability of a
liquid to flow. Consider that some so-called heavy oils
actually have a more favorable viscosity and flow as well as
that with a higher API due to gas content and reservoir
temperature. For example, some of the Orion and Polaris
participating areas are 5-10 cP, and the Kuparuk [River Unit]
formation oil has an API gravity of 22-25 but also has a
favorable viscosity. Care must also be taken with regard to
where and under what conditions the API gravity and viscosity of
oil are measured, because different pressure, temperature, and
gas-to-oil ratio conditions can give different values for API
gravity and viscosity, with temperature being the more important
variable.
9:45:26 AM
MS. WILSON pointed out that one of the oil reservoirs described
under the bill as containing challenged oil is already under
production at Lisburne and has been since 1986; the Lisburne
participating area was approved by the Division of Oil & Gas in
December 1986. The other possible known reservoir defined by
proposed AS 43.55.026(g)(1)(E) is the Shublik formation, which
is one of the Permotriassic reservoirs in the Prudhoe Bay Unit
(PBU), and the Permotriassic reservoirs are the main producing
reservoirs in the PBU and are known as the initial participating
areas. Some of the projects identified in proposed AS
43.55.026(g)(1)(F) are currently under valuation in the PBU and
Duck Island Unit, and BP has already performed pilot/test
projects involving polymer-augmented water-flooding [at] the
Brightwater project at the Flow Station 2 area in the PBU, and
low-salinity water flooding in the PBU and Duck Island Unit.
Single-well tracer tests in these two units have yielded 8-20
percent recovery improvements, and the Internal Revenue Service
(IRS) has certified low-salinity water injection as an EOR
process for federal investment tax credit.
MS. WILSON referred to proposed AS 43.55.026(g)(1)(H), and said
that the North Slope producers have already drilled extended
reach drilling ("ERD") wells of over 22,000 feet at Niakuk and
Milne Point; numerous development projects on the North Slope
are easily designed around drilling 15,000-20,000 feet and
beyond. Such drilling may be more expensive but it allows
access to oil through centrally located and more environmentally
friendly locations. She pointed out that many of the
aforementioned projects already qualify for the 15 federal EOR
credit and could potentially benefit by a 35 percent federal tax
rate, and under both this bill and the PPT legislation, a
project could also qualify for a 20 percent tax deduction, a 20
percent credit, and potentially another 15 percent credit. That
potentially adds up to over a 100 percent, and does not include
the state income tax deduction, which is based on the federal
credit.
MS. WILSON, in conclusion, said she would be happy to work with
the committee to clarify the aforementioned issues.
CHAIR KOHRING indicated that clarification might come in the
form of a committee substitute (CS).
[Following was a brief discussion regarding how the committee
would be proceeding.]
The committee took an at-ease from 9:51 a.m. to 9:53 a.m.
CHAIR KOHRING then recessed the House Special Committee on Oil
and Gas to a call of the chair.
CHAIR KOHRING called the meeting back to order at 11:34 a.m.
11:35:54 AM
BILL VAN DYKE, Acting Director, Central Office, Division of Oil
& Gas, Department of Natural Resources (DNR), opined that
viscous oil projects are challenged on the North Slope, and that
the economics are generally not on par with comparable light oil
projects. He urged restraint, however, when considering
incentives for viscous oil projects and the other types of
projects addressed in HB 498. As currently drafted, with
respect to viscous oil, HB 498 cuts a pretty broad swath across
the entire North Slope, and with respect to nonconventional gas,
it cuts a pretty wide swath across the entire state.
Furthermore, HB 498 also contains some unintended consequences;
therefore, he said, he would recommend that the bill be more
narrowly focused, perhaps limiting the proposed tax credits to
new capital investments pertaining to viscous oil, and then only
with regard to certain pools and formations. He said he would
also recommend thinking about providing tax credits for EOR,
nonconventional and renewable energy, and research and
development at a later time.
MR. VAN DYKE, on the issue of unintended consequences, directed
the committee's attention to the language of proposed AS
43.55.026(g)(1)(A)(ii) and noted that it says "a formation that
is stratigraphically equivalent to" the Ugnu Formation or West
Sak - Schrader Bluff Formation; this leaves the bill pretty wide
open with regard to depth, location, and oil gravity. The word,
"field" as used in proposed AS 43.55.026(g)(1)(C) also leaves
the bill open to unintended consequences; he opined that it
would be preferable to look at specific pools and formations,
because fields are generally groups of pools and formations.
For example, in the Prudhoe Bay field, there are 12 or 13
separate oil pools.
