Legislature(2007 - 2008)ANCHORAGE
06/17/2008 09:00 AM House RULES
| Audio | Topic |
|---|---|
| Start | |
| HB3001|| SB3001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB3001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
JOINT MEETING
HOUSE RULES STANDING COMMITTEE
SENATE SPECIAL COMMITTEE ON ENERGY
June 17, 2008
9:07 a.m.
MEMBERS PRESENT
HOUSE RULES
Representative John Coghill, Chair
Representative John Harris (AGIA Subcommittee, Chair)
Representative Anna Fairclough
Representative Craig Johnson
Representative Ralph Samuels (AGIA Subcommittee)
Representative Beth Kerttula (AGIA Subcommittee)
Representative David Guttenberg
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Charlie Huggins, Chair
Senator Bert Stedman, Vice Chair
Senator Kim Elton
Senator Lyda Green
Senator Lyman Hoffman
Senator Lesil McGuire
Senator Donald Olson
Senator Gary Stevens
Senator Joe Thomas
Senator Bill Wielechowski
Senator Fred Dyson
Senator Thomas Wagoner
MEMBERS ABSENT
HOUSE RULES
All members present
SENATE SPECIAL COMMITTEE ON ENERGY
All members present
OTHER LEGISLATORS PRESENT
Representative Bob Buch
Representative Mike Chenault
Representative Mike Doogan
Representative Les Gara
Representative Carl Gatto
Representative Mike Hawker
Representative Lindsey Holmes
Representative Reggie Joule
Representative Mike Kelly
Representative Jay Ramras
Representative Bob Roses
Senator Gene Therriault
COMMITTEE CALENDAR
HOUSE BILL NO. 3001
"An Act approving issuance of a license by the commissioner
of revenue and the commissioner of natural resources to
TransCanada Alaska Company, LLC and Foothills Pipe Lines
Ltd., jointly as licensee, under the Alaska Gasline
Inducement Act; and providing for an effective date."
- HEARD AND HELD
SENATE BILL NO. 3001
"An Act approving issuance of a license by the commissioner
of revenue and the commissioner of natural resources to
TransCanada Alaska Company, LLC and Foothills Pipe Lines
Ltd., jointly as licensee, under the Alaska Gasline
Inducement Act; and providing for an effective date."
- HEARD AND HELD
BILL: HB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (H) READ THE FIRST TIME - REFERRALS
06/03/08 (H) RLS
06/03/08 (H) WRITTEN FINDINGS & DETERMINATION
06/04/08 (H) RLS AT 9:00 AM CAPITOL 120
06/04/08 (H) Subcommittee Assigned
06/05/08 (H) RLS AT 9:00 AM TERRY MILLER GYM
06/05/08 (H) House Special Subcommittee on AGIA
06/06/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/06/08 (H) House Special Subcommittee on AGIA
06/07/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/07/08 (H) House Special Subcommittee on AGIA
06/08/08 (H) RLS AT 1:00 PM TERRY MILLER GYM
06/08/08 (H) House Special Subcommittee on AGIA
06/09/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/09/08 (H) House Special Subcommittee on AGIA
06/10/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/10/08 (H) House Special Subcommittee on AGIA
06/12/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/12/08 (H) House Special Subcommittee on AGIA
06/13/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/13/08 (H) House Special Subcommittee on AGIA
06/14/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/14/08 (H) House Special Subcommittee on AGIA
06/16/08 (H) RLS AT 9:00 AM ANCHORAGE
06/16/08 (H) House Special Subcommittee on AGIA
06/17/08 (H) RLS AT 9:00 AM ANCHORAGE
BILL: SB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (S) READ THE FIRST TIME - REFERRALS
06/03/08 (S) ENR
06/03/08 (S) REPORT ON FINDINGS AND
DETERMINATION
06/04/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/04/08 (S) Heard & Held
06/04/08 (S) MINUTE(ENR)
06/05/08 (S) ENR AT 9:00 AM TERRY MILLER GYM
06/05/08 (S) Heard & Held
06/05/08 (S) MINUTE(ENR)
06/06/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/06/08 (S) Heard & Held
06/06/08 (S) MINUTE(ENR)
06/07/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/07/08 (S) Heard & Held
06/07/08 (S) MINUTE(ENR)
06/08/08 (S) ENR AT 1:00 PM TERRY MILLER GYM
06/08/08 (S) Heard & Held
06/08/08 (S) MINUTE(ENR)
06/09/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/09/08 (S) Heard & Held
06/09/08 (S) MINUTE(ENR)
06/10/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/10/08 (S) Heard & Held
06/10/08 (S) MINUTE(ENR)
06/12/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/12/08 (S) Heard & Held
06/12/08 (S) MINUTE(ENR)
06/13/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/13/08 (S) Heard & Held
06/13/08 (S) MINUTE(ENR)
06/14/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/14/08 (S) Heard & Held
06/14/08 (S) MINUTE(ENR)
06/16/08 (S) ENR AT 9:00 AM ANCHORAGE
06/16/08 (S) Heard & Held
06/16/08 (S) MINUTE(ENR)
06/17/08 (S) ENR AT 9:00 AM ANCHORAGE
WITNESS REGISTER
Julie Houle, Chief, Resource Evaluation Section, Division of
Oil and Gas, Department of Natural Resources; Steve
Moothart, Petroleum Geologist, Division of Oil and Gas,
Department of Natural Resources; Anil Chopra, President and
CEO, PetroTel Inc.; Nan Thomson, Petroleum Manager, Division
of Oil and Gas, Department of Natural Resources; Craig
Haymes, Alaska Production Manager, Exxon Mobil; John Zager,
General Manager, Chevron North America Exploration &
Production; Vince LeMieux, Manager, Alaska New Ventures,
Chevron; Cathy Foerster, Commissioner, Alaska Oil and Gas
Conservation Commission (AOGCC).
ACTION NARRATIVE
CALL TO ORDER
SENATOR CHARLIE HUGGINS called the joint meeting of the
House Rules Standing Committee and the Senate Special
Committee on Energy to order at 9:07:18 AM.
HB 3001-APPROVING AGIA LICENSE
SB 3001-APPROVING AGIA LICENSE
NAN THOMSON, PETROLEUM MANAGER, DIVISION OF OIL AND GAS,
DEPARTMENT OF NATURAL RESOURCES (DNR), introduced staff.
JULIE HOULE, CHIEF, RESOURCE EVALUATION SECTION, DIVISION OF
OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, gave a brief
history of the Resource Evaluation section, which provides
technical support for the Division of Oil and Gas and Alaska
Oil and Gas Conservation Commission (AOGCC). The resource
section provides technical development to assure the state
receives its fair share of the resource. The resource
section completed an in-house geological simulation on Point
Thomson prior to contracting with PetroTel Inc. for a
reservoir engineering study.
9:10:53 AM
MS. HOULE explained that the term "hydrocarbon" encompasses
oil, gas and condensates. Point Thomson has all three phases
in its potential reserves.
9:11:58 AM
STEVE MOOTHART, PETROLEUM GEOLOGIST, DIVISION OF OIL AND
GAS, DEPARTMENT OF NATURAL RESOURCES, introduced himself and
thanked legislators for the opportunity to present his study
of the Point Thomson field and reservoir. He previewed that
his talk would include information about the scope of the
project, answer technical questions proposed, and discuss
results of geologic modeling. He said that Dr. Anil Chopra
would explain the written findings of the study and give a
more detailed presentation of the computer simulations that
were conducted.
MR. MOOTHART reported that the study was initiated in the
spring of 2007. He stated that his department wanted
PetroTel to do an independent engineering and geologic
assessment of the Point Thomson reservoir. PetroTel is
recognized as an industry leader in reservoir
characterization, oil and gas simulation, enhanced oil
recovery and exploration and recovery technologies. He
reported that the objectives of the study were two-fold. The
first objective used data available to the division to
determine in-place volumes of oil, gas and gas condensates.
The construction of three dimensional computer models
enabled better understanding of reservoir properties and in-
place volumes. These volumes have generally been referred to
as reserves, which are recoverable to the surface and
available for sale. He explained that the volumes of
hydrocarbons, which are technically recoverable, are
dependent on several factors: quality of reservoir rock,
type and properties of hydrocarbons contained in the
reservoir, and recovery method.
MR. MOOTHART shared that the second objective of the study
was to analyze the potential recoverable reserves and
impacts that different variables would have on those
recoveries.
9:17:44 AM
MR. MOOTHART reported that once the geologic models have
been constructed and populated, the information can be
imported into a reservoir simulator and be analyzed under
different scenarios employing the dynamic properties of
reservoir pressures, flow rates, and ultimate recoverable
hydrocarbons. This information can be analyzed throughout
time and under different off-take scenarios. The ultimate
goal using the best geologic representation of the reservoir
available would be to input that information into a
reservoir simulator to determine the range and potential
impact that various recovery methods and different off-take
scenarios could have on the ultimate recoverable reserves
within the Point Thomson reservoir. There have been
discussions about potential differences in hydrocarbon
recovery methods such as gas blowdown or gas cycling. He
stated that these are put out there without much
understanding of the actual potential differences in
hydrocarbon recoveries that would happen under various
scenarios. He submitted that this was the first independent
study.
9:20:23 AM
REPRESENTATIVE SAMUELS inquired whether the state has the
same access to information that the lease holders have.
MS. HOULE explained that the state gets information from
AOGCC and through the operators when applying for units. She
said she gets lots of confidential information in that
manner. The other way the state gets information is from the
permitting for seismic shoots. She emphasized that a lot of
the oil companies' analyses is based on the state's raw
data.
9:22:19 AM
MR. MOOTHART reiterated that this is the first study to
quantify those impacts. He stressed that the study did not
attempt to design or determine the best comprehensive
economic development plan for the area. He noted that the
study focused on the Point Thomson sand reservoir and not on
the hydrocarbon resources in the underlying and overlying
strata. The majority of the resource lies in the Point
Thomson reservoir. He mentioned that the reservoir is
generally perceived as a gas reservoir, but within the
industry it is recognized as a high pressure retrograde
condensate reservoir. The reservoir conditions manifest at
the surface, as oil is held as a gas or vapor within the
reservoir. Development for maximum recovery requires
engineering and operating methods that are significantly
different from most crude oil or dry gas reservoirs. He
relayed that Dr. Chopra will give more details about this
distinction.
9:26:17 AM
REPRESENTATIVE GATTO thought that the information just
presented about liquids and gases was contradictory to what
he had learned in school, that when you pressurize a gas it
becomes a liquid.
MR. MOOTHART acknowledged that the issue is confusing. He
explained that in addition to the gas and condensate, the
reservoir is also known to contain a relatively thin oil rim
that exists between the overlying gas cap and the underlying
water aquifer. He noted that long term definitive tests of
the oil rim are lacking. In a 1977, 18-hour test across this
zone in Point Thomson number 1 well, flow rates revealed
2300 barrels of oil per day of over 18 degree gravity oil.
Uncertainty still exists in the depths of the actual fluid
contacts and a lot is unknown about the oil rim. As a
result, a range of uncertainty exists in the thickness of
the reservoir that is available to contain oil within the
rim, resulting in a broader range of potential volumes
contained in the rim. He reported that the wells drilled to
date in the Point Thomson reservoir have not adequately
delineated the oil rim at this time and additional wells are
needed to specifically target and test the interval. This is
needed to both determine oil volume within the oil rim and
the ultimate producibility of the resource. He reported
that uncertainty is one of the reasons why eleven different
three dimensional models were constructed for the study.
MR. MOOTHART explained that the depths of fluid contact were
varied in the different models to capture the range of
uncertainty. Reservoir properties were also varied to
account for the uncertainty in the distribution of those
properties between the existing wells. From the eleven
models that were constructed, the original in-place
hydrocarbon volumes that were determined to exist in the
reservoir ranged as such: gas volume in place ranged from
about 8.5 to over 10 trillion standard cubic feet; and
associated condensate, liquid hydrocarbons that are
entrained in the gas, were roughly 500-600 standard stock
tank barrels in place. He went on to define a stock tank
barrel as 42 gallons. He emphasized that a stock tank barrel
is 42 gallons at surface conditions, not at reservoir
conditions. There are estimates of 600 to 950 million stock
tank barrels in oil rim, which is a broad estimate due to
uncertainties. He summarized that ultimately Point Thomson
is the largest yet undeveloped oil field in Alaska. He noted
that these volumes do not reflect the resource that has been
tested in the underlying Pre-Mississippian strata or the
overlying shallower Brookian in this area.
MR. MOOTHART observed that Dr. Anil Chopra would discuss the
reservoir simulation portion of the study and potential
recovery reserves from the various recovery methods that
were studied.
