Legislature(2009 - 2010)SENATE FINANCE 532
02/16/2010 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| Oil and Gas Production Forecast | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
9:01 a.m.
9:01:13 AM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee meeting to order at
9:13 AM.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Charlie Huggins, Vice-Chair
Senator Johnny Ellis
Senator Dennis Egan
Senator Donny Olson
Senator Joe Thomas
MEMBERS ABSENT
None
ALSO PRESENT
Jennifer Duval, Petroleum Economist, Tax Division, Department of Revenue;
Marcia Davis, Deputy Commissioner, Department of Revenue; Frank Mollie,
Petroleum Engineer, Department of Revenue.
PRESENT VIA TELECONFERENCE
Kevin Banks, Director, Division of Oil and Gas, Department of Natural
Resources.
SUMMARY
^Oil and Gas Production Forecast
JENNIFER DUVAL, PETROLEUM ECONOMIST, TAX DIVISION, DEPARTMENT OF REVENUE,
explained that her job was to coordinate the publication of the revenue
sources book. Her specific responsibility is the production forecast. She
introduced the PowerPoint presentation "Oil and Gas Production
Forecasting" (Copy on File). She introduced an outline for the
Presentation.
o Decline Curve Analysis
9:06:27 AM
Ms. Duval explained that the department must forecast for revenue and
budgetary purposes. She referred to Slide 3, which categorizes reserves
versus resources. Reserves are categorized as proved, probable, and
possible. She pointed out that the Department of Revenue (DOR) uses
similar categorization with terminologies such as currently producing,
under development and under evaluation.
Ms. Duval pointed out that the department did consider the forecast to be
conservative. Undiscovered resources, prospects, leads are not considered
in the forecast.
Ms. Duval addressed Slide 4: "Three Categories of Forecasted Production"
1. Currently Producing- Includes base production and enhanced recovery
production from investment in rate enhancing activities
(perforations, stimulations, well workovers, gas and water injection
support).
2. Currently under Development- New projects that are currently funded
or awaiting project sanction in near future.
3. Currently under Evaluation- Includes technically viable projects in
the "pencil sharpening" stage where engineering, cost, risk and
reward are being actively evaluated. Unfunded but are considered to
have a high chance of being brought to fruition.
Ms. Duval detailed Slide 6: "Factors That Affect Production Forecasting"
1. Geology
a. Rock type and formation characteristics
b. Depth, thickness, pressure
c. Oil and gas characteristics (oil gravity, viscosity, water
content, etc.)
2. Development Plan
a. Well density and development rate
b. Well bore size and completion technique
c. Artificial lift and enhanced oil recovery
d. Facilities and surface operations
3. Commercial
a. Project economics
b. Oil price and market conditions
c. Government Policy: access, regulation, taxation
4. Production Profile
a. History, stage of depletion
b. Use production profile to extrapolate trends
5. Timing
9:09:19 AM
permitting activity affects the forecast. Ms. Duval responded that the
type of permit makes the difference. An exploratory permit will not be
included in the forecast. Developmental permits are categorized in the
"under development" plan. She noted that the department meets with the
operators each year to review plans. A change in the permitting activity
such as adjusting the plan of development will be reflected in the
forecast.
9:12:16 AM
Ms. Duval pointed out that while the government has control over some of
the factors, there is no control over geology, oil price, and market
conditions. Areas of government policy can impact the development plan and
can be controlled.
Ms. Duval described Slide 7: "Typical Production Profile." She explained
that production increases at first, reaches a peak then declines. The
decline rate typically levels off in later years. The field's geology,
operator's development plan, and commercial factors, all influence the
shape of the curve.
Ms. Duval compared the North Slope to the graphs on Slide 7. She detailed
the graph on Slide 8 "Production Profile of a Prudhoe Well." She noted
that the graph fits the production profile of a single well shown on Slide
7. The sum of all the wells that have produced for Prudhoe and Kuparuk are
summarized on Slide 9. She noted points in time where the rate has changed
slightly.
9:15:25 AM
Co-Chair Stedman asked for a definition of the Y axis. Ms. Duval stated
that the Y axis indicates millions of barrels per day.