MR. VAN DYKE referred to proposed AS 43.55.026(g)(1)(D), which
speaks of oil that has an API gravity of 18 or less, and noted
that almost every light oil pool on the North Slope has a tarmat
at its base and so under the bill a credit would be given for
tarmat production in light pools; this language will create
challenging production and cost allocation issues down the road,
though those issues will have to be dealt with regardless when
they pertain to joint-use facilities, drill sites, production
facilities, and separators. There is also the question of how
to define viscous or heavy oil - currently there is no bright
line - and the committee needs to consider the API gravity of
the oil, the temperature of the oil, and the dissolved gas
content of that oil. All of the aforementioned must be measured
down in the reservoir where the oil actually has to flow into
the well bores. He posited that although API gravity can serve
as an acceptable parameter to define viscous oil, there must
also be appropriate "sideboards" in place. In situ viscosity is
really a better metric to use, he opined, even though it is a
little harder to measure.
MR. VAN DYKE said he would be willing to work with the committee
and bill sponsor [to address his concerns].
11:41:57 AM
MR. VAN DYKE, in response to questions, said that there are
commercial laboratories, which all the North Slope producers
have access to, that can measure the aforementioned aspects
while mimicking reservoir conditions; that the producers are
going to want to know what an oil's viscosity is anyway; that he
would prefer to see in situ oil viscosity used as the parameter,
though he could live with API gravity being used; that the
measurements would have to made for each separate pool and at
each of a pool's different elevations; that it is very possible
to get different API measurements from different wells in the
same pool based on depth and the geographical location within
the pool; that the API gravity will not be the same,
necessarily, for every well in a given pool; and that there are
lenses of lighter oil in the West Sak - Schrader Bluff
formation, and so one must look at what's coming out of the well
bores as a mixture rather than attempting to dissect the layer
cake and grant a credit for the third layer, for example, but
not the forth layer.
MR. VAN DYKE, in response to further questions, said that one
would estimate the centipoise measurements for separate zones if
they are different, and then do some sort of volume weighted
average; that he could live with an API gravity measurement if
it had a couple more sideboards than are currently in the bill;
that it would be appropriate to replace the word, "field" - as
currently used in proposed AS 43.55.026(g)(1)(C) - with either
the word, "reservoir" or the word, "pool"; that the term,
"reservoir" is more focused than the term, "pool"; and that the
terms, "horizon" and "zone" generally refer to layers of rock
regardless of whether they contain oil.
11:49:58 AM
MR. VAN DYKE, in response to more questions, said that although
some of the oils on the North Slope have different chemical
compositions, it might not be possible to chemically tell
certain oils apart; and that proposed AS 43.55.026(g)(1) ought
to be clarified.
REPRESENTATIVE ROKEBERG concurred with the latter point, and
acknowledged Mr. Van Dyke's comments regarding narrowing the
bill.
MR. VAN DYKE, in response to questions regarding proposed AS
43.55.026(g)(1)(F), said that most of the EOR techniques listed
therein could be applied to either light or heavy oil; that
steam injection and in situ combustion target viscous oil; and
that if one were just looking at capital credits for investments
for facilities to operate an EOR project or an injection well or
a new-production well, as long as it was targeted to a heavy oil
reservoir, a definition could be arrived at, though there will
still be an allocation issue to deal with once the oil is
brought to the surface because it's all going to processed at
joint-use facilities.
MR. VAN DYKE, in response to a question regarding proposed AS
43.55.026(g)(1)(E), remarked that the wells in the Lisburne
reservoir produce too much gas in association with the oil they
are producing and thus are not competitive with other Prudhoe
Bay and satellite wells, though a number of horizontal-well
techniques have been tried in order to stay away from the gas
production - to increase the oil production in relative terms,
in relative amounts. In response to further questions, he noted
that the Lisburne reservoir from day one has had a large gas
cap, and although it has a large amount of recoverable oil, the
gas flows more easily to the well bore than does the oil, adding
that the rock in "the Northern foothill area" is tighter rock -
less permeable rock - and probably more gas prone than oil
prone. He remarked that a lot of the tight gas reservoirs are
also fractured, so it would be hard to say that just because the
bulk of the rock has low permeability that the reservoir isn't
highly productive at the same time.
MR. VAN DYKE, in response to a question, recommended that the
committee delay consideration of a tax credit related to gas
because at this time he is not entirely comfortable with
utilizing a "tight gas standard for incentive for exploration."