9:32:23 AM
REPRESENTATIVE FAIRCLOUGH observed that the Commission
agreed with the assessment that Point Thomson is the largest
undeveloped oil field and asserted that the highest and best
value for production of that field is going to be oil first
and not gas. She inquired as to the timeline for extracting
the oil, versus having access to the gas.
MR. MOOTHART indicated that Dr. Anil Chopra would respond to
the question.
MS. HOULE interjected that it depends upon how much oil
versus gas is taken out, and noted that there is a trade off
between oil and gas recovery including how much you want to
cycle gas.
9:34:47 AM
REPRESENTATIVE COGHILL asked for clarification regarding
assumptions from the number of wells compared to the size of
the unit to help understand the modeling, whether it was 2
wells, 10 wells, or 100 wells.
MS. HOULE clarified that Dr. Chopra would provide more
detail.
REPRESENTATIVE COGHILL observed that the scenarios become
confusing when it is not clear whether empirical data or
supposed data is being used. He wanted a clear picture in
order to determine if the field was properly modeled. He
wanted to know with confidence that the pipeline would be
doable with or without [the Point Thomson gas].
9:36:46 AM
ANIL CHOPRA, PRESIDENT AND CEO, PETROTEL INC., distributed
handouts and referred to slides of the Point Thomson field
(Copy on File.) The field has, in broad terms, 20 Bcf
(billion cubic feet) of gas. He explained that Bcf refers to
standard cubic feet in standard conditions and is the unit
of gas in which gas is traded or sold, and is equivalent to
about 2 billion barrels of stock tank barrels. A stock tank
barrel is a standard condition of barrels that is 50 degrees
Fahrenheit, 14.7 psi where oil is measured in gallons.
DR. CHOPRA explained that there is good porosity overall for
the reservoir with an overall average of 14 percent. He
related that the reservoir has three dome-like structures
with a fairly large reservoir, over 72,000 acres within the
boundary. There is a gas cap with varying composition and an
oil rim. He reiterated that the gas cap is called a
retrograde gas condensate and referred to Representative
Gatto's question regarding an increase in pressure resulting
in the gas becoming more like a liquid. He stated that that
is exactly what happens. At high pressures gas and liquids
look alike, so it is a single phase in the reservoir.
However, when the pressure is dropped, gas becomes more gas
like and liquid stays like liquid, and the liquid drops out
in the reservoir. This accounts for the two phases and
separation of liquid in the reservoir when pressure drops.
He pointed to the slide showing the Point Thompson
simulation model and defined SG as gas saturation. There is
a thin oil rim in a doughnut shape around the reservoir.
This is a large area, almost 15,000 acres, with a
significant amount of oil in the rim.
9:39:50 AM
DR. CHOPRA said the gravity is low at an api gravity of 18.
He stated that those were the numbers used in the simulation
models. This gives an idea about the pressure. The reservoir
is around 12,500 feet on average. If the reservoir were
normally pressured, it would be considerably lower. He
pointed out that the reservoir pressure is on average 10,000
psi, making it a very high pressure reservoir. This makes it
great for production because it provides excellent support
to produce all of the gas and oil in the reservoir.
9:41:04 AM
DR. CHOPRA explained that about 70 different scenarios or
simulations were conducted. The simulations varied the
production of the reservoir from about six wells with
primary depletion in the gas cap in the mini case to 22
producers in the oil rim, 14 producers in the gas cap and
additional 12 injectors in the gas cap. There were quite a
few variations over these 70 scenarios with a number of
wells. He commented that it is very cheap to drill wells in
simulations and study different scenarios; the beauty of
reservoir engineering is the ability to plan ahead to see
what kind of recoveries can be expected, what kind of rates
can be expected as a function of time, and the optimal time
to produce oil and/or gas. He stated that the scenarios were
designed to look at well configurations, operating
constraints of a high pressure reservoir, and the bottom
hole pressure constraints of the producers as well as the
number of wells. He observed that Point Thomson is 10 Bcf
and 2 billion more or less oil. The central question of the
study is how many wells, over how many years, it would take
for production. The impact variables were evaluated on
ultimate recovery. Methods were studied without physical
constraints such as location, well size, or facilities,
which were beyond the scope of the study. The study focused
on rates and recoveries.
9:43:01 AM
REPRESENTATIVE GATTO questioned whether 2 billion barrels of
oil, as cited by Dr. Chopra, was correct and referred to
previous testimony that suggested there was 500 million
barrels of oil.
DR. CHOPRA responded that he had been rounding up to get 2
billion and answered that the number is gross including
condensate of the gas cap, plus the oil rim, plus other oil
here and there. He continued that the number is closer to
1.5 billion and not 500 million.
9:43:47 AM
SENATOR HUGGINS questioned the age and reliability of the
studies and data used for the modeling.
MS. HOULE explained that publicly available, in-house data
was used from wells that have been drilled. Modeling was
used since there is not enough drilling information
pertaining to the Point Thomson reservoir to delineate the
oil rim, the gas cap and the condensate. Given this fact,
the department's data set was used in the PetroTel study.
9:45:28 AM
SENATOR HUGGINS questioned the reliability of the data was
used for the modeling and asked for the well dates.
MS. HOULE replied that the department did the best technical
evaluation possible with the data available.
MS. THOMPSON clarified that the last well in the unit was
drilled in 1982. The earliest wells were drilled in the
1970s. She emphasized that the modeling project was done
with the data they had available and acknowledged that it
was imperfect and limited due to the number of wells that
have been drilled in the area.
SENATOR HUGGINS summarized that the data is old and
questioned if PetroTel Inc. attempted to update the data.
9:47:23 AM
DR. CHOPRA clarified that DNR data was used. His company
looked at the quality of the data and accepted what they
felt was reasonable and rejected what they felt was not. He
reported that the fluid composition data was very good and
reliable, with many samples taken with different condensate
rates and condensate ratios. The porosity data was also very
reasonable. He concluded that a large field with so few
wells gives the 8-10 uncertainty that Mr. Moothart has
suggested.
9:48:10 AM
REPRESENTATIVE SAMUELS questioned how much of the in-place
gas would be recoverable.
DR. CHOPRA explained that the 70 scenarios were studied to
look at how much gas and oil could be recovered over various
time periods. The study looked at the number of wells it
would take and the best recovery mechanism. For example, the
study looked at whether the best recovery method was
blowdown, gas cycling or an enhanced oil recovery process
(EOR). PetroTel is a leader in EOR and the study examined if
it would be possible to get both oil and gas at the same
time. This was the purpose of running 70 simulations. The
simulations were run on very high speed work stations with
multiple central processing units. With today's technology
it is very feasible to do these simulations quickly.
DR. CHOPRA discussed the simplest case first. He explained
that to produce a gas reservoir you punch holes, start
producing gas, and deplete the reservoir. As the reservoir
is depleted the pressure drops down, the rates drop down and
the reservoir runs out of life in 15-25 years. The first
scenario concerns primary depletion. If 22 wells are
operated over 12 to 15 years, 70 percent of the gas would be
produced. If only six wells were drilled it would take 50 to
60 years to deplete the reservoir. Fewer wells result in a
longer reservoir life, with a lower recovery rate. A larger
number of wells would produce the gas quicker. In the
primary depletion case, as gas is produced the pressure
falls and the liquid drops in the reservoir. As a result,
gas condensate recovery is approximately 26 percent (74
percent of the condensate is lost). This phenomenon is very
well known in the industry; when pressure drops below the
dew point, condensate is left behind. He concluded that
pressure maintenance is required to increase condensate
recovery. Three adverse things happen during primary
depletion of a gas condensate reservoir. One, gas condensate
is left behind. Second, wells have a condensate bank, liquid
sitting around, which hurts the productivity of the wells.
This can result in a drop of productivity of up to ten fold.
For example, if a gas well is producing 100 million a day,
when the condensate drops out it may drop to 10 million per
day.
DR. CHOPRA explained the difficulty of bringing the pressure
up and the condensate back into the gas cap once the
condensate drops out. The second scenario is a scheme that
does not allow the pressure to drop below the dew point and
cycles gas for a number of years, which recognizes that a
blowdown is always possible after the liquids have been
produced. During all of the gas cycling cases, gas pressure
is maintained until all recoverable condensate and oil are
produced. It is hard to produce the thin oil rim during
primary depletion in the blowdown phase once the reservoir
pressure drops. He reiterated that any oil in the rim
requires pressure to be produced, but once the pressure has
been dropped the thin oil rim will lose the pressure support
and will not be able to be produced.
9:52:43 AM
REPRESENTATIVE ROSES questioned whether the statement
"maintain reservoir pressure until all economically
recoverable condensates are produced" contradicts slide 7,
last item: "no physical constraints such as location of
surface drill sites and facilities or drilling departures
were modeled". He questioned how economic recoverability
could be determined if there was no consideration for
constraints, no risk application and nothing about economics
or costs.
9:53:44 AM
DR. CHOPRA asked him to wait two more slides for the
explanation. He noted that gas cycling was applied in the
gas cap in conjunction with development of gas injection in
the oil-rim. The study looked at a case of gas cycling for
20 years where the condensate recovery was increased from 25
to 76 percent. He concluded that gas cycling and maintained
reservoir pressure enables 76 percent of the condensate to
be recovered in the gas cap. Pressure in the reservoir
allows recovery of 43 percent of the oil rim and maximizes
oil production. He added that gas can always be produced
after the oil has been recovered.
The study also looked at the gas cycle for 10 years. This
resulted in recoveries of 62 percent condensate and 39
percent oil rim. Subsequent blowdown of the gas cap after 10
to 20 years recovers almost 56 to 57 percent of the original
gas in place in this particular gas cycling scenario.
9:55:02 AM
DR. CHOPRA discussed oil development. The oil rim as seen in
the database is not very well defined. They tested oil
production at 2,300 barrels per day at 18 degrees API.
Prudhoe Bay oil is 27 degrees API and Kuparak oil is 23
degrees API. Once gas cycling is started and that gas is
mixed with 18 API oil, it can lighten up the oil, and
decrease viscosity and the swelling effect. Experience has
shown that this oil production would require horizontal well
technology. This technology, which is now common worldwide,
was not available 20 years ago. He reported that long
horizontal wells in the oil rim are necessary because
without them the gas starts coning into the oil rim,
resulting in the oil wells very quickly gassing out making
it impossible to produce that oil.
DR. CHOPRA stated that if the horizontal wells are placed in
the oil rim parallel to the gas/oil contact the wells can
produce for a very long time. Gas injection in the oil rim
also helps to reduce viscosity and should be considered in
this reservoir. Carbon dioxide injection can expand the oil.
Point Thomson will be an excellent place to sequester, store
and recover oil if Prudhoe gas with 15 percent carbon
dioxide content is available. Use of off-site gas from
nearby fields can be injected to maintain the pressure (see
Slide 10).
9:56:56 AM
SENATOR HUGGINS asked if it is accurate to describe the
development of Point Thomson reservoir as necessitating
state of the art technology and drilling capability that was
not available some years ago.
9:57:41 AM
DR. CHOPRA agreed that Prudhoe Bay took state of the art
technology to develop thirty years ago. He stated that
horizontal wells like Prudhoe Bay were being drilled about
18 years ago.
9:57:57 AM
SENATOR HUGGINS concluded that Point Thomson as a reservoir
is very complicated with uncertainty and risks. He wanted to
know if techniques to develop Point Thomson have only
emerged recently.
DR. CHOPRA responded that the main difference with Point
Thomson is the high pressure. He felt development would
depend upon how comfortable an operator would be working
with this high pressure.
SENATOR HUGGINS asked if it was common in different well
sites around the world to have pressure of 10,000 psi or is
this unique.
DR. CHOPRA replied that there is a very large field in
Kazakhstan called Kashagan with pressure of 10,200 psi that
is very much like Point Thomson. The field has a content of
15 to 35 percent. The field will produce gas and do gas
cycling with high pressure gas injection using compressors
made by General Electric. He observed that the project is
currently being implemented and production will begin in a
couple of years.
REPRESENTATIVE SAMUELS queried the number of worldwide
fields with a 10,000 psi that are producing or being
developed.
DR. CHOPRA replied that there are at least ten high pressure
fields around the world. There is one reservoir in the Gulf
of Mexico with high pressure and high temperature and
another field with pressure of 16,000 psi. There are high
pressure fields being produced. Pressure provides energy so
less wells are needed, thereby increasing producibility. The
key issue when there is high pressure is gas cycling and the
ability to get the compression necessary to cycle gas. He
stated that in his opinion General Electric has the
technology to do that.
SENATOR STEDMAN asked if there were any of these high
pressure reservoirs located in the Arctic or Subarctic or if
they were all in warmer climates.
DR. CHOPRA responded that the field in Kazakhstan has
temperatures ranging from -40 degrees to very hot
conditions.