Ms. Duval continued with Slide 10: "Alaska North Slope History." The
addition of new fields has mitigated this decline. In 2009, Prudhoe Bay
and Kuparuk alone represented only 57 percent of total North Slope
production. The addition of new fields has been important in mitigating
the decline. Infill drilling, facility capacity expansion, and enhanced
oil recovery projects have also helped stem decline.
Co-Chair Stedman asked about the history chart and whether the data was
typical of oil basins around the world. Ms. Duval responded in the
affirmative. He asked if the expectation for the industry to return to $2
million barrels per day was realistic. Ms. Duval stated that she would not
expect so. Co-Chair Stedman commented on the normal decay of an oil field.
Ms. Duval concurred. She noted that the sections of the graph indicating
Alpine and North Star had a large impact on reducing the production
decline. Because Prudhoe Bay and Kuparuk account for so much production, a
very large field would be needed to return to historic rates.
9:18:15 AM
fit into the curve on the graphs. He asked if it indicated a longer period
of development. Ms. Duval noted that if Alpine was graphed alone, one
could see that it fits the profile well. She supposed that the aggregation
of the chart as an area curve combined with layering the fields in the
graph increases the ambiguity. She offered to provide individual field
profiles for Senator Thomas and the committee. Senator Thomas stated that
he wanted to understand the lifetime of the fields.
Co-Chair Stedman requested a focus on the last five and the next five
years in production.
9:21:04 AM
Ms. Duval referred to Slide 11: "North Slope Production Decline"
*Excluding 2007, 4.0% decline on average.
average, through FY 2030.
Ms. Duval detailed Slide 12: "ANS Production History and Forecast." She
explained that through FY2050, the expectation is to recover an additional
5.3 billion barrels of oil. The forecast does not include projections from
the outer continental shelf, heavy oil productions from UGNU as well as
most of the heavy oil production from West Sak and Shrader Bluff or the
Umiat field. The forecast does include some production from the National
Petroleum Reserve Alaska (NPRA).
9:24:08 AM
Co-Chair Stedman asked for production profiles for heavy oil in Alaska and
its potential impact. One tax credit was to incentivize heavy oil. Ms.
Duval stated that she did not have specific slides prepared on profiles
for heavy oil. She offered to pull profiles for West Sak and Shrader
bluff. She noted that pools in the Prudhoe Bay unit are considered heavy
oil. She offered to provide the profiles for heavy oil for Co-Chair
Stedman. The resource contains approximately 20 and 35 billion barrels of
oil. The recovery for the pools is much lower than some of the lighter oil
pools that are currently producing. Co-Chair Stedman concurred and asked
that the information be added to the presentation on tax credits.
Co-Chair Hoffman stated that the forecast indicates that the state could
potentially see something in 2012. He asked how many are currently under
development. Ms. Duval stated that offshore is referring to Oooguruk and
Nikaitchuq. Co-Chair Hoffman asked if they would be under category three
as currently under evaluation. Ms. Duval stated that the reference is not
included under the three layers.
Co-Chair Stedman asked about the difference between federal and state
waters. Ms. Duval responded that federal waters are beyond the six mile
limit. Between zero and three miles is considered state waters and between
three and six miles is federal. Co-Chair Stedman explained that from three
to two hundred miles is federal and the state is unable to share resources
with the industry.
MARCIA DAVIS, DEPUTY COMMISSIONER, DEPARTMENT OF REVENUE, added that the
state authority to tax production stops at the three mile line. The state
authority to receive royalty generally expands to three miles for state
leased land. An arrangement for some royalty sharing exists in the zone
between three and six mile where the state receives a share of federal
royalty.
Co-Chair Hoffman explained the reason for addressing off shore is that
although the three mile and six mile does not directly impact us, offshore
oil through the pipeline would lead to lower tariffs on the Trans Alaska
pipeline for the remainder of the oil travelling through the pipeline that
benefits Alaska. Ms. Duval agreed that although the state may not receive
tax revenue from offshore federal waters, Alaska can receive benefit
through the shipment of oil down the Trans Alaska pipeline. The impacts
would show up as an increased well head price because the tariff would be
reduced. An additional benefit would be seen in petroleum corporate income
tax.
