Legislature(2015 - 2016)BARNES 124
02/23/2015 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Overview(s): Arctic National Wildlife Refuge by the Department of Natural Resources and the Department of Revenue | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE RESOURCES STANDING COMMITTEE
February 23, 2015
1:32 p.m.
MEMBERS PRESENT
Representative Benjamin Nageak, Co-Chair
Representative David Talerico, Co-Chair
Representative Bob Herron
Representative Craig Johnson
Representative Kurt Olson
Representative Paul Seaton
Representative Andy Josephson
Representative Geran Tarr
MEMBERS ABSENT
Representative Mike Hawker, Vice Chair
COMMITTEE CALENDAR
OVERVIEW(S): ARCTIC NATIONAL WILDLIFE REFUGE BY THE DEPARTMENT
OF NATURAL RESOURCES AND THE DEPARTMENT OF REVENUE
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
SUSAN MAGEE, Statewide ANILCA Program Coordinator
Office of Project Management & Permitting
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Provided an overview of the provisions of
ANILCA that are relevant to the recently released Arctic
National Wildlife Refuge Revised Management Plan.
PAUL DECKER, Acting Director, Petroleum Geologist
Division of Oil & Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Provided a PowerPoint overview of potential
oil and gas development in the Arctic National Wildlife Refuge.
KEN ALPER, Director
Tax Division
Department of Revenue (DOR)
Juneau, Alaska
POSITION STATEMENT: Provided a PowerPoint presentation about
revenue potential to the State of Alaska from oil and gas
development in the Arctic National Wildlife Refuge.
DAN STICKEL, Assistant Chief Economist
Tax Division
Department of Revenue (DOR)
Juneau, Alaska
POSITION STATEMENT: Answered questions regarding the revenue
potential from oil and gas development in the Arctic National
Wildlife Refuge.
ACTION NARRATIVE
1:32:48 PM
CO-CHAIR BENJAMIN NAGEAK called the House Resources Standing
Committee meeting to order at 1:32 p.m. Representatives Herron,
Tarr, Johnson, Josephson, Olson, Seaton, Talerico, and Nageak
were present at the call to order.
^OVERVIEW(S): Arctic National Wildlife Refuge by the Department
of Natural Resources and the Department of Revenue
OVERVIEW(S):
Arctic National Wildlife Refuge by the Department of Natural
Resources and the Department of Revenue
1:34:06 PM
CO-CHAIR NAGEAK announced that the only order of business is an
overview of potential oil and gas development in the Arctic
National Wildlife Refuge by the Department of Natural Resources
and the Department of Revenue.
1:35:20 PM
SUSAN MAGEE, Statewide ANILCA Program Coordinator, Office of
Project Management & Permitting, Department of Natural Resources
(DNR), said she represents a small group of state employees from
various departments who work diligently to review federal plans,
policies, and regulations to ensure the provisions of the Alaska
National Interest Lands Conservation Act (ANILCA) appropriately
recognize and protect state interests. She said she will be
providing an overview of the provisions of ANILCA that are
relevant to the recently released Arctic National Wildlife
Refuge Revised Management Plan, which is the vehicle for the
Wilderness and Wild and Scenic River recommendations that were
recently announced by the President of the United States.
MS. MAGEE related that ANILCA was passed by Congress in 1980
after extensive debates and a series of compromises. It
designated or expanded over 100 million acres of conservation
system units (CSUs) and other conservation designations across
the state. It more than doubled the National Wilderness
Preservation System (NWPS), it designated 26 Wild and Scenic
Rivers, it identified 12 additional study rivers, and it gave
the U.S. Department of Interior a three-year time limit to
follow up with recommendations on those. It also allowed for a
one-time follow up Wilderness review of areas not already
designated for potential recommendation. This applied to the
National Park Service (NPS) and the U.S. Fish and Wildlife
Service (USFWS) and had a seven-year time limit. Also, ANILCA
prohibited further studies for the single purpose of
establishing new conservation system units, commonly referred to
as the "no more clauses." Wilderness and Wild and Scenic Rivers
are both defined under ANICLA as conservation system units.
Because the conservation areas were of such unprecedented size,
and to accommodate the state's developing economy, limited
infrastructure and distinct rural lifestyles, ANILCA included a
number of unprecedented exceptions that are unique to Alaska.