REPRESENTATIVE SAMUELS asked if the carbon dioxide in
Prudhoe Bay is needed for recovery or pressurization or if
it was a waste.
DR. CHOPRA responded that Prudhoe has been undergoing gas
cycling for over 30 years and injecting 7.5 Bcf of dry gas
back into the reservoir. Prudhoe has been using an enhanced
oil recovery process for almost 25 years, taking a solvent
and injecting in the oil rim for production. As a result,
the utility of Prudhoe would be potentially less. He
observed that Point Thomson is a virgin reservoir with the
oil rim.
10:02:55 AM
REPRESENTATIVE GATTO stated that Point Thomson is a very
high pressure reservoir and if high pressure is a problem,
it would not take much to lower the pressure. He asked if it
is more desirable to work with lower or higher pressure, and
if there were an ideal pressure.
DR. CHOPRA answered that from a recovery point of view
pressure is good for every reservoir, but from an
operational point of view people may say that high pressure
is not good. The study looked at a scenario in which the
pressure was dropped to 8,000 psi with gas cycling, which
gave lower recoveries that were still much higher than
blowdown. He suggested high pressure should be used where
resources are available. Decompressors will go up to 19,000
psi, but may be cheaper at 10,000 psi. He emphasized that it
is then an economic decision to increase the pressure and
maximize recovery.
REPRESENTATIVE GATTO inquired about the benefit of bringing
some of this high pressure into Prudhoe Bay. He wondered if
it could be used for a gas line.
DR. CHOPRA said that pressure has been maintained for a very
long time in Prudhoe Bay. In fact, 7.5 tscf per day has been
used to maintain pressure and water has been injected in the
periphery as a solvent. Pressure is always good, but in the
late mature state of well life it becomes an economic
decision.
SENATOR WIELECHOWSKI clarified that gas is needed in the
field to produce the oil and condensates. He asked if it
would be possible to pull off a portion of the gas now or in
the future when the gas pipeline is on line, while oil and
gas condensates are being pulled or if it is necessary to
wait until all the oil and condensates are gone.
DR. CHOPRA stated that Slide 11 would answer this question.
He continued by saying that in the primary depletion
potential oil rim recoveries ranged from 3 to 16 percent and
that gas cycling could recover 45 percent of the oil rim. He
qualified that the oil rim volume and potential ultimate
recovery and delineation of the oil-rim during gas cycling
will determine the scale of development.
DR. CHOPRA referred to Slide 11 to answer Senator
Wielechowski's question. He said that by looking at a
scenario in which pressure is maintained, using 22
horizontal wells producing almost 160,000 barrels of oil per
day, there would be a gradual decline over the next 15 years
until the rate drops down to approximately 25,000 barrels
per day. He noted that the cumulative oil production line on
the graph shows a plateau, which is why the term
economically desirable is used. He said that it is
preferable to produce oil when going up that slope, as the
more gas is being injected and producing oil. He added that
the graph shows a slope change, which means the incremental
value for continuing becomes less and less because much of
the oil has already been produced. Optimization theory
asserts that it is time to start producing the gas cap after
15 years when most of the condensate has been recovered.
10:08:05 AM
DR. CHOPRA restated that the earlier Point Thomson is
developed, the earlier the gas will be available for the
pipeline. In this case, if Point Thomson were started today,
it would be available in 15 years. The gas would be
available for production if the pipeline plan takes 10 years
to get ready, and another five years after it gets
commissioned.
SENATOR WIELECHOWSKI asked how closely this tracks Exxon's
twenty third plan of development (POD).
DR. CHOPRA answered that he had not looked at that POD.
SENATOR WIELECHOWSKI responded that Exxon wanted to extract
10,000 barrels of condensate per day.
DR. CHOPRA pointed out where 10,000 would be on the graph
(Slide 11).
MR. MOOTHART pointed out that the graph shows both
condensate and oil rim development. "It's from the model and
it's a full scale development of those resources." He
reiterated that there are twenty-two horizontal wells in the
oil rim.
DR. CHOPRA said that one case was run (see handout) with
about five or six wells that produced 10,000 barrels per day
of condensate.
SENATOR WIELECHOWSKI asked if this is the optimal Point
Thomson production schedule for Alaska.
MS. HOULE responded that the analysis is only as good as the
data and the data set is incomplete. As Nan Thompson pointed
out, the last well was drilled in the early 1980s. The model
is based on the information available.
10:11:11 AM
SENATOR WIELECHOWSKI questioned, based on Exxon's unit
development, a decision could be made that will determine
what is good or bad for the state. He queried how the
decision can be made if the data is unknown.
MS. THOMPSON opined that that decision is not before the
legislature today. She said that was the subject of
Commissioner Irwin's decision on remand that was issued
April 22. She specified that she was not trying to be
evasive and suggested that there was a detailed analysis by
the commissioner based on the existing information of the
proposed plan of development. She offered to provide the
page numbers if needed. She disclosed that the attorney
general advised that there should not be a reiteration or
further discussion of what was said in the decision due to
pending litigation.
SENATOR WIELECHOWSKI replied that he was trying to figure
out whether the twenty-third POD is in the best interest of
the state. He understood Ms. Thompson's inability to
comment. He understood the plan to say that 10,000 barrels
of condensate a day would be produced. He thought the graph
showed more production than proposed by Exxon.
MS. THOMPSON pointed out that Commissioner Irwin did not
approve the twenty-third plan since it was not in the best
interest of the state, which is the topic of litigation. Her
comments were meant to convey that without further, more
detailed information about the reservoir, which is not
available because wells have not been drilled for many
years, it is difficult for anybody to come up with the
optimal recovery plan. She concluded that within that
twenty-third recovery plan there was considerably less
production than demonstrated on the graph.
10:13:38 AM
DR. CHOPRA reiterated that the reservoir has a big gas cap
with condensate. Most of the uncertainty is in the oil rim,
but the gas cap alone has 490-600 million barrels of
condensate. He suggested that the focus should be on that
certainty, which is pretty high because all the wells tested
have produced condensate, all the logs have shown gas up and
down, and all the wells have produced gas. That can be
interpreted to mean that even with gas cycling for the gas
cap, a lot more condensate can be produced. There is also
one scenario in which just the condensate is produced
without oil rim development with rates close to 100,000
barrels per day for some years.
SENATOR HUGGINS queried Dr. Chopra's confidence level and
asked him to provide a benchmark.
DR. CHOPRA responded that the fluid data for condensate
looks pretty reasonable and everything ties together. Dry
gas cycling is an obvious choice getting fairly good rates
since there are 600 million barrels of condensate in the gas
cap.
SENATOR HUGGINS suggested a confidence level above 50
percent for and asked whether Dr. Chopra's confidence level
in terms of development and extraction was about the same.
DR. CHOPRA responded that it was higher.
SENATOR HUGGINS asked about the likelihood of horizontal
wells for oil rim production and what would be required if
these wells did not work.
DR. CHOPRA clarified that there are a couple of ways to do
the recovery. Horizontal wells are desirable in oil rim
development if there are going to be coning issues. Coning
issues take place when producing the oil rim and bleeding
the pressure rapidly. Horizontal wells might not be needed
with new methods, like carbon dioxide injections that
pressure up the oil rim.
RECESSED: 10:16:59 AM
RECONVENED: 10:30:58 AM.
REPRESENTATIVE GARA referred to Exxon's failure to develop
Point Thomson. He pointed out that this has gone on since
the 1970s with the last major work being done in the 1990s.
He spoke in defense of the state's data, which is the data
that Exxon produced. When Exxon stopped producing data the
state stopped getting data. He maintained that the state
would be closer to production at Point Thomson if Exxon had
honored its lease. Estimates show that gas production at
Point Thomson would be 10 to 20 years away if oil and gas
condensates are produced before gas. He questioned if there
is a way to force, through a lease-bid (after the lease is
taken back from Exxon), to have the new lease owner produce
the oil and gas condensates more quickly, maybe in an
enhanced processing facility or by drilling more wells and
operating more wells. He wanted to know if there are ways to
get the oil and gas condensates out more quickly for use in
the gas pipeline. He inquired if there was any chance of
getting the gas out in 12 to 15 years to meet one of the
early open seasons in conjunction with the pipeline designed
as a larger capacity pipeline. He concluded that if this is
not possible, the damage that the state has been caused by
Exxon's failure to produce Point Thomson is that now the
pipeline project is being scaled back.
MS. THOMPSON explained that in the state's development of
its oil and gas lands, the lessees do the drilling and
collect the data, and not the state independently. She
agreed that the lessees in this case are responsible for the
dearth of data rather than the state itself. She reported
that regarding moving production forward more quickly
through another lease sale, the Division of Oil and Gas has
looked into the structuring future sales of the leases in
this area. It is possible under current statues to put
conditions of development in a lease and it may be necessary
to relook at the leasing statutes to provide more
flexibility. In other areas of the world where lands are
leased for oil and gas development, there are development
conditions in the lease; the state is looking at this very
carefully. She emphasized that these lands are unique.
Usually when lands are first leased for oil and gas
development, there is no knowledge about what is contained.
The purpose of an oil and gas lease is to encourage
exploration and development. In this situation, the state
does have information, though it is somewhat limited. She
surmised that the state could use a different method than
what has traditionally been used and that the state should
look at different options to maximize the value for the
recovery of the resources on these lands.
REPRESENTATIVE GARA commented about Exxon's failure to
develop Point Thomson resulting in an inability to explore
and produce the collection of data.
SENATOR HUGGINS contended that the litigation piece is what
it is. He responded that Exxon would speak for themselves
later during their time.
10:36:05 AM
REPRESENTATIVE GARA asked if it would be possible to give
the history of the failure to produce data, the failure to
explore on Point Thomson, and the failure to produce.
SENATOR HUGGINS replied that this could be discussed later.
REPRESENTATIVE HAWKER noted that the data appears very
precise and questioned the confidence level that can be had
in this data. He said that there are three strata with the
lower level of Brookian sands, medium strata of Point
Thomson sands, and at the bottom, the oil rim and the pre-
Mississippian issues that have not been looked into yet. He
asserted that the full document is more cautious about the
credibility of the interpretation, particularly for the oil
rim. This is true especially for the oil rim where AOGCC is
charged with looking at the best way to get immediately to
the Point Thomson sands, the condensate development. He
observed that AOGCC must also determine how to get the
maximum of all the hydrocarbons by looking at the oil rim on
the bottom. There are a lot of assumptions about the oil rim
and about the other strata. "It seems to me that it is very
much an unknown whether or not the premises you are basing
this analysis on are as accurate as it might be inferred in
the presentation." He asked what is known about the
properties of the oil rim and whether a high degree of
confidence can be given regarding the accuracy of the
modeling.
10:39:06 AM
MS. HOULE responded that the reason there is uncertainty in
the conclusions is the lack of data. She said that the data
the state has is basically the data the industry has. Part
of the reason for this study was to take the available data,
given that it is more in exploration mode than in
delineation mode, to see what the realm of possibilities of
the reserves were. As a geologist, she looks at the minimum
(P10) and at the imagined potential (P90), and then there is
the case of beyond one's wildest dreams. On the North Slope
almost every field that has been produced has been beyond
geologists' wildest expectations. Prudhoe originally was
expected to recover 8 to 9 billion barrels and now
expectations are at 14 billion. Most fields on the North
Slope have done better than expected with two notable
exceptions, Lizborn and Bendami. A lot of fields have been
beyond the P90. She said that she did not see the Point
Thomson sands as an extension of the Bendami. She stated
that this is a different discussion.
REPRESENTATIVE HAWKER summarized that his concern is about
the precision of the presentation when the properties of the
oil realm are unknown.
MS. HOULE responded that that was because of the lack of
delineation drilling.
10:41:26 AM
SENATOR STEDMAN acknowledged that the data set used in the
analysis is old and that the data is derived from the
industry. He asked what kind of dialogue there has been with
the industry and various corporations and if there had been
any agreement. He questioned if there was full agreement on
the dew point or other areas, and if there been
communication with industry.
DR. CHOPRA responded that there were three components of the
study. The first component is the gas cap, the 8-10 Bcf of
gas with condensate. The second component is how to get the
condensate out of the gas cap. The third component is oil
rim development, specifically what is there and how to
develop it. There is old bad data and old good data. He
emphasized that not all old data is bad data. Some of the
data is very high quality and very comprehensive. Referring
back to the precision of the study, he said that the
conclusion about the gas is expressed as 8.5 to 10.5
trillion standard cubic feet, which is expressed in a range
and relates to Point Thomson sands only. The condensate is
490-600 million stock tank barrels expressed as a range,
which has been derived from averages. The potential oil rim
is 580-950 million stock tank barrels. This range, while not
precise, is big - half a billion to one billion barrels. He
said that extensive uncertainty analysis was completed,
which has given these ranges of what is believed to be in
the reservoir. People have produced gas fields in the world
with four or less wells. He pointed to the reservoir
pressure slide and stated that it shows high pressure on the
east side, south side and west side. He emphasized that this
showed good continuity high pressure, which means that the
sands are continuous and the gas is there. He inferred from
this data that the gas is there throughout the reservoir. He
emphasized that this information is from a large number of
wells, not just one or two. The uncertainty is in the oil
rim, as there are fewer tested intervals; hence the
conclusion of first doing gas cycling, then developing the
condensate and while doing that, do delineation of the oil
rim. This is a typical way to proceed in terms of oil rim
development, as it provides more confidence in its
development.