9:30:17 AM
Senator Thomas asked about heavy oil. He asked if the confirmation of data
occurs with the industry as well. Ms. Duval remarked that the number
quoted is from a Department of Energy (DOE) study that was recently
released from the National Energy Technology Laboratories. The study was
originally released in 2007 with an addendum in October 2009. The resource
potential of the Alaska North Slope is reported upon, which includes
potential from other sources not included in the department's forecast.
Ms. Duval examined Slide 10: "Alaska North Slope History." She explained
that the slide depicts the forecast. She noted that the grey shaded area
indicates the production profile to look like in the decline rate. She
noted that the decline rate is approximately seven percent per year. The
expectation is for new projects for new fields and additional development
at currently producing fields as well.
Ms. Duval discussed Slide 14: "Timing is Important!"
DOR's FY 2010 forecasted total NS production:
Spring 1989- 104,000 bpd
Spring 1994- 583,000 bpd
Fall 2009- 659,000 bpd
*However, operators are not bound to what they provide to us. Budgets
can change; partners may not approve projects.
9:34:00 AM
Senator Huggins agreed that timing is important. He expressed concern
about the developmental certifications. He asked if Ms. Duval wanted the
new production to come online in good timing based on economic perspective
and credentials. He asked what three things might be done to incentivize
new development and new production. Ms. Duval responded that her role was
not to discuss policy issues, but she referred to Slide 6: "Factors that
Affect Production Forecasting." She noted that factors that the department
has control over are access, regulation, and taxation. Factors that would
help speed up developmental certifications would include increase of
access, reducing inefficiencies and regulations, and making permanent
process easier and providing for tax incentives.
Co-Chair Stedman stated that the intent of the upcoming meetings is to
address the concerns expressed. He agreed that Ms. Duval and other
scheduled presenters are not in the policy making business.
9:37:01 AM
FRANK MOLLIE, PETROLEUM ENGINEER, DEPARTMENT OF REVENUE, explained how the
forecast was generated. He noted that the Alaska Oil and Gas Conservation
Commission (AOGCC) maintain monthly production data for every well in the
state. The data is gathered from the state and used in a decline curve. A
decline curve plots production data on a linear graph; it appears as
depicted in Slide 17: "Data Plotted on a Linear Scale." The scale on the
left side of the graph is called a linear scale. Engineers plot on a log
scale. A log scale is depicted on Slide 19: "Decline Curve Extrapolates
Trend" where the left side of the graph begins at 100 Barrels of Oil Per
Day (BBLS/DAY) and moves up to 1000 BBLS/DAY and up to 10,000 BBLS/DAY. If
oil production is plotted on a log scale regions appear fairly linear. The
decline curve simply includes a line drawn through the linear section of
data, which is then used to project the oil and gas production. He stated
the decline curve is done for every producing well in Alaska. This data
can be moved to a linear scale as depicted on Slide 20: "Trend (linear
scale)."
Co-Chair Stedman explained that one issue is transitioning between a tax
and royalties system to a production sharing arrangement, which includes
capital credit incentives to increase production. He opined that there is
any increase in production. Mr. Mollie responded that the graph depicts a
single well production, which will not include the entire field.
Mr. Mollie described Slide 22: "KRU Well Decline Curve at the End of
2002." The slide depicts the Kuparuk River Well. He admitted that the
decline method is not perfect. The Kuparuk well if viewed in 2002 would
9:41:22 AM
Senator Egan asked which rate would necessitate that the well is shut
down. Mr. Mollie responded that he did not know the answer. He stated that
other producing wells might feed into the same facility. Senator Egan
asked for a specific figure that indicates that shut down is prudent. Mr.
Mollie stated no.
Mr. Mollie described Slide 24: "To Generate a Field Forecast:"
1. Upload production history form AOGCC into database
2. Apply a decline curve to every well with recent production history
data
3. Sum all of the production history and forecasts
Mr. Mollie moved on to Slide 25: "Prudhoe Bay Currently Producing Wells."