1:37:59 PM
MS. MAGEE explained the Arctic National Wildlife Refuge (ANWR)
was initially established in 1960 through a public land order
(PLO) as the Arctic National Wildlife Range, and included the
Coastal Plain. Under ANILCA the range was expanded and re-
designated as the Arctic National Wildlife Refuge, and new
purposes were identified similar to the majority of other
refuges in Alaska. Additionally, ANILCA designated the Mollie
Beattie Wilderness, an area included in the original range; it
designated three Wild and Scenic Rivers; it directed the study
of the Porcupine River for potential recommendation as a Wild
and Scenic River; and it provided specific direction for the
Coastal Plain in Section 1002, which is why the plain is often
referred to as the 1002 Area. Under this section Congress
directed the Department of Interior to conduct an inventory and
assessment of the fish and wildlife resources of the Coastal
Plain and an analysis of the impacts of oil and gas exploration,
development, and production. It also authorized oil and gas
exploration activities. The end result of all of that work was
a legislative environmental impact statement (EIS) and the
Section 1002(h) report, issued in 1987. It recommended Congress
authorize full leasing of the entire area for oil and gas
production. To date, however, Congress has not acted on that
recommendation.
MS. MAGEE said the Arctic National Wildlife Refuge Comprehensive
Conservation Plan (CCP) is the vehicle for the Wilderness and
Wild and Scenic River recommendations that were recently
announced. The final CCP recommends Congress designate as
Wilderness nearly the entire refuge, including the 1002 Area,
which in total is approximately 19 million acres. The CCP also
recommends four new Wild and Scenic Rivers. One of those
rivers, the Hulahula, is in the 1002 Area. The Atigun River is
on the western border of the refuge near the Dalton Highway and
the Trans-Alaska Pipeline System (TAPS). These recommendations
can be forwarded to Congress for action after the record of
decision (ROD) is signed for the final plan. There is a 30-day
hold period which ends 2/26/15. Then Congress can act to either
reject or designate these areas or it can take no action on the
recommendations. The no action leaves everyone in a limbo
status and USFWS policy will then be relied upon to protect the
recommended areas and rivers until Congress does act.
1:41:07 PM
MS. MAGEE pointed out a number of issues with the CCP. Even
though the recommendations do not change the prohibition in
ANILCA on oil and gas production in the refuge, and Congress
would need to act on the Wilderness and Wild and Scenic River
recommendations to put them into effect, pursuant to agency
policy the areas and rivers now have a special recommended
status that can affect a variety of uses and activities on lands
within and adjacent to the refuge. For example, that
recommended status sends a clear message to Congress making it
more difficult to authorize oil and gas development in the
Coastal Plain. Also within the refuge, permits for commercial
recreation guiding activities may be more limited or have permit
stipulations to protect wilderness character or values. Outside
the refuge the USFWS provides input through the 1969 National
Environmental Policy Act (NEPA) process on the impacts of
development projects occurring on adjacent lands to refuge
resources and values. For example, the Point Thomson oil and
gas development EIS addressed impacts to the Arctic National
Wildlife Refuge and mitigation was initially based on a
misconception that the 1002 Area was part of a congressionally
mandated Wilderness Study Area. [The state] corrected that and
the mitigation was modified, but [the state] is concerned that
the current recommended status could affect the Alaska Liquefied
Natural Gas (LNG) Project (AK LNG), which will run adjacent to
the Arctic National Wildlife Refuge.
MS. MAGEE said the state's position on the Wilderness and Wild
and Scenic River reviews is that the USFWS is following agency
policy, not ANILA. The "no more clause" says no more studies
for the single purpose of establishing a new CSU unless
authorized under ANILCA or another act of Congress. The reviews
authorized under ANILCA had time limits and Congress has not
provided any new directions. The U.S. Fish and Wildlife Service
says the studies do not violate the "no more clause" in ANILCA
if they are housed within a larger management plan because that
gives them more than one purpose. But, she argued, the reviews
themselves clearly state that their purpose is to consider
recommendations to establish new CSUs. The USFWS also says it
is complying with ANILCA's planning requirements in conducting
the study, but ANILCA only says the USFWS should identify and
describe the special values of the refuge, not study them for
potential recommendation.
MS. MAGEE pointed out that policy is not law, but policy is
supposed to be based on law and the U.S. Fish and Wildlife
Service's Alaska policy on conducting Wilderness reviews was
reversed in the beginning of the Arctic planning process,
without consultation with the state or Native interests and also
no public review even though its policy on directives indicates
there should have been. She noted that USFWS policy now says
Wilderness reviews will be conducted in all future CCP
revisions, so it will apply to the Yukon Flats, Yukon Delta,
Alaska Maritime, and Izembek refuges. The revised plans will
also include Wild and Scenic River reviews.