10:45:35 AM
SENATOR STEDMAN wanted clarification regarding how much of
the conclusions are in agreement with the administration and
the industry, and how much are subject to debate. He also
wanted to know if there has been any dialogue in the areas
where there is disagreement. He wanted to sort out what
information he should be paying attention to and what
information is irrelevant to any decision making.
MS. HOULE clarified that data from industry is raw data,
which the state interprets. This study took raw data and
interpreted it. She said that the division did their own
independent analysis, but PetroTel's expertise in reservoir
engineering was needed. The state had to use the industry's
data set. In general, the operator provides the data when
the unit work is done. She said there is more dialogue with
some companies than with others.
10:47:59 AM
MS. THOMPSON said the history of this unit and the dialogue
between industry and the state would be articulated later.
REPRESENTATIVE FAIRCLOUGH expressed concern about engaging
in litigation and how it would impact the timeline for
bringing gas on line and making it economical for Alaska.
MS. THOMPSON replied that the timeline would be addressed by
Commissioner Foerster later.
REPRESENTATIVE FAIRCLOUGH reiterated her question asking for
an engineer's prospective. She wanted to know specifically
how much oil will be removed along with a timeline showing
when it gets to gas, which will help in determination of the
timeline for Point Thomson and help support economically
Alaska's natural gas pipeline.
10:51:38 AM
DR. CHOPRA responded by explaining Slide 11, which shows
that producing oil only for 15 years, without producing any
gas, would result in recovery of up to 650 million barrels
of oil. Earlier the analysis showed just the blowdown case.
In that scenario, the production is only 150 plus or minus
barrels of oil. He queried whether it was worth getting half
a billion barrels of oil in 15 years with current market
value of $70 billion dollars and waiting 15 years to produce
gas, or sacrificing that oil and start producing that gas
today and delivering it to the pipe.
MS. FAIRCLOUGH responded that this would require two
different sets of pipes in Point Thomson if oil is produced
first because the gas line could serve to pipe the oil, but
not vice versa. An oil line would have to come out of the
field first as a capital structure infrastructure cost and a
gas line to follow that.
MR. MOOTHART answered that some infrastructure would be
required to get the oil from Point Thomson, but not all the
way back to the North Slope since there is Badami.
MS. FAIRCLOUGH pointed out that gas would be needed to be
brought in to maintain gas line pressurization.
MR. MOOTHART expressed that the report outlines this as a
possibility because if the oil rim turns out to be as good
as or better than expected and a full development ensues,
which may include 30 wells, then you are increasing voidage
or off-take. In order to maximize that full development
something will need to be brought in to make up for that
voidage and to maintain the pressure. This creates a
balancing act, which is outside these analyses. He said this
will be determined during initial gas cycling and further
delineation of the oil rim and the scale of that development
of the oil will be determined and is not a foregone
conclusion.
10:56:10 AM
REPRESENTATIVE FAIRCLOUGH said that understanding Point
Thomson and its timeline for natural gas production may give
a better understanding of the economics regarding moving
forward on the issue, at least from the private sector.
REPRESENTATIVE KERTULLA was not concerned about the old data
being bad, but wanted to know the impact of the litigation.
She wondered if there was not litigation, if there would be
access to more data and a more cooperative working
relationship.
MS. THOMPSON answered that it has been a long battle to get
where they are today after 30 years with no development, and
as a result they have not had the dialogue with operators
and other units about how land should be developed.
REPRESENTATIVE KERTULLA requested a walk-through of that
history, as it will be important later.
10:58:32 AM
DR. CHOPRA reviewed Slide 12 by saying that in primary
depletion 6-7 tscf gas is recovered and gas cycling in 15-20
years gives 620-850 mmstb of condensate and oil. He stated
that the conclusion of the analysis is that additional wells
are needed to delineate and test the Point Thomson oil rim
and pressure maintenance is definitely required to maintain
maximum producibility of the wells as well as maximize the
recovery of the condensate.
MS. THOMPSON provided background information on the Point
Thomson Unit and the litigation history and status. She
explained that the essence of an oil and gas lease is timely
production. The state agrees to lease its land to a
developer in exchange for a share of the production, which
is paid as royalties. Oil and gas leases contain a
commitment that the lessee will diligently explore and
develop the property. When a lessee fails to fulfill this
duty, the lease is forfeited. Article 8, Section 8 of the
Alaska Constitution mandates that a lessee's breach of duty
to develop results in forfeiture.
11:00:51 AM
MS. THOMPSON observed that oil and gas lease is a temporary
(commonly 5 to 10 years) right to explore for and develop
hydrocarbon resources. The purpose of the primary term of a
lease is to allow the lessee sufficient time to explore,
delineate, and produce the hydrocarbon resources. Leases
expire at the end of their primary term unless the lease is
producing oil or gas or the lease has become part of a unit.
MS. THOMPSON explained that units are formed when a group of
lessees apply to the state to form a unit because their
leases overlay a common geologic formation that holds
recoverable oil or gas. She provided members with a map
delineating different leases (Copy on File). It illustrates
that geology does not follow straight lines along state
leases. So lease holders determine where the formation is
and come together as a unit for greater efficiency. Oil and
gas leases are owned by different entities. There are about
48 units in Alaska, 14 on the North Slope and 34 in Cook
Inlet. Unitization extends the term of lease so that the
discovered resources can be produced in an efficient and
coordinated manner that will maximize recovery and minimize
waste.
11:03:20 AM
MS. THOMPSON explained that Exxon Mobil acquired several
leases in the Point Thomson area in 1965. Exxon Mobil and
Chevron acquired 14 more leases in 1969 and 1970. The
majority of the remaining leases were acquired in the 1980s
and early 1990s.
MS. THOMPSON pointed out that the Point Thomson Unit was
formed in 1977 with 18 leases comprising approximately
41,000 acres of state land. The boundaries have been
expanded and contracted several times in the last 30 years.
Unit boundaries can be expanded to include lands proven to
overlay a producible resource. Unit boundaries are
periodically contracted to exclude leases the unit operator
fails to develop. The state's form unit agreement requires
that all lands not included in a participating area or PA (a
process used to allocate production for royalty accounting
purposes) within five years of formation of the unit
contract out of the unit. The Point Thomson unit included 45
separate leases with approximately 106,000 acres of state
land when Commissioner Menge issued his decision to
terminate it in November 2006. Therefore any discussion
about a lease depends on which lease. The leasehold
interests were held by Exxon Mobil (52 percent), BP (29
percent), Chevron (14 percent), Conoco (2.8 percent), and
other minor interest holders.
11:07:13 AM
MS. THOMPSON explained that the working interest owners
elect a unit operator to manage the unit's business; Exxon
Mobil has been the unit operator throughout this unit's
history. Under the Unit Agreement, Exxon Mobil was primarily
responsible for exploring and developing the unitized lands.
In the recent remand hearing, the working interest owners
submitted amendments to the unit operating agreement to
change the voting percentages, with the stated purpose of
preventing one of the major owners from blocking an action
the other two agreed upon. Those amendments were contingent
on DNR's acceptance of the 23rd POD and not agreed to by
ConocoPhillips; thus their current status is not clear.
MS. THOMPSON said that during the first five year of the
unit's existence, Exxon Mobil submitted five one-year PODs
and drilled several exploration wells. The first POD
promised that if oil was discovered in sufficient quantities
to warrant future development, the Prudhoe Bay to Valdez oil
pipeline will be the probable marketing outlet for the area.
Since the early 1980s, Exxon Mobil has known about the
existence of significant quantities of oil and gas
condensate, but has not produced anything.
MS. THOMPSON continued that despite significant uncertainty
about the unit's resources, the unit operator drilled no
more wells after 1982. New wells would yield geophysical
data that would resolve the remaining uncertainties about
the reservoir. Two wells were drilled by BP and Chevron in
the 1990s and several other wells were drilled by other
producers on lands outside of the unit boundary.
MS. THOMPSON pointed out that the unit agreement originally
provided for expiration after five years if lessees failed
to form a participating area. Participating areas are formed
before production begins to allocate the production to the
appropriate lease. Thus, when the parties signed the unit
agreement, they expected that the unit would begin
production by 1983. Because Exxon Mobil was unable to commit
to production by then, DNR agreed to remove the PA formation
requirement to prevent the unit from terminating. The
amendment extended rather than removed the obligation to
produce. When DNR agreed to amend the unit agreement it
expected that production would begin by the late 1980s.
11:10:33 AM
MS. THOMPSON observed that since 1983 can be characterized
as a struggle between the state and the unit operator, with
DNR demanding development activity and Exxon Mobil either
insisting that it was not economic or promising to drill
wells that were never drilled. The remand decision and
decision on reconsideration detail the history.
MS. THOMPSON explained that in 1985 and 1990, DNR contracted
leases from the unit because lessees failed to drill
promised wells. In 1995 DNR rejected the 12th POD because it
did not include a development commitment. Significant
quantities of oil were discovered by Exxon Mobil in 1975,
and by BP and Chevron in 1994. The unit plans have never
included development of this oil. By the time the 13th POD
was due, the Division of Oil and Gas had a new director who
accepted Exxon Mobil's promise to develop the unit lands
with "farm-out" agreements. Then Director Boyd dearly stated
the division's objective: "Most importantly the division
wants a fair and honest attempt to get this acreage explored
and be appraised of efforts to develop and produce the Point
Thomson sands accumulation itself."
MS. THOMPSON said that when the negotiations over the
Stranded Gas Development Act became active in 1997, Exxon
Mobil linked Point Thomson development with construction of
a gas pipeline. Exxon Mobil suggested that before the
construction of a gas line, it would produce the hundreds of
millions of barrels gas condensates through a gas cycling
program. In 2001, Exxon Mobile also promised that the Point
Thompson Unit's considerable oil reserves would be produced
starting in 2010. From the late 1990s until 2005, DNR
approved PODs with the expectation that wells would be
drilled to further delineate the unit's resources and that
Exxon Mobil was progressing towards production with
development drilling to begin by 2006. During this period,
Exxon Mobil drilled no wells.
MS. THOMPSON further explained that the DNR unit litigation
has been successful so far and the litigation will probably
continue to the Alaska Supreme Court. The basis for the
litigation was the 2001 second expansion agreement and the
18th though 22nd PODs that were designed to implement the
commitments made in that agreement.
11:14:26 AM
MS. THOMPSON discussed the unit litigation. In 2001, Exxon
Mobil asked DNR to expand the unit and filed the 18th POD.
They repeated their commitment to develop the land by
saying: "The Owners have endeavored in the attached response
to unambiguously demonstrate our commitment to the
development of the Point Thomson Unit. We are committing to
an aggressive work program and the expenditure of
substantial funds that will put us in a position to initiate
project execution activities as early as possible." That
"unambiguous' commitment was to expedite permitting and
engineering studies, drill an exploration well by 2003, a
production well by 2006 and seven more production wells by
2007. DNR agreed to expand the unit based on these
commitments, but none of the proposed development activity
occurred. Exxon Mobil eventually paid a penalty of $20
million, plus interest, for failure to perform the promised
work.
11:15:35 AM
MS. THOMPSON explained that since the 21st POD expired In
September of 2005, this unit has not been operated under an
approved plan of development. The first proposed 22nd POD
was submitted and rejected because it did not contain
adequate work commitments. Intense negotiations ensued, but
the revised POD submitted months later was also rejected.
The unit was put in default. The working interest owners
asked for reconsideration and appealed to the commissioner.
At the end of the Murkowski administration, Commissioner
Menge terminated the unit because Exxon Mobil submitted a
POD that did not comply with Director Myers' criteria for
what an acceptable POD must contain. Acting Commissioner
Rutherford affirmed Commissioner Menge's decision when the
lessees asked for reconsideration after the new Governor was
sworn in.
11:17:12 AM
MS. THOMPSON clarified that the litigation began with
lawsuits filed in Superior Court that were eventually
consolidated before Judge Gleason. Exxon Mobil also
separately filed an action for damages and injunctive relief
that was dismissed by Judge Michalski. Exxon Mobil appealed
the dismissal, but never filed their brief with the Alaska
Supreme Court.