He explained that the graph depicts the Prudhoe Bay decline curve
generated from summing the individual well of the field. The red line
represents the projection of the currently producing wells. For all of the
equipment and facilities, this is the production we expect for the
currently producing equipment production. The decline rate on this
particular graph is six percent.
Co-Chair Stedman asked if the analysis shows any change in the data for
the last three years. He asked if the forecast predicted any fiscal regime
change. Mr. Mollie answered that the last three years of production from
Prudhoe Bay does show a change in slope. He noted the change in slope
shown in the last three years, which flattens out. He did not know if the
flattening slope was a result of a tax regime, but it is a result of the
gas cap water injection that the company proceeded with during the time.
Co-Chair Stedman asked for a brief explanation of gas cap water injection.
Mr. Mollie responded that an oil reservoir contains an oil layer and a gas
layer above it. In order to maintain pressure in the reservoir to maintain
the production profile, water is injected into the gas cap which adds
pressure to the reservoir that maintains the production rates for the oil
well.
Co-Chair Stedman asked about the down spike in the fifth or sixth year.
Mr. Mollie believed that it was a pipeline issue for Prudhoe Bay. Ms.
Duval added that in 2006 the drop indicates the shutting of the well.
9:45:19 AM
Mr. Mollie moved on to Slide 27: "Prudhoe Bay Currently Producing + Under
Development." He explained that the red line represents the currently
producing wells and the green line represents the currently producing
wells plus any production forecasted from the projects under development.
The added investment of the projects will significantly increase the
production rates and maintain them longer.
Development." The slide shows the decline rate at seven percent. The
projection is the same. With decline curves, a straight line indicates a
constant percentage decline.
Co-Chair Stedman requested that Mr. Mollie return to the committee with
charts beginning in the year 2000 through 2015 including Prudhoe, Kuparuk,
and Alpine. Mr. Mollie agreed to produce the chart for the committee.
Co-Chair Stedman asked if Prudhoe, Kuparuk, and Alpine wells could be
separated. Mr. Mollie pointed out that he had a chart that contains the
entire North Slope.
Mr. Mollie referred to the map on Slide 29: "North Slope and Beaufort Sea
Alaska Overview of Oil and Gas Activity January 2005" He reminded that
areas such as the Arctic National Wildlife Refuge (ANWR) were not
forecasted. Co-Chair Stedman asked if the map might be revised to include
dollars where the revenue generation is located. Ms. Duval offered to
review the data to determine the best way to graphically display the
request. Co-Chair Stedman stated his point is to display the revenue to
the treasury. Ms. Duval responded Prudhoe Bay, Kuparuk, Alpine, Northstar.
9:49:28 AM
Mr. Mollie continued with Slide 30: "Total North Slope." He pointed out
the log scale and the area between 1995-2000 where the decline rate was
six percent. The area following 2004 until the current time is again six
percent. From 2000 to 2004, the decline rate stopped. He explained that
during that time the state had seven fields begin production. The fields
included Polaris, Alpine, Aurora, Meltwater, Northstar, and Orion. New
production can mitigate the decline somewhat.
Mr. Mollie moved on to Slide 31: "Total North Slope Currently Producing +
Under Development." He explained that the red line indicates the currently
producing and the green line indicates the currently producing plus the
under development projects. The decline rates are historically six
percent. Future prediction is a four percent decline rate. Co-Chair
Stedman asked if Point Thompson is included. Mr. Mollie answered that
Point Thompson is in the under evaluation category as depicted by the blue
line in Slide 32: "Total North Slope." The projects under evaluation are
not viewed with the same confidence in the forecast as the under
development and currently producing categories. If all investment were to
stop tomorrow, production rates would include the currently producing data
only. If the price of oil plummeted investment would be lost. With the
current plans and development, the green line is predicted for the North
Slope Production. The bump seen in the blue line around the year 2023 is
the effect of Point Thompson. In Point Thompson, there is the assumption
that a gas sales pipeline exists to reach the level of production
predicted. If the gas sales line is not created, the blue line would
follow the green line closely without the increase in production.