In response to more questions, he said he would agree that once
folks are comfortable with a start-up date for gas sales, that
it will change the economics significantly, and that he doesn't
know whether gas should be incentivized at this point in time.
12:03:34 PM
REPRESENTATIVE SAMUELS mentioned that a similar debate occurred
in the House Resources Standing Committee regarding whether to
have a credit apply to Point Thomson gas development. The
argument went along the lines of, "If you have a gas line, do
you need the incentive, [but] if you don't have a gas line,
there's not going to be any developed," and so the language was
left in HB 488.
REPRESENTATIVE McGUIRE noted that HB 498 could focus on heavy
oil at this time and then the legislature could come back at a
later point in time and deal with the issue of gas.
REPRESENTATIVE ROKEBERG, in response to comments, indicated that
if the bill could be moved from committee today he would be
willing to work with all the interested parties before the bill
is heard in its next committee of referral.
MR. PASKVAN, in response to comments and questions, said that
"Prudhoe" has a free gas cap that's above the oil and that's not
associated with hydrates, and that gas hydrates can form and
actually plug wells when "gas lift" is used to move oil through
cold zones such as those that are shallower than 3,500 feet.
Below that zone, methane hydrate ice can be trapped underneath;
dropping the pressure in systems where that occurs can generate
replacement gas, and this is one way to "start to produce off"
from the hydrates. He relayed that the free gas beneath the gas
hydrates isn't a huge target for BP because it does not
constitute a large accumulation, though it is appreciable
because the North Slope is a big place.
MR. PASKVAN, in response to further comments, concurred that the
gas hydrate resource on the North Slope is huge, but pointed out
that currently there isn't an economic means of recovering that
resource; therefore, the committee should think carefully about
what it chooses to incentivize. "Right now there ... is no line
of sight to a clear economic development, and research and
development that might be spurred or incentivized by this would
be applicable to what is one of our larger potential gas
resources," he added.
REPRESENTATIVE SAMUELS offered his understanding that there is
10,000 Tcf of [gas hydrates] beneath the Beaufort Sea.
12:15:20 PM
REPRESENTATIVE ROKEBERG, referred to gas hydrate potential in
the Gulf of Mexico, and remarked that it is a policy call
whether the legislature should grant an extra credit for gas
hydrate research.
MR. WENZEL, in response to comments and a question, expressed a
willingness to work with the administration regarding future
cost allocations and the allocation mechanism that would be
used; "we'd want to address those issues to be sure that there
wasn't a double dipping, if you will, between expenditures for
non-heavy non-viscous [oil] and ... new expenditures to develop
this resource." He added, "I won't dispute the fact that
getting into allocations between one type of resource and
another is going to create [an] administrative burden - no doubt
about that; is that burden worth while in the face of an
additional credit that helps us accelerate the development of
this resource - yes."
REPRESENTATIVE SAMUELS asked whether new facilities for heavy
oil will be needed.
MR. PASKVAN said that there is specific equipment that is being
added into the existing infrastructure; for example, production
heaters to assist the separators, solids handling equipment, and
de-sanding equipment. His company is cognizant of the fact that
in planning drilling wells, investments in the facilities must
be made to enable them to deal with heavy oil - investments in
heat, hygiene, and chemicals. In response to another question,
he said that heavy oil does have impacts on the processing
equipment at the refineries. He indicated that BP supplies data
on the crude that's being produced to the potential recipients
of that crude, and they in turn make in investments in their
facilities to enable them to better handle that product.
12:22:23 PM
REPRESENTATIVE ROKEBERG asked whether BP tries to harvest
tarmats.
MR. PASKVAN indicated that tarmats are out of his current
geographical area, but offered that they are difficult targets
to access, tend to remain immobile, and bring with them
technical challenges such as high amounts of associated water
production; BP has not yet been able to effectively develop that
resource with standard technology.
REPRESENTATIVE ROKEBERG asked Ms. Wilson whether inserting a
start date after the effective date would alleviate some of her
concerns. In this way, only expenditures that occur after that
point in time would qualify for the proposed credits.
MS. WILSON indicated that such a provision would add clarity and
accountability. In response to another question, she relayed
that she had observed earlier that HB 488 has clauses that are
modified by the term, "in this state", as well as other clauses
that don't specify that point; therefore, the bill should be
clarified with regard to the committee's intention on that
issue.
REPRESENTATIVE ROKEBERG asked how the current versions of HB 488
and SB 305 have handled the deductibility of out-of-state labor
costs.
MS. WILSON said they provided for an allocation of overhead and
rely on operating agreements and standard industry practices.