MS. THOMPSON continued that Judge Gleason ruled in December
2007 that DNR properly rejected the 22nd POD and that it had
the legal authority to terminate the unit, but remanded the
case to the agency because she found that DNR had not given
the parties enough notice that the unit might terminate and
the opportunity to argue about other alternative remedies.
The unit litigation progressed till 2007, when the judge
ruled and remanded to DNR that the case might terminate. The
decision came to the same conclusion and sent back to the
judge. The record is in the process of being the final
decision is likely to be appealed to the Alaska Supreme
Court, which normally takes two years to complete.
MS. THOMPSON explained that DNR had a hearing earlier this
year on the 23rd POD, the remedy proposed by Exxon Mobil.
Commissioner Irwin found that the proposal did not meet the
statutory criteria for approval and did not protect the
state or public interests. Commissioner Irwin also found
that the lessees' failed to explain why termination was not
an appropriate remedy given the unit's history. When asked
to reconsider, he came to the same conclusion. The remand
record will soon be sent back to Judge Gleason. Judge
Gleason has not set a hearing or told the parties whether
she would like briefs and/or oral arguments on DNR's
decision. It is likely that her final decision will be
appealed to the Alaska Supreme Court.
11:19:15 AM
MS. THOMPSON discussed the lease process and timing for
reclaiming the 45 leases, which vary according to the lease.
Almost all of the leases are beyond their primary terms, and
thus held because they were a part of the unit. After the
initial unit termination decision, DNR began the process of
terminating the leases in February 2007 and the leaseholders
appealed. Further action on the lease appeals was delayed
until the status of the unit was resolved. Thus, agency
action on the status of all 45 leases is pending. Some may
be available for leasing in the next couple of years, long
before a pipeline is available. Others may be litigated
longer.
11:20:55 AM
MS. THOMPSON referred to the map (Copy on File) and
concluded that none of the leases are currently certified.
Green dots on the map identify leases that were once
certified. Red dots identify wells that have been plugged
and abandoned. The two yellow dots identify wells are
cauterized as suspended; they have been plugged and
abandoned, but have not received surface clearance from
AOGCC. Blue refers to leases beyond primary term that have
not had a well drilled and is the easiest to resolve. Yellow
indicates leases beyond the primary term that has had a well
drilled. The one pink lease is in its primary term.
Litigation is likely on the green leases. On the leases with
wells that were once "certified" there is a factual dispute
about whether the wells are still capable of production that
is likely to be litigated.
11:23:18 AM
MS. THOMPSON referred to the future and how things might
progress. The division may decide to release lands that are
currently available or wait. It is likely that the
conditions of the next lease sale will be different
considering the knowledge regarding the resources underlying
the leases.
11:24:19 AM
REPRESENTATIVE GATTO asked if there is drilling information
that is considered proprietary, owned by the driller and not
available to the state.
MS. THOMPSON observed that there is confidential data, which
is available to the state, but not available to the public.
The data for all but five wells is available to the public.
Some data is confidential due to its proximity to the ANWR
boundary.
11:26:05 AM
REPRESENTATIVE RAMRAS asked if the AOGCC's point of view was
creditable. MS. THOMPSON expressed respect for Commissioner
Foerster and felt that the information would be creditable.
11:27:04 AM
REPRESENTATIVE BUCH asked who controls the information data
and what entities are involved with the map.
MS. HOULE responded that industry has the same data that is
available to the state. Some data may not reside with AOGCC.
It is the responsibility of the companies to provide well
data to AOGCC.
MS. HOULE, in response to a question by Representative Buch,
observed that the state has statutes and regulations
regarding the collection of data. The AOGCC has its own
regulations. She explained that most of the state's data
comes from the unitization, summary of process, and seismic
permitting.
REPRESENTATIVE BUCH asked for additional requirements for
minerals management surveys, and other requirements on
Bureau of Land Management (BLM) and Native lands.
MS. HOULE noted that the state would not have access to
anything on private, Native lands. The BLM land is
administered by the federal government and includes Natural
Petroleum Reserves-Alaska (NPR-A). The state only receives
NPR-A data through the Economic Incentive Credit (EIC)
process. She observed that ACES provided tax credits and
data. Minerals Management Service is off shore data, which
releases seismic data after 15 years.
11:31:50 AM
CATHY FOERSTER, COMMISSIONER, ALASKA OIL AND GAS
CONSERVATION COMMISSION (AOGCC), provided a brief overview
of the AOGCC, which is tasked with the regulation of the
operations of oil and gas throughout the state. The Division
of Oil and Gas is responsible for maximizing the value to
the state of Alaska of the oil and gas under state lands.
The AOGCC regulates oil and gas operations throughout the
state, not just on state lands, but also on federal, Native,
and privately held lands. The state, by law, has no greater
standing in adjudications than any other party.
MS. FOERSTER noted that AOGCC has five primary
responsibilities: prevent waste of oil and gas, encourage
greater ultimate recovery of oil and gas, protect sources of
fresh ground water from harm by oil and gas operations,
protect human health and safety related to down-hole oil and
gas operations, and protect correlative rights, which is
done throughout the State, regardless of land ownership.
11:35:54 AM
MS. FOERSTER discussed AOGCC's day-to-day regulatory
oversight and focused on two responsibilities: preventing
waste of oil and gas and encouraging greater ultimate
recovery of oil and gas. She pointed out that the commission
is not tasked with making the most money, balancing the
budget, or making any particular set of constituents happy.
MS. FOERSTER explained that in engineering vernacular, Point
Thomson is considered a gas condensate reservoir or a
retrograde condensate reservoir. In such a reservoir, the
hydrocarbons are in the gas phase until the pressure drops
below a certain point called the dew point. When the
pressure drops below the dew point, some of the
hydrocarbons, the condensates, switch to the liquid phase
and drop out of the gas. When this happens, a substantial
portion of those liquids can be trapped in the reservoir and
can never be recovered.
MS. FOERSTER further explained that in many retrograde
condensate reservoirs, cycling (reinjecting the produced gas
over and over again to maintain high reservoir pressure
until the liquid condensate has been recovered) prevents
these losses. Cycling the gas until most of the liquids have
been recovered is the way to achieve greater ultimate
recovery and prevent waste from a gas condensate reservoir
such as Point Thomson.
MS. FOERSTER observed that publicly available estimates of
recoverable liquid hydrocarbons associated with the gas at
Point Thomson vary from 200 to 500 million barrels,
depending on the source and the method of development. She
emphasized that a significant portion of those liquids would
be at risk if Point Thomson is produced as a gas reservoir
without cycling first, and emphasized that the value of this
liquid resource is the size of another Alpine Field.
11:40:23 AM
MS. FOERSTER noted that there is a second potential problem
with not cycling first. As the reservoir pressure drops,
liquids will drop out in the place where the pressure is
lowest, adjacent to the wellbores if they are not cycled
first. When liquids drop out at the wellbores, they damage
the producibility of the reservoir and decrease the ability
of the wells to bring the gas up to the surface. The
operator can undo some of this damage through well
interventions, but these cost money, must be repeated as
additional damage is done, and eventually may no longer be
effective at fixing the problem. This is important to AOGCC
because it will result not only in liquid losses, but also
in gas losses. It is important to the state for that reason
and because, under ACES, the state shares the cost of these
interventions that will likely be done over and over to keep
the gas wells producing. She urged members to keep in mind
that cycling will likely add significant capital costs,
which the state would share via ACES.
MS. FOERSTER observed that a third problem exists regarding
producing the gas from Point Thomson. Underlying this thick
gas condensate reservoir is a relatively thin oil layer.
Much of that oil will be lost if the gas from Point Thomson
is produced before producing the oil.
MS. FOERSTER clarified that since AOGCC is charged with
preventing waste of hydrocarbon resources in Alaska and
since producing gas from an oil reservoir can cause waste,
they determine when and how much gas can be produced from
every oil reservoir throughout the state with an eye to
greater ultimate recovery of both the oil and the gas. The
commission does not typically dictate to an operator what he
must do. Rather, the operator typically comes to the AOGCC
with a request for permission to do something and they allow
it, disallow it, or allow some modification to the
originally proposed plan. They do not tell an operator where
or how deep to drill wells. The operator requests to drill a
particular well in a particular location to a particular
depth using particular procedures and AOGCC approves the
request, denies it, or approves it subject to limitations or
modifications. The same will hold true for gas off-take from
an oil field, such as Prudhoe Bay and Point Thomson. Before
the operator can produce gas from Point Thomson, the
applicant must come to the AOGCC and request a gas off-take
allowable. The applicant must prove that waste will not
occur. Without that proof the request is not granted.
MS. FOERSTER maintained that not enough is currently known
about the Point Thomson sand, either the gas portion or the
oil layer, to know what the right answer is for the oil
companies or the state. They do not know if there is
adequate connectivity in the gas condensate part of the
reservoir for cycling to work. If it doesn't work, then both
the oil companies and the state will have wasted a lot of
money. Not enough is known about the characteristics of the
oil in the oil layer to know whether it is technically
recoverable. In other words, even if all agreed to get that
oil first, they don't know if it can be done. The oil may or
may not be too viscous to produce; the gas above and water
below it may cone into the oil layer and drown out the oil
production; the extremely expensive wells required to
attempt to produce the oil may or may not be economical.
She concluded that they will never answer these questions
without a bit of drilling, producing, and cycling.
11:45:44 AM
REPRESENTATIVE HOLMES questioned why there has not been an
effort to recover the liquid condensates to date.
MS. FOERSTER could only guess, but observed that operators
generally define the biggest prize. Development is designed
around the recovery of the biggest prize. She thought that
Exxon Mobile had viewed the gas as the prize and the
technically challenged oil resource as the cherry. She
guessed that it did not justify development until the gas
pipeline was imminent. Exxon Mobile will either have to get
the liquids first or prove to AOGCC that it is not the right
answer.
11:49:19 AM
REPRESENTATIVE GATTO wanted to know if gas would need to be
imported to develop the oil.
MS. FOERSTER replied that it is possible that data will
reveal the need for gas to stay above the dew point. The
data seems to indicate that the dew point is close.
Additional data will determine the dew point. She observed
that Point Thomson is only one of the places that North
Slope operators are looking at using the carbon dioxide.
REPRESENTATIVE GATO observed the high pressure and expressed
surprise that the dew point would be so close.
11:51:20 AM
REPRESENTATIVE BUCH noted his visit to Calgary to see how
the information was more complete and accurate than what we
have here.
MS. FOERSTER stressed that data is difficult to extract due
to the technical challenges of drilling the wells.
Technology has advanced. The data dearth is not due to the
lack of adequate requirements. Data comes from core samples.
The state has access to all of Exxon's data. She did not
think that the uncertainly comes from access or
inappropriate data.
11:54:36 AM
REPRESENTATIVE BUCH asked the state's requirement for data
and questioned if there is a repository for the data.
MS. FOERSTER stated that the repository for wells that are
not confidential is the AOGCC's website. All of the data is
put on the website as soon as the well information is not
confidential. Confidential well data is kept in their
office. The commission requires cuttings, mud logs, open
hole and case hole logs, and core data. All additional data
and analyses becomes part of the public record.
11:56:35 AM
REPRESENTATIVE FAIRCLOUGH referred to Prudhoe Bay off-take.
She observed that AOGCC has an agreement with the producers
that would take off 2.4 Bcf/d. She asked if the take-off for
gas at Prudhoe Bay would be revalued and whether it would go
up or down.
MS. FOERSTER noted that the current off-take for Prudhoe Bay
is 2.7 Bcf/d. The only gas being used for anything other
than reinjection is the gas used for fuel for the seal and a
small amount of gas that is exported to other fields for
enhanced oil recovery. The off-take is approximately 0.7
Bcf/d. She did not see this amount decreasing when there is
a gas line because there will be additional facilities. Any
off-take would have to include this volume.
MS. FOERSTER noted that AOGCC completed a confidential study
with Prudhoe Bay owners, and that off-take would remain the
same until an operator request an increased allowance.
Providers must ask for a change. The answer would depend on
how much oil has been produced when the gas line is ready,
what mitigation steps have been adopted to decrease the risk
of losing oil, and the off-take rate.
MS. THOMSON observed that the unit manager must make an
application to the state of Alaska for the additional off-
take that the administration has said would be available
through Prudhoe Bay.
12:01:07 PM
REPRESENTATIVE KELLY asked for a timetable and expressed
surprise that Point Thomson would not be available for 15 to
20 years.
MS. FOERSTER noted that Point Thomson is an oil field and
the operator would have to prove to the AOGCC that waste
would not occur if they went into a gas blowdown.
RECESSED: 12:02:48 PM
RECONVENED: 1:32:00 PM
SENATOR STEDMAN pointed out that it is difficult to assess
the situation without more knowledge of the volumes.