2014. Ms. Duval added that the department assumes a ten year development
lead time for Point Thompson and a gasline. Co-Chair Stedman asked if the
prediction was the historic norm. Ms. Duval answered yes.
9:53:24 AM
Mr. Mollie described the graph on Slide 33: "Fall 2009 Forecast: Log
Scale." The graph shows Prudhoe Bay with the vast majority of production.
Unless another large field comparable to Prudhoe Bay is found, similar
production rates will never be seen again.
Ms. Duval described Slide 34: "Conclusion"
geology, development plans, commerciality, production profiles,
decline curves and timing.
producers, AOGCC and DNR
currently producing, under development, and under evaluation.
Co-Chair Stedman reminded that the department will return with additional
information on a more focused area of 2000 through 2020.
Senator Thomas realized that finding another field like Prudhoe Bay was
highly unlikely. The existence of the heavy oil at Prudhoe Bay is more
than double the amount extracted. He believed that innovation is a result
of desire and need. He opined that continuing the development at Prudhoe
Bay was desirable as there is not a need for infrastructure. He mentioned
new heavy oil discoveries in the state. Ms. Duval agreed that the state is
producing some heavy oil in the Orion, Polaris, and Schrader Bluff pools.
She pointed out that the Ugnu deposit is much shallower and includes
stores of heavy oil.
9:57:48 AM AT EASE
10:03:02 AM RECONVENED
KEVIN BANKS, DIRECTOR, DIVISION OF OIL AND GAS, DEPARTMENT OF NATURAL
RESOURCES (via teleconference), explained that his presentation "Oil and
Gas Activity in Alaska 2009-2010" (Copy on File) includes the exploration
aspect of oil production. He pointed out the map "North Slope Oil and Gas
Activity 2009-2010." He noted that the bright blue line shown on Slide 2
represents the three mile limit from the coast. Everything south of the
line is state submerged waters. North of the blue line is the outer
continental shelf is managed by the federal government. Production from
those lands is not subject to state taxes, however, between the three and
six mile limit, the state shares in the federal royalties at the rate of
27 percent.
drilled in 2009, and red indicate wells that are permitted or planned for
2009 and 2010. These wells are exploration activities, some of which are
subject to tax credits as exploration wells.
10:07:00 AM
Mr. Banks addressed Brooks Range petroleum. The unit was formed recently.
Brooks Range is a new entrant on the North Slope. UltraStar has begun
drilling a second well east of the unit. He noted that Liberty will begin
drilling an explorer well to begin testing their new ultra extended reach
drilling equipment. He anticipated drilling to begin on a satellite
drilling unit from the state lands.
Co-Chair Stedman asked if the normal tax activity is received under
Liberty. Mr. Banks answered that there is no tax coming in for Liberty.
The oil and gas liquids from Liberty will be processed at Endecott and
production will be allocated to the Liberty production.
Senator Olson asked if a tax was collected by the North Slope borough. Mr.
Banks answered no. The property tax to the North Slope Borough will be
collected because of the Endecott facilities and the addition of the well
heads and the equipment placed on the satellite drilling island. There are
physical improvements that occur within the borough that are subject to
property tax, but the well's bottom hole location is outside of the
borough.
10:11:20 AM
Co-Chair Stedman noted that employment issues will be discussed later in
the presentation and he requested that Liberty be factored out. Mr. Banks
pointed out that he did not know how to estimate the difference for
Liberty, but he knew that the majority of employment will occur in the
drilling of the well. Once fluids begin to reach the surface, the local
employees manage both state and federal oil and gas. Employment is
enhanced with the increased activity at the Endecott facility.
Mr. Banks pointed out the eastern part of the map and Badami, where
production is anticipated to begin in September 2010. He addressed the
Point Thompson text box. He pointed out that Exxon struck a total depth of
PT 15 and would enter the PT 16 well. When DOR refers to Point Thompson
production and timing, the administration is not a monolith. He explained
that DOR relies on public information with respect to Point Thompson. Gas
sales from Point Thompson rely on the public pronouncement from Exxon both
in discussions with the public and hearings with the Department of Natural
Resources (DNR).