1:44:46 PM
MS. MAGEE stated another issue is that the CCP did not look at
oil and gas development alternatives because the USFWS said it
did not have authority to authorize oil and gas activities, even
though the same can be said for the Wilderness and Wild and
Scenic River reviews and the USFWS doesn't think ANILCA limits
the agency in that regard. Additionally, while the revised CCP
references the Section 1002(h) report, it does not acknowledge
the actual recommendations. The U.S. Fish and Wildlife Service
also indicates it intends to manage recommended areas and rivers
under the minimal management category. [The state] still feels
this is problematic because the Arctic National Wildlife Refuge
revised CCP provides a more restrictive overarching management
framework that promotes a wilderness-like experience regardless
of whether or not the Wilderness and Wild and Scenic River
recommendations are acted upon. Also, minimal management, which
is already the most restrictive category other than the
Wilderness and Wild and Scenic River categories is more
restrictive in the revised CCP. For example, public use cabins,
which are allowed by ANILCA in designated Wilderness for health
and safety purposes, will not be allowed or even given
consideration anywhere in the Arctic National Wildlife Refuge
under minimal management.
MS. MAGEE related another issue is that the Alaska Department of
Fish & Game (ADF&G) is concerned the more restrictive, hands off
management approach in the CCP, in combination with some other
regulatory wildlife related changes currently under
consideration by the USFWS, will impact ADF&G's ability to
effectively manage fish and wildlife resources in accordance
with the state constitution and, by extension, the availability
of meaningful harvest opportunities, including for subsistence.
Lastly, future stepdown management plans are likely to impose
additional restrictions on uses and access in the Arctic
National Wildlife Refuge. The CCP calls for a visitor use and
management plan, a wilderness stewardship plan, to begin right
after the ROD is signed. The CCP also requires Wild and Scenic
River management plans for the three existing Wild and Scenic
Rivers and four more if Congress designates the recommended
rivers. It also calls for an ecological inventory and monitory
plan, as well as some other things.
1:48:07 PM
PAUL DECKER, Acting Director, Petroleum Geologist, Division of
Oil & Gas, Department of Natural Resources (DNR), began with
slide 2 of his PowerPoint overview of the Arctic National
Wildlife Refuge (ANWR) entitled, "ANWR 1002 Area." He pointed
out the refuge is just about the same size as the state of South
Carolina, about 19.8 million acres. Within the refuge, the
Coastal Plain, or 1002 Area, is about the same size as Delaware.
MR. DECKER noted the committee's request was for him to provide
before and after comparisons. He said slide 3 depicts refuge
management under the previous plan or, in essence, the no action
alternative. Under the previous plan the 1002 Area, outlined by
the box at the top of the map, was managed in minimum management
mode in contrast to the Wilderness area shown in green. The
southern and southwestern parts of the refuge were in minimal
management status rather than Wilderness status. The blue
indicates the Wild and Scenic Rivers that traverse the refuge.
MR. DECKER turned to slide 4 to show what the refuge will look
like if the new/current management plan is adopted. The Coastal
Plain becomes proposed Wilderness or minimal management with
Wilderness recommendation, as does the southern and southwestern
part of the refuge. So, the entire refuge will be managed as
defacto Wilderness until, and unless, Congress makes some other
decision. Also seen are the additional Wild and Scenic River
designations, one is the Hulahula River which flows through the
1002 Area. It is not only the 1002 Area that is of concern.
The southwestern part of the refuge is also very important to
geologists with the state and U.S. Geological Survey (USGS) for
gaining access to important outcrops that can be used for
studying, evaluating, and extrapolating information for beneath
the state lands that are located just to the north of that
southwest portion of the refuge. This area of state land is the
mountain front on the east side of the Haul Road. So, this is a
secondary consideration compared to the potential loss of access
to the oil and gas lands of the Coastal Plain.
1:51:25 PM
MR. DECKER drew attention to slide 5 to outline key moments in
the 1002 Area's history. He said this list is a subset of the
history provided by Ms. Magee that is pertinent to the oil and
gas activities and potential of the area. He pointed out that
Section 1002(a) of ANILCA did three things: directed the
Secretary of Interior to assess the area for fish and wildlife;
required an analysis of the impacts of oil and gas exploration,
development, and production; and authorized certain low-impact
oil and gas exploration activities. Between 1983 and 1985, low-
impact exploration activities were conducted, and nearly 1,200
line miles of two dimensional (2-D) seismic data was collected.
He said he has seen that data and it is absolutely imperative
for understanding anything about the sub-surface in the Coastal
Plain. However, it is challenging data to work with and it is
strongly believed that modern seismic techniques using three
dimensional (3-D) seismic would greatly enhance understanding of
the 1002 Area sub-surface. The 2-D seismic activity and the one
well drilled on Kaktovik Inupiat Corporation (KIC) lands by
Tenneco