MS. FOERSTER noted that the off-take at Prudhoe Bay would be
2.7 Bcf/d. That volume includes approximate 0.7 Bcf/d for
export for use in other fields, which would leave 2.0 Bcf/d
for sales. The impact of gas sales on Prudhoe Bay recovery
is confidential, but trends show that the later the gas is
sold, the less it should take. The more the operator has
done in the meantime to mitigate for losses, the small the
oil losses would be.
SENATOR STEDMAN observed that the state has been waiting 30
years for the gas line, but that it would have been
detrimental in terms of maximizing revenue to have built it
then.
MS. FOERSTER agreed.
SENATOR STEDMAN pointed out the legislature's support of the
administration's request to move the gas pipeline forward,
especially regarding funding. He questioned if the state
should be putting forth the question to the AOGCC regarding
off-take amounts.
1:36:34 PM
MS. FOERSTER noted that there are different opinions
regarding the standing of the state. The question has to be
raised before the AOGCC makes a determination. The problem
with the state initiating the process is that there would
not be onus on the operators to provide confidential data to
support the request. Without sufficient data entered into
the public record to support a decision, AOGCC cannot make
one.
MS. THOMPSON added that useful information about timing and
off-take could also be gathered related to the proposal to
the Denali pipeline.
1:38:11 PM
REPRESENTATIVE SAMUELS asked for clarification regarding a
cycling project.
MS. FOERSTER responded that it was not yet determined if
cycling would work. She noted that wells need to be further
apart to sweep the condensate out of the greater portion of
the reservoir.
REPRESENTATIVE SAMUELS asked if Exxon's proposal did that.
MS. FOERSTER answered that their proposal intends to do that
in part.
REPRESENTATIVE SAMUELS asked if the administration thought
it was a good idea.
MS. THOMPSON answered that the question raises issues she is
not allowed to embellish upon.
1:40:55 PM
REPRESENTATIVE DOOGAN thought that the earlier testimony
indicated that the solution to the lack of data available
for Point Thompson was to produce condensate and that
interjection of the gas would reveal more about the gas rim.
MS. FOERSTER explained that some of the questions regarding
reservoir properties could be answered by drilling new wells
and obtaining new data. There is debate regarding the API
gravity and condensate yield. The economics would be decided
by drilling into heavy oil and attempting production.
REPRESENTATIVE DOOGAN summarized that delineation wells are
needed.
MS. FOERSTER pointed out that delineation wells often become
development wells. It would not make sense to only drill for
delineation.
1:44:17 PM
REPRESENTATIVE DOOGAN spoke to oil, gas, and gas liquids
relating to Point Thomson and asked for more information
about condensates.
DR. CHOPRA explained that condensates are light oil in the
gas stage that drop off with the pressure. The oil is in the
oil rim and has no gas in it. Its gravity is lower.
REPRESENTATIVE DOOGAN summarized that there is gas with two
types of oil.
1:45:37 PM
SENATOR THOMAS asked for clarification regarding what needs
to be done to delineate Point Thomson and if the entire
North Slope is involved. He asked for additional
clarification on the number of wells drilled, their value,
and the time frame.
MS. THOMPSON explained that "sourdough" wells (wells drilled
by other than the operator) were not in the unit. It is not
the state's role as landowner to come up with a delineation
plan. Generally, more work is needed to learn about the
reservoir. She acknowledged reserves in other areas outside
of Prudhoe Bay.
1:50:20 PM
MR. MOOTHART described the need to narrow the range of
potential volumes.
MS. FOERSTER responded to the question regarding other North
Slope gas resources. The two known significant resources are
the Prudhoe Bay gas cap and the gas section of Point
Thomson. The rest are in the potential reservoir. The state
is dealing with the only two proven sizable gas reserves in
Point Thomson and Prudhoe Bay.
SENATOR THOMAS clarified that Alpine Field is not a large
gas resource. He asked for elaboration on the operator's
role.
MS. FOERSTER explained that the operator can interject water
into the gas cap. A pilot project has tested the gas cap
interjection, which seems to be working. Carbon dioxide
could be interjected into the oil rim. Smaller pools of
trapped oil are being gathered through lateral drilling.
1:55:44 PM
REPRESENTATIVE ROSES asked if modeling done at Point Thomson
has been done at Prudhoe Bay.
MS. HOULE explained that there has not been a modeling
similar to Prudhoe Bay. However, the department plans
additional modeling, using outside resources as well.
REPRESENTATIVE ROSES referred to the validity of the
information and suggested that the Prudhoe Bay data would be
more accurate.
MS. HOULE agreed that there would be a surplus of data.
REPRESENTATIVE ROSES described how estimations on gas volume
have changed. He stressed that members are dependent on
speculation until further data is gathered. He stated
concerns as the net present value changes according to the
assumptions. He pointed out that TransCanada is the only
company that does not need to know the return before
investment.
2:01:07 PM
MS. THOMPSON emphasized that the Prudhoe Bay study was
planned. She discussed Point Thomson seismic data. The
department has confidence in the structural picture and
reservoir continuity.
REPRESENTATIVE ROSES questioned the need for the study if
they were that confident and asked how much the Point
Thomson study cost.
MR. MOOTHART estimated that half a million dollars had been
spent on studies to date.
2:03:07 PM
SENATOR STEDMAN observed that it costs money to make money.
He suggested that the state would better off developing
Point Thomson under the previous plans, in light of PPT, gas
prices and progressivity.
2:05:25 PM
MS. THOMPSON could not determine whether the state would
have been better off with production 20 years ago. She
pointed out that costs have increased along with prices.
Analysis indicates that the project is economic even without
Point Thomson gas. The off-take question must be determined.
SENATOR STEDMAN summarized that the economics look promising
at this time.
2:07:54 PM
DR. CHOPRA, in response to a question by Representative
Buch, explained that carbon dioxide is effective at
recovering oil. When interjected in the oil rim through
horizontal wells, 50-60 percent of the carbon dioxide is
trapped in the reservoir. The gas that might otherwise have
been released into the atmosphere is sequestered and the oil
is recovered. He emphasized that carbon dioxide molecular
weight is higher than dry or liquid gas.
REPRESENTATIVE BUCH noted discrepancies in the estimates of
Bcf's available in Prudhoe Bay.
DR. CHOPRA noted that Prudhoe Bay recycling is an
optimization exercise to see how much oil is recovered. The
goal is to maximize recovery.
2:11:18 PM
REPRESENTATIVE BUCH questioned the adequacy of a proposal
that includes only Prudhoe Bay.
MS. FOERSTER observed that all the gas produced in Prudhoe
Bay is reinjected. She clarified that gas coming up with the
oil wells has increased over time. That will continue until
there is a gas line. Currently, two Bcf/d is the only gas
demonstrated to the AOGCC as an acceptable off-take.
REPRESENTATIVE BUCH noted that there has not been new
information in the last 40 years and questioned if anything
had changed in that time regarding Point Thomson.
DR. CHOPRA acknowledged that there have been changes.
Extensive seismic surveying was done in 1989 which was tied
to the well data. The continuity of gas is excellent. Things
have evolved.
2:15:00 PM
REPRESENTATIVE BUCH concluded that current technology allows
for efficient production of oil or gas anywhere on the North
Slope.
MS. FOERSTER agreed, with the caveat that the cost of
economics is not included. The technology exists for
production.
DR. CHOPRA agreed that the technology has existed for the
last 25 to 30 years to produce the condensate at Point
Thomson. Other issues are the availability of technology,
implementation and understanding of the technology.
2:17:32 PM
SENATOR WIELECHOWSKI queried the value of condensate.
DR. CHOPRA noted that the value is slightly higher than a
barrel of oil.
SENATOR WIELECHOWSKI asked if some of the northern and
eastern tracts have higher royalty rates.
MS. THOMPSON explained that royalty rates are set at the
time the lease sale and then they are sometimes re-
negotiated later. In the unit referred to, there is a
combination of both.
SENATOR WIELECHOWSKI questioned how much gas is being used
on the North Slope for energy consumption.
MS. FOERSTER responded that the consumption is just under .5
Bcf/d in Prudhoe Bay.
SENATOR WIELECHOWSKI asked if the state received a
production tax on that.
MS. FOERSTER responded that field use is not considered for
royalty.
2:19:36 PM
SENATOR WIELECHOWSKI queried if that was included in the
total off-take.
MS. FOERSTER stated that the allowable off-take in Prudhoe
Bay is 2.7 Bcf/d, of which 0.5 Bcf/d is used for fuel. Other
off-take is used for fuel for other fields, which makes that
total 0.7 Bcf/d. This leaves 2 Bcf/d available for sale.
SENATOR WIELECHOWSKI questioned the need for operators to
get permission to put their gas into the line.
MS. THOMPSON remarked on the complexity of the operating
agreements involved. She noted that there are different
provisions dependent on the volume and timing of gas. She
offered to do further research.
REPRESENTATIVE KELLY questioned if there was a statistical
confidence level at the lower end of the range.
DR. CHOPRA stated that there were two numbers for the oil
rim. Confidence in the lower number was high. The higher
number is based on analysis of the data.
2:24:51 PM
REPRESENTATIVE KELLY wondered how things got resolved in
cases of disagreement.
MS. FOERSTER responds that the Attorney General's office
would have more information about that. She described two
ways a disagreement could be resolved. The operator could
seek redress through the courts. It could also be dealt with
through the legislative process.
REPRESENTATIVE KELLY asked for more information. He stated
positive feelings and wondered why the producers and
TransCanada should be less confident about the off-take
numbers.
MS. FOERSTER replied that she is optimistic that explorers
will find abundant gas and that the gas line would be
filled.
REPRESENTATIVE KELLY asked if she was speaking of new gas.
MS. FOERSTER responded in the affirmative.
2:29:54 PM
REPRESENTATIVE GARA questioned if responsible law changes
were needed. He was concerned about lost opportunities if
various circumstances changed.
MS. FOERSTER responded that her office has sought a legal
opinion regarding the question of considering economic waste
in decision making. She hoped get this opinion in time to
enact legislation in the next session.
REPRESENTATIVE GARA further asked if at some time in the
future more Bcf/d could be authorized.
MS. FOERSTER responded that studies indicate that by the
time the pipelines are ready, the allowable limits will be
accessible and stated that there is no need to worry. She
encouraged prudent accelerated production at Prudhoe Bay.
REPRESENTATIVE GARA wondered if the law was not changed
whether the state would have the ability to order faster
drilling to get the oil out in time.
2:36:46
MS. FOERSTER did not think the operator could be forced to
spend money that they did not want to spend.
REPRESENTATIVE HAWKER asked if the known reserves would keep
this line full or does this include unknown, yet to be
discovered reserves.
MS. THOMPSON replied that they attempt to clearly
distinguish between known and potential reserves. There are
very few proven gas reserves, but there are significant
other known reserves. She stated confidence that there will
be enormous incentive for exploration when there is a gas
line.
2:41:19 PM
REPRESENTATIVE HAWKER observed that "other gas sources" are
not inventoried but they are there.
MS. HOULE described potential reserves.
REPRESENTATIVE HAWKER commented that he did not have
confidence that there are tangible, adequate sources of gas.
MS. THOMPSON pointed that Black and Veatch was the
consultant who did the economic modeling of the necessity
for the Point Thomson gas.
2:43:25 PM
REPRESENATIVE CHENAULT summarized that a 4.5 Bcf/d line is
the current proposal. If the line was built and running
today, there would be a known excess. He thought there was
around 2 Bcf/d of gas to fill a 4.5 Bcf/d line. He
questioned where the gas is and how much was needed.
MS. FOERSTER replied that if there were a line today and
someone were to ask for 5 to 6 Bcf/d from Prudhoe Bay, the
state's answer would be no. There are approximately two
billion barrels of oil left to be produced today that could
not be wasted via statute.
MS. THOMPSON clarified that the proposed line is not a 4.5
Bcf/d line. The administration asked for several different
options, as allowed by AGIA. The TransCanada proposal had
some flexibility. It is also not helpful to discuss a line
that is ready "today." She advised that Black and Veatch
would talk the next day about proven reserves and other
available gas on the North Slope. The state hired them to
look at the question of whether gas would be available and
the effect of different sizes of pipeline.
REPRESENATIVE CHENAULT thought it was relevant and important
to discuss the 4.5 Bcf/d line. He emphasized that in order
to get financing, shippers would need to know the extent of
the reserves.
2:51:27 PM RECESS
2:54:49 PM RECONVENE
CRAIG HAYMES, ALASKA PRODUCTION MANAGER, EXXON MOBIL,
commented that the 27 leaseholders were surprised and
disappointed with Commissioner Irwin's decision to reject
the POD submitted February 19, 2008. The plan would bring
Point Thomson into production by 2014 and ensure gas is
available for a gas pipeline.