10:15:46 AM
Mr. Banks continued that Chevron drilled five wells into the White Hills
Program. Chevron originally permitted 16 wells. Discussion occurred about
unitizing the area. Co-Chair Stedman requested a definition of unitizing.
the resource and to assure that ownership of the resources is correctly
allocated to our lessees. Leases are offered for 50-100 acres each. In
order to develop a region, DNR combines leases into a single unit to be
managed as a single lease and everyone's rights are taken care of and
production is efficient.
Mr. Banks noted that the Department of Transportation and Public
Facilities (DOT) considered routes from the Hall Road to the Gubik and
Umiat area. The division has contributed some information to DOT to
indicate the most attractive potential along the routes. He continued with
the west end of the North Slope. The National Petroleum Reserve-Alaska
(NPRA) includes three new wells from Anadarko, Petro Canada, and BG. The
NPRA was established in 1910 as part of the naval oil reserves. The
intention was to find areas under federal management that would serve the
nation's needs for oil and gas. The Department of Interior took NPRA over
in the 1920s. Now NPRA is federal land managed by the Bureau of Land
Management (BLM) and has adopted strong multiuse provisions involved in
its management. The area has been offered for considerable drilling in the
1950s. The gas fields near Barrow were discovered in NPRA. The BLM leased
quadrants in the 1990s.
10:24:55 AM
Co-Chair Stedman asked about the tax difference between Liberty and NPRA.
Mr. Banks replied that the taxes on NPRA are subject to state production
taxes and the state enjoys a 50 percent share of the royalties collected
by the federal government. Co-Chair Stedman asked if it was more
profitable for the state's treasury to develop NPRA. Mr. Banks concurred.
He added that more oil may exist offshore than has been discovered in the
NPRA.
Senator Olson asked about ownership of subsurface rights for the Arctic
Slope Regional Corporation (ASRC) land. Mr. Banks replied that ASRC owns
the subsurface rights.
Mr. Banks continued with the area known as the Greater Moose's Tooth Unit
conducted by ConocoPhillips. He expected a scout well to be reentered by
2012 as an obligation by the Bear Tooth Unit. ConocoPhillips had drilled
the Grandview and Pioneer wells. Some of the wells are subject to state
tax credits even though they occur on federal land. He noted the challenge
in developing these areas and testing the exploration wells. Some of the
most expensive wells drilled are in the NPRA.
10:29:03 AM
Mr. Banks pointed out the Alpine West satellite known as (CD-5) which is
on hold for activity. The reason development was ahead of the exploration
activities is because it is already part of the Colville River Unit, which
is owned by the ASRC. The surface is run by the federal government and a
private owner will benefit. Through the unitization and unit agreements
that apply at Colville River, the development of the Colville River unit
for ASRC than the state. The department's concern about the Corp of
Engineer's decision is an indication that the federal government believed
that leasing the land would assure development although they failed to
allow oil companies to access their leases.
Co-Chair Stedman requested data about wells drilled in 2004 and 2005 along
with the "feet per year drill." Mr. Banks pointed out that he had provided
similar information to the House Finance Subcommittee. He prepared charts
for the last five or ten years. He pointed out that the oil companies are
reluctant to discuss plans for fear that the state will mistake a plan for
a commitment.
10:33:40 AM
Mr. Banks continued with the northern area of the map and the region
around the Kuparuk River. Brooks Range Petroleum Corporation plans to
drill North Tarn on a lease shared with the Italian Oil Company (ENI).
Pioneer has moved forward with development at the Oooguruk project, which
was challenged initially, but is now successful. He concluded with the
Nikaitchuq unit with expectation that first oil will be developed by the
end of 2010.