REPRESENTATIVE ROKEBERG reiterated that he would like to make
HB 498 consistent with HB 488. He asked whether research and
development is considered a deductible expense under HB 488.
MS. WILSON offered her recollection that that issue is not
specifically addressed in HB 488, and so whether research and
development would be allowed or precluded as an expense would
depend on whether it's specific to a particular lease and direct
and necessary to that lease. In response to another question,
she said that under the PPT legislation, operating expenses are
deductible and capital expenditures are both deductible and
creditable; furthermore, under the federal code, a company can
elect whether to list research and development as an operating
expense or as a capital expenditure.
REPRESENTATIVE ROKEBERG said he would appreciate feedback from
the committee regarding which direction the legislature should
take on this issue. He pondered the question of whether the
legislature should mandate specifically whether research and
development should be considered a deductible expense or a
capital expense.
MS. WILSON posited that as long as it's "spelled out," the
administration can handle the accounting aspect.
REPRESENTATIVE ROKEBERG asked whether mandating that research
and development be handled as a deductible expense would make
HB 498 more consistent with "the PPT-type concept."
MS. WILSON said, "That might be a little bit of a disconnect
with PPT, because I think that under the PPT, if it's
capitalized for federal then it's treated as a capital
expenditure and subject to a credit - not to say we couldn't do
that."
12:31:03 PM
MS. WILSON, in response to a question, said that if the producer
"expenses that," for example, then there would be that
disconnect; it's not impossible to handle as long the bill is
clear with regard to how the legislature wants that issue
handled.
REPRESENTATIVE ROKEBERG asked whether the legislature should not
allow a special provision for research and development, even if
that seems to be counterproductive.
CHAIR KOHRING noted that there is also the issue of the Alaska
legislature providing a tax credit for research and development
that could be used to benefit other countries.
REPRESENTATIVE ROKEBERG posited that that issue could be
addressed by stipulating that the research and development be
done in state.
12:32:18 PM
REPRESENTATIVE SAMUELS said he sees an allocation problem, from
an accounting or auditing standpoint, with providing a credit
for research and development, even that which is done in state.
MR. WENZEL said that his company's view regarding research and
development is that it's going to be done sooner or later, and
the benefit of HB 498 is that it will accelerate research and
development. So it's a policy call as to whether Alaska wants
to wait for "someone else to do it" and then use that technology
without paying for it; if Alaska does pay for researching and
developing new technology, then that technology could very well
be shared and used around the world. He said he can see some
validity for trying to tie investments for research and
development to Alaska projects.
MR. WENZEL, in response to a question, said that his company has
a budget line item for research and development - blue-sky-type
research and development - to the extent that it can't be
associated with a specific project. He offered his
understanding that right now, the PPT legislation allows both
capital expenditures and exploration expenditures to qualify for
the 20 percent credit; the reason for this is that exploration
involves both operating expenses and capital expenditures. He
suggested that heavy oil could be treated the same way by having
the bill cover expenditures related to Alaska projects on
viscous heavy oil up to a certain point.
CHAIR KOHRING suggested that the committee move the bill from
committee along with a letter from him requesting that the House
Resources Standing Committee address the issues that have been
raised thus far; doing so would provide the bill's sponsor with
an opportunity to craft any necessary amendments or committee
substitute (CS) that would address everyone's concerns.
REPRESENTATIVE ROKEBERG concurred, and questioned whether the
bill should address the issue of gas hydrates. He said he
wishes to work with the department to narrow it down and improve
accountability and conformity.
CHAIR KOHRING after ascertaining that no one else wished to
testify, closed public testimony on HB 498.
12:40:17 PM
REPRESENTATIVE DAHLSTROM moved to report HB 498 out of committee
with individual recommendations, the accompanying fiscal notes,
and the aforementioned letter from the chair of House Special
Committee on Oil and Gas to the co-chairs of the House Resources
Standing Committee.
REPRESENTATIVE GUTTENBERG objected for the purpose of
discussion. He said, "Certainly we wouldn't want to see
research being done in Mississippi that could be done here, not
just the field work, but the lab work also," adding that there
seems to be quite a bit of tightening and refocusing that needs
to be done [on the bill].
REPRESENTATIVE GUTTENBERG then removed his objection.
CHAIR KOHRING asked whether there were any further objections to
reporting HB 498 from committee. There being none, HB 498 was
reported from of the House Special Committee on Oil and Gas.
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Oil and Gas meeting was adjourned at
12:43 p.m.
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