MR. HAYMES pointed out that the project is already underway.
Alaskan contractors are in place. Over 50 million dollars
has been committed in the past months. In spite of concern,
the project will continue to move forward. He noted that the
plan is supported by the AOGCC and even DNR.
MR. HAYMES described the POD as an unconditional commitment
to production and to further delineate the oil and gas and
learn more about condensate, which does not exist in the
reservoir but only in the gas after it is removed from the
ground.
3:00:27 PM
MR. HAYMES referred to the Point Thomson handout (Copy on
File). Slide 2 shows that Point Thomson is on the North
Slope, 60 miles east of Prudhoe Bay and the TransAlaska
Pipeline in a remote and environmentally sensitive area
adjacent to ANWR. The reservoir is about 80,000 acres and
12,000 feet beneath the surface. It is a high pressured
reservoir and is costly to develop.
MR. HAYMES turned to Slide 3, depicting the 19 wells drilled
at Point Thomson. Exxon Mobil is the operator for 14 of the
wells. Over 3,600 feet of core have been collected from the
wells and have completed 20 well tests. Data from eight 3-D
seismic programs have been collected. The permafrost
thickness is 2,000 feet. Seismic uses sound waves to learn
more about the reservoir; permafrost mitigates that effect
and adds to the complexity of interpreting seismic readings.
3:03:58 PM
MR. HAYMES asserted that Exxon Mobil has fulfilled its
commitments. He defined the POD as a plan of work activity
to develop hydrocarbons. It consists of studies, activities,
engineering for drilling wells that are approved up-front by
DNR. As the lease-holders move forward with the work plans,
things change. Further discussions result in a revised POD.
There have been 21 PODs approved by the DNR from 1978
through 2005.
3:05:57 PM
MR. HAYMES listed the reasons the most recent POD is unique.
He talked about Slide 5, which graphs historical oil and gas
prices. He noted that the crude price prior to 2002 was less
than $20 per barrel. Six years later it is at $130 per
barrel. Up until 2002, the gas price was $4 Mcf. Only
recently have prices increased. The technology needed at
Point Thomson did not exist even ten years ago. This will be
the largest, high-pressure gas cycling project in the world
when operational. The project's estimated cost is $1.3
billion for the initial phase.
3:09:54 PM
MR. HAYMES turned to Slide 7, which depicts what Point
Thomson will look like by 2014. Production facilities will
be capable of producing a minimum of 10,000 barrels per day
of condensate by cycling 200 Mcf/d of gas through a
production well and an injection well. The export liquids
pipeline will be built to handle 70,000 barrels per day.
There will be an airstrip, camp and warehouse facilities. He
described measures to minimize environmental impact. He did
not anticipate permitting issues.
MR. HAYMES described guarantees to production rate. The
facilities have been designed to be expanded in any
direction needed.
3:12:17 PM
MR. HAYMES pointed to Slide 9, with a picture of the 27A
rig, which is being upgraded to handle the pressure at Point
Thomson. He described the 50 mile ice road (depicted on
Slide 11) that will be built by an Alaskan company this
winter to get equipment to the site. There will be an ice
runway build adjacent to the road. The ice road will cost
tens of millions of dollars to build, and it disappears in
summer.
3:15:08 PM
MR. HAYMES discussed permitting activities. Materials will
be barged from Prudhoe Bay to Point Thomson next summer by
an Alaskan company. Slide 14 is a photograph of the present
site. He pointed out there would be around three hundred
jobs created for just this initial phase drilling the first
well.
3:17:43 PM
MR. HAYMES showed Slides 16 and 17, showing the building and
use of ice roads, which are up to 13 feet thick and protect
the tundra from heavy equipment moving to site.
MR. HAYMES turned to Slide 19 and discussed the subject of
cycling gas and producing condensate. Cycling gas needs two
wells: a production well and an injection well. The wells
are four miles apart to test whether they work. The
reservoir temperature is 230 degrees Fahrenheit and the
pressure is 10,200 pounds per square inch. "Wet gas" is
produced in the right hand well, meaning the condensate is
contained in the gaseous vapor. After the pressure and
temperature are reduced, some of the gas turns into
condensate, which is stripped off and sent down the new oil
pipeline to market. The remaining dry gas will be re-
pressured and reinjected through the other well back into
the reservoir. This hopefully will sweep the wet gas from
the right to the left. This conserves the resource for
future development phases.
3:20:10 PM
MR. HAYMES listed DNR's concerns: timely development,
reservoir delineation, and a firm commitment. He asserted
that the POD addresses all three, and expounded on details
as depicted in Slides 20 through 24. He addressed timely
development using a detailed timeline on Slide 21. He
described activities that are already underway. The drilling
is a multi-year drilling activity. There is only a 90 to 120
day window to drill, which allows for drilling one well per
year.
MR. HAYMES turned to DNR's second area of concern, reservoir
delineation. Slide 23 depicts planned wells to access
different kinds of oil in the reservoir. To provide
perspective, a Prudhoe Bay well costs $6-8 million; a Point
Thomson well will cost between $60-100 million and will take
up to five times longer to build, due to the pressure and
depth. He described further wells and incentives for Exxon
Mobil to succeed.
3:27:22 PM
MR. HAYMES addressed DNR concerns about commitment. He
described proceedings such as a court order and changes in
voting processes that indicate Exxon Mobil's commitment to
the project.
MR. HAYMES covered five risks at Point Thomson, illustrated
on Slide 25. He addressed the first and second risks, health
and safety environment, and reservoir management. The third
area is production technology. Separation facilities will be
needed that are rated at 10,000 pounds per square inch. This
is one of the highest separator pressures in the world and
requires wall thickness of six inch steel. He emphasized
that it is critical to execute this project well. He
described the "A team" that would work on it.
3:32:41 PM
MR. HAYMES addressed the fourth risk, operability and
reliability. Until the wells are in place, it is difficult
to tell if the reservoir quality is homogenous throughout
the reservoir. There is a risk that once the gas is cycled,
the gas will not flow as hoped. He discussed the graph on
Slide 28, "Cycling at High Injection Pressure," which
depicts the result of a study of high-pressure projects.
3:35:56 PM
MR. HAYMES spoke about the high pressure well-head depicted
on Slide 29. The well is about three times the height of
well-heads at Prudhoe Bay. The reservoir is not only
abnormally high-pressured, but it straddles the coast line.
Wells have to be drilled from the land to get to the
reservoir under the ocean. They also need to be clustered in
discreet areas to minimize environmental impact. These will
be some of the longest reach wells in the world and they
will require some of the heaviest drilling mud in the world.
He described engineering challenges. This is what drives the
cost of the wells up to 100 million dollars.
3:39:37 PM
MR. HAYMES summarized the proposed POD for Point Thomson
depicted on Slide 31:
· Provides for production
· Further delineates reservoirs
· Provides information about reservoirs
· Conservation
· Minimizes environmental impacts
· Expandability
MR. HAYMES talked about the importance of Point Thomson gas
to a gas pipeline. Point Thomson represents 25 percent of
the known resource (Slides 32-33). This will be the largest
private infrastructure project in the history of North
America, well in excess of $30 billion, plus hundreds of
billions of dollars in firm transportation commitments.
Those commitments are critical for securing project
financing. A lower through-put, less availability of gas, or
fewer fields, will cause more doubt, which can not be
afforded with the gasline.
3:42:03 PM
MR. HAYMES pointed out that more fields will translate to
better prices for the consumer. He discussed yet-to-find
gas. He emphasized the importance of the project moving
forward.
3:44:15 PM
MR. HAYMES noted the importance of low tariffs, which the
governor encouraged. Without Point Thomson gas, the tariff
will increase by one dollar. There will be a 20 percent
increase in tariffs if the pipeline size is reduced from 4.5
Bcf/d to 3.5 Bcf/d, according to consultants. The net
present value is $15 billion in today's value. The increase
in tariffs would discourage exploration.
3:45:48 PM
MR. HAYMES observed that Point Thomson gas is critical, but
the timing is unknown. A dollar increase in the tariff will
result in $1.3 billion dollars a year. This is discouraging
to explorers.
3:47:28 PM
MR. HAYMES spoke about the DNR summary of PetroTel's report
(Slide 34). There is still a significant amount of technical
work and analysis needed, which is essential to understand
Point Thomson resource potential. He emphasized Exxon
Mobil's experience and expertise.
3:49:55 PM
MR. HAYMES observed that PetroTel's report depends on the
drilling of horizontal wells, which he did not think was
realistic. He maintained that a horizontal well would have
to be traversed for two miles without breaking through the
top gap or bottom water. The well would be compromised if
water entered the well. Exxon Mobil's technical work shows
that over 90 percent of all the resources at Point Thomson
will be developable through a gas sales development.
Significant production data is still needed. He emphasized
the need for flexibility and stated that they would share
information with DNR. The department does not have the last
two years of technical work available to Exxon. He stated
that the company does not want litigation.
3:53:39 PM
MR. HAYMES concluded that the 27 lease holders were
disappointed with the DNR decision. He asserted that there
is not a faster way to bring Point Thomson into production.
He reiterated Exxon Mobil commitment to the project.
3:55:09 PM
SENATOR THERRIAULT asked for clarification on regulations
and questioned the need for a retroactive clause.
MR. HAYMES acknowledged that a retroactive date was
included, and explained that the intent was to share
information that had been collected. The date is not firm.
SENATOR THERRIAULT discussed mechanisms for returning the
leases described by another company, and wondered why Exxon
Mobil did not have similar consequences and if they would be
willing to have such consequences.
MR. HAYMES explained that there are different levels of
assurances. Exxon Mobil had talked about lease
relinquishment and other remedies such as fines. They wanted
feedback on what the state was looking for. The court order
was an attempt to reach out and engage in a process towards
agreement.
4:00:26 PM
REPRESENTATIVE GARA stated that he wanted the lease back.
Exxon Mobil has conceded to 16 work commitment violations
since 1983. He referred to differences in amounts of money
spent.
MR. HAYMES believed that work commitments have been met.
Entwined in the plans of development were references to
expansion agreements, which are like contracts with the
state. The agreement was that the leases could be included
if a well is drilled. Because the leases were adjacent to
the existing unit, it made sense for the current
leaseholders in the unit to look at those leases and
determine the best way to develop potential resources in
those leases. They decided that in some of those cases it
was not prudent to drill. Agreement was obtained with DNR
that those wells should not be drilled and then those leases
were released back to the state, in some cases with
compensation. He disagreed that there was a commitment to
drill a well.
MR. HAYMES addressed the second question regarding the $800
million. Most of the money was spent early on the unit; in
today's dollars that would be $5 billion dollars to get the
level of information available to the current lease holders.
New lease holders would need to spend an equivalent amount.
4:04:42 PM
REPRESENTATIVE GARA questioned the timeframe Exxon Mobil
proposed to get to 10,000 barrels a day.
MR. HAYMES noted that 90 percent of the resource would be
recovered through gas sales development, based on the
technical work done. They are in the process of sharing
information to the AOGCC. There is a lot of incentive to
drill and produce as much oil and gas as possible. In six
years, a lot will be learned. The gas pipeline is at least
ten years away. Within six weeks of production, they will
know if there is a small tank in Point Thomson, or not.
4:07:52 PM
REPRESENTATIVE GARA felt that there was an overstatement on
the ability to advance the gas pipeline without Point
Thomson.
MR. HAYMES argued that 45 to 50 Tcf/d is needed. Prudhoe Bay
is around 25, without off-take rates.
4:08:58 PM
SENATOR WIELECHOWSKI referred to Slide 33 and questioned
when gas would be put into the pipeline according to the
analysis. He estimated they would not have gas for 43 years.
MR. HAYMES clarified that the state's Black and Veatch model
was used, which assumes gas production in 10 years. That
model looks only at gas, and does not take into account the
value of the condensate or oil. Condensate is not the
ultimate development plan for Point Thomson. There is a lot
of incentive for rapid expansion.
4:11:05 PM
SENATOR WIELECHOWSKI observed that in 1986, Exxon projected
a gas pipeline with eight producing wells by 1992. He
questioned why it was not completed.
MR. HAYMES explained that early exploration focused on oil.
When they drilled at Point Thomson then, they found a lot of
gas and not much oil. They recognized condensate could be
gotten from the gas. At that time Exxon focused on cycling
and believed that it was economic. However, the complexity
of the geology and the fact that the high-pressure
technology did not exist presented a problem. More work was
needed. Cycling has been looked at three times, but each
resulted in problems.
4:13:46 PM
SENATOR WIELECHOWSKI asked at what point in time Exxon would
feel the lease should be returned to the state.
MR. HAYMES emphasized that value remains and they have a
unique and firm POD, which provides greater confidence.