Senator Egan asked about multi phased metering. Mr. Banks explained that
multi phased metering occurs where water gas and oil are mixed together
and flowing through a device that distinguishes the amount of the various
components. Normally oil production is metered for the purposes of
royalties or allocations for the oil or gas that is subject to royalties
or sold. The accuracy of the meters is high. At the Oooguruk well, fluids
are mixed together with a machine that meters all three fluids and parse
out the different components. The precision of a multi phase meter is less
than the traditional lease acquisition custody transfer meters seen on the
North Slope. With appropriate checking and testing against other kinds of
devices of the state, the companies, AOGCC are gaining additional
confidence and are willing to use multiphase metering in situations where
the fluids are blended for processing in already built facilities.
10:37:57 AM
Mr. Banks added that continued year-round development drilling occurs at
the Prudhoe, Kuparuk, Colville and Milne Point units. He hoped that DOR
could provide a forecast. He commended Ms. Duval on her presentation about
the potential for heavy oil on the North Slope. He agreed that heavy oil
is a challenged resource, but once the wells are drilled, production tends
to flatten out.
Mr. Banks clarified that Alaska heavy oil is not like California heavy
oil, it is better quality and is assigned the nickname "heavy oil" because
it is heavier than the oil produced today. He stated that heavy oil is the
next phase of development in the existing oil fields on the North Slope.
10:41:30 AM
Mr. Banks moved on to the map "Cook Inlet Oil and Gas Activity 2009-2010"
(Copy on File). He pointed out that the activities in the Cook Inlet
include the geothermal projects submitted as part of the exploration plans
for the coming season. The potential exists to develop a large power plant
which would represent a quarter of the electric demand.
Mr. Banks discussed the Rampart Energy Company well at Nunivak 1 in the
Nanana Basin which involves an exploration license. The well was drilled
last summer and was one of the most "wildcat" wells drilled. Activities in
the Cook Inlet that Mr. Banks found most interesting were the Sunrise and
Shadura prospects near Swanson River. The Marathon has begun drilling the
Sunrise well. Shadura is another potential gas well to the west of the
Swanson River drilled by an independent company called Nordik Energy
Partners. Pioneer is working on the Hansen 1A-L1 well in 2010. The testing
for the well began approximately two weeks ago.
Mr. Banks mentioned the North Fork project sponsored by Armstrong which is
the company that initiated the prospect of Oooguruk and Nikaitchuq and
flipped it to ENI. Armstrong is a capable explorer who can put together a
prospect and find appropriate investors to development. The consequence of
the development is a pipeline that will flow from Anchor Point to
Ninilchik. Armstrong will construct a pipeline from North Fork to Anchor
Point to connect. Infrastructure is reaching an area of the Kenai as yet
undeveloped. He anticipated potential growth in gas plays.
Mr. Banks addressed the Kitchen Lights Unit with Escapada who will bring a
jack up rig into the Cook Inlet to drill for an oil target in the Kitchen
Lights unit as a preliminary exploration program. The department is
waiting to see if Escapada will be affected by critical habitat issues.
Co-Chair Stedman requested further information on the drilling done in
Prudhoe Bay, Kuparuk, and Alpine.
10:41:30 AM AT EASE
10:50:08 AM RECONVENED
ADJOURNMENT The meeting was adjourned at 10:50 AM.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2010 02 16 DNR AK O&G Activity 2009-10 SFC.pdf |
SFIN 2/16/2010 9:00:00 AM |
Oil and Gas Production Tax Review |
| 2010 02 16 DNR OG Activity CI.pdf |
SFIN 2/16/2010 9:00:00 AM |
Oil and Gas Production Tax Review |
| 2010 02 16 DNR OG Activity NS.pdf |
SFIN 2/16/2010 9:00:00 AM |
Oil and Gas Production Tax Review |
| Agenda 021610 am.docx |
SFIN 2/16/2010 9:00:00 AM |
|
| 201610 DOR TAPS Tariff History & Going Forward.pdf |
SFIN 2/16/2010 9:00:00 AM |
|
| 2010 02 16 DOR Prod Forecast Flwup SFC.pdf |
SFIN 2/16/2010 9:00:00 AM |
|
| 2010 02 16 DOR Production Forecast SFC v4.pdf |
SFIN 2/16/2010 9:00:00 AM |
Oil and Gas Production Tax Review |