There is improved technology.
4:15:16 PM
REPRESENTATIVE KERTTULA asked about the status of the
Endicott Causeway and its relation to the proposed ice road.
MR. HAYMES stated that the plan was to connect the ice road
with the Causeway.
4:16:08 PM
REPRESENTATIVE DOOGAN asked the definition of "retrograde"
in connection with the reservoir.
MR. HAYMES explained that "retrograde condensate" means that
when you get to a certain pressure, condensate will drop out
of the reservoir. Point Thomson wells do not have a liquid
drop out issue. The quality of the well in the immediate
vicinity of the well neutralizes the effect.
4:18:49 PM
REPRESENTATIVE DOOGAN referenced Slide 34 and asked for
explanation of the phrase: "Our technical work shows that
over 90 percent of developable hydrocarbons (gas,
condensate, and oil) can be produced today through a gas
sales development." He thought gas was measured differently
than condensate and oil. He wanted to know what was being
measured by the "90 percent."
MR. HAYMES answered that there are two kinds of resources at
Point Thomson: gas and oil. Condensate does not exist in the
reservoir. If there was a move to gas sales, 90 percent of
that gas, and the possible recoverable condensate, and the
oil will be produced.
REPRESENTATIVE DOOGAN summarized that Exxon does not agree
with the AOGCC's assessment of Point Thomson as an oil field
first.
MR. HAYMES responded that Exxon Mobil agrees with AOGCC's
representation of Point Thomson in accordance with
regulations, which stipulate that if the liquid yield is
over 50 barrels per million cubic foot, the reservoir is
deemed an oil field. The reality is that the predominate,
recoverable economic resource at Point Thomson is gas and
along with it, condensate. Most of the condensate will be
produced with gas sales. Cycling will accelerate what is
available.
REPRESENTATIVE DOOGAN thought that he had heard from AOGCC
that the development scenario was getting the condensate and
the oil and then producing the gas. He asked if Exxon Mobil
was saying there would be simultaneous production of gas,
condensate and oil.
MR. HAYMES replied that the next best step for Point Thomson
would be to attempt to get as much condensate out of the
reservoir while waiting for the gas pipeline. The best time
to delineate and produce oil is when the pressure is
available. He agreed that more oil and condensate would be
developed (up to 90 percent) with gas sales development. He
maintained that there are still many challenges. Expansion
in multiple directions would be available.
4:24:08 PM
JOHN ZAGER, GENERAL MANAGER, CHEVRON-ALASKA, provided
members with a PowerPoint presentation (Copy on File). He
explained that Chevron has interest in the North Slope and
is a 25 percent working interest owner at Point Thomson. The
majority of their interest is in Point Thomson. At a
minimum, the recent DNR decision would delay the 2008-2009
drilling season.
MR. ZAGER introduced Slide 3, a visual map of Chevron assets
on the North Slope.
4:28:30 PM
MR. ZAGER reviewed items that have been brought forward as
fact or fiction:
1. Point Thomson is not needed for a gas pipeline.
2. The lessees are warehousing Point Thomson.
3. DNR rejected the plan of development on its merits.
4. The lessees are not doing any work on Point Thomson.
5. Point Thomson is "wildly economic."
MR. ZAGER turned to Slide 5, "Point Thomson is not needed
for a gas pipeline." He maintained that:
· There are insufficient proven reserves available to
back a commercially viable 4.5 Bcf/d gas pipeline
without Point Thomson.
· Will anyone commit FT (ship-or-pay) for the 'yet to
find' (YTF) resources? Without Point Thomson, this is
a significantly bigger number.
· A Prudhoe Bay-only pipeline delivers less value to
the state and producers through higher tariff rates
and the loss of oil resulting from blowing down
Prudhoe Bay.
4:31:51 PM
MR. ZAGER addressed Slide 6, "The lessees are warehousing
Pout Thomson":
· At no time has there ever been a way to get the gas
to market; it is disingenuous to say it has been
warehoused.
· Until the recent ramp up in prices, the condensate
resource was clearly uneconomic; it remains
challenged.
· The oil resource is problematic due to its depth,
range in quality, and potential range of recoverable
volumes. It is currently viewed as economically
challenged. The proposed POD is designed to resolve
these uncertainties.
4:33:07 PM
MR. ZAGER discussed the third point, "The DNR rejected the
plan of development on its merits" (Slide 7):
· The prior plan and amended plan were rejected because
they did not "commit to put the unit into production."
The current plan commits to put the unit into
production as well as delineate all reservoirs.
· In its April 2008 decision, the DNR stated that the
current plan is "a technically reasonable first step
for developing these lands."
· But instead of considering the plan on its merits, the
Commissioner of DNR has:
o Taken the unprecedented step of decertifying wells
for the purpose of terminating a unit through
administrative action.
o Has ruled that the proposed PODs do not coincide
with his preferred development, while refusing to
specifically lay out his preferred development.
o Moved to expropriate the asset despite
acknowledging the plan's merits by claiming a lack
of "trust" of the lessees. (For over 27 years, the
Commissioner of DNR and the lessees agreed the
PODs set out the appropriate course of action for
the development of Point Thomson as evidenced by
the ongoing DNR approval up to August of 2005.)
o Refused to meet with the lessees to outline his
expectations.
MR. ZAGER disavowed point 4, "The owners are not doing any
work on Point Thomson" (Slide 8):
· Over the last 30 years, the owners have spent over
$800 million on the exploration and development of
Point Thomson.
· Despite the state's move to expropriate the leases,
the lessees have dedicated significant resources to
continue technical work:
o Reservoir simulation and flow stream modeling;
o Planning for development;
o Initiating engineering design for facilities;
o Making financial commitments for drilling oil
rig and long-lead items; and
o Progressing permitting applications.
MR. ZAGER addressed the claim that "Point Thomson is wildly
economic" (Slide 9):
· The complexity and unique nature of this reservoir
makes it a very challenging and expensive field to
develop.
· While the upstream has been described as delivering a
greater than 50 percent rate of return (ROR), specific
to PTU it appears that the Black and Veatch base case
depicts the value at a modest 13 percent ROR:
o Aggressive assumptions on gas price and cost
trends; and
o Base case of an initial gas blowdown (i.e., no gas
cycling).
(4:37:45 PM)
4:39:24 PM
VINCE LEMIEUX, MANAGER, ALASKA NEW VENTURES, CHEVRON, noted
that they had looked at PetroTel's report and that DNR
Commissioner had said that the new information changed
everything. The work done is strictly theoretical. It does
not take into consideration the full and practical aspects
of economics and concrete considerations about the wells.
Most of all, the report overstates the oil.
MR. LEMIEUX argued that the incremental recoverable liquids
at Point Thomson are substantially less than 500 million
barrels. He estimated that there could be less oil produced
on the North Slope as a result of this. The entire system
has to be taken into consideration.
MR. LEMIEUX emphasized the complexity of the field. He spoke
to the continuity of the field, which relates to how the
rocks are put together. That cannot be assessed through
seismic. This is absolutely critical to figuring how the
field will be developed. Chevron operates some of the
highest pressure cycling projects today, but those projects
are difficult and risky, both from economic and safety
standpoints.
4:44:07 PM
MR. LEMIEUX thought that PetroTel's report did a very good
job regarding the immediate work that needs to be done at
Point Thomson is consistent with the proposed plan of
development. It has to be a phased approach; the initial
information will inform the next step. He asserted that the
proposed POD is the right first step.
4:46:40 PM
MR. LEMIEUX argued that the project needs to get started,
and that the current lease holders are in the best position
to get results. There is no magic bullet; the work needs to
be done to get the information, and the time frame proposed
is necessary. He did not think that cycling was likely to
work, given the stratigraphy of the field. If it doesn't
work, then the move can be made to gas sales. If it does
work, there will be a productive oil field. A delay could
result in a smaller pipeline. He reiterated the importance
of moving forward with the proposed plan of development.
4:48:54 PM
MR. ZAGER referred to Slide 13, which delineates Chevron's
position regarding AGIA and any pipeline. Chevron is not a
participant at this time, although they would like to own
shipping capacity. If Point Thomson is resolved favorably
for Chevron, they would be a significant player in a
pipeline.
MR. ZAGER asserted that Chevron will commit firm
transportation for known gas reserves to a pipeline that
they are confident provides reasonable upstream economics
and terms. There would have to be a tariff that allows Point
Thomson to have reasonable economics. By "confident,"
Chevron means they will look at the open season materials to
determine economics.
MR. ZAGER spoke to key variables and assessed the
controllability of each. Point Thomson resolution is
controllable, but future gas prices are not. Construction
costs are partially controllable; some components such as
the price of steel and labor will escalate at an unknown
rate, while design and management of the project are
controllable. He raised the question of the actual costs of
open season.
4:55:28 PM
MR. ZAGER observed that cost risk allocation is
controllable, although Chevron would like to see it spread
out so that there is real incentive for the developer to
meet the number in the open season proposal. State taxes are
controllable and will be a real issue. Many of the elements
are aligned with the state to assure the highest price
available. He concluded that both Chevron and the state want
the projects done in the most economic way. A certain amount
of capital invested will be picked up by the state in the
form of credit. Producers are looking for a greater
partnership with the state to find the most prudent
investment.
4:58:38 PM
MR. ZAGER concluded with Slide 14:
· The Point Thomson Unit is critical to any major gas
pipeline.
· Point Thomson development should begin as soon as
possible; the POD is the right plan.
· DNR should have approved the proposed PTU plan on its
merits.
· The current lessees can and will (if allowed) develop
Point Thomson better and faster than anyone else.
· Chevron is being forced to litigate to protect its
rights.
· Chevron wants to sell its North Slope oil and gas as
efficiently and rapidly as possible.
5:02:11 PM
MR. ZAGER noted that Chevron is in protracted litigation and
Point Thomson is outside of the proposed gas pipeline.
Everyone agrees that the substance of the proposed POD is
right and Chevron stands ready to perform the proposed plan.
Owners remain ready to drill in 2008-2009. He proposed that
an independent, objective review of the pipeline analysis
should be undertaken. More outside resources are needed. In
an open and honest government, the parties to the Point
Thomson litigation would sit down and talk through their
differences.
5:05:06 PM
REPRESENTATIVE FAIRCLOUGH asked for more information
regarding acceptance by DNR regarding submitted permits. She
observed that FERC typically can look at two proposals and
will discern which project should go forward and let the
finance markets decide. She questioned the disadvantages for
the producer of voting "yes" on AGIA.
MR. ZAGER stated that Chevron did not want to comment on
AGIA or if the $500 million would be well spent. The issue
remains whether or not AGIA would result in production.
REPRESENTATIVE FAIRCLOUGH summarized that many thought there
is no reason to vote no. She wanted to know how producers
stood in order to inform her constituents.
5:07:53 PM
SENATOR WAGONER asked how much of the $1.2 billion estimated
for the development would be taken up by the state through
ACES credits.
MR. ZAGER did not have a figure and observed that it would
different for each company. He acknowledged that there will
be credits on capital, but he did not know which would be
covered and which would not.
SENATOR WAGONER requested those figures.
5:09:28 PM
SENATOR THERRIAULT asked for comments regarding the change
in the Point Thomson Unit voting rights to a simple
majority.
MR. LEMIEUX observed that the voting change was most
dramatic for Chevron. Prior to the change, both Exxon and BP
could make a decision which would carry Chevron. A simple
majority meant that any two of the three could decide that a
project needed to be carried forward. The motivation is
significantly changed.
MR. ZAGER added that one way to look at it was that no one
would carry the risk of carrying someone else. On the other
hand, if two say yes, the other would not take the risk for
staying behind.
SENATOR THERRIAULT pointed out that the possibility that a
company would go non-consent in a circumstance like this is
low.
MR. LEMIEUX agreed that the penalties for non-consent on a
big project are very stiff and a company would most likely
not take that risk.
5:12:31 PM
SENATOR THERRIAULT raised the issue of meaningful penalties.
Exxon did not have meaningful penalties under the POD. Under
the unit agreement, if the state were to impose that, there
is a shift of burden of proof from the producers to the
state. He asked if Chevron had a position.
MR. LEMIEUX stressed Chevron wants to sell its oil and gas.
He thought that there was a lack of honest dialogue
regarding the proposed plan. Chevron would consider a broad
range of consequences, including lease relinquishment.
5:15:28 PM
REPRESENTATIVE DOOGAN asked for clarification regarding
"practically recoverable reserves."
MR. LEMIEUX answered that practical is closely linked to
economic reserves.
5:17:04 PM
SENATOR HUGGINS noted that $700 thousand was spent for
PetrolTel's contract. HB 3001 and SB 3001 were held in
committee.
ADJOURNMENT
The meeting was adjourned at 5:18:16 PM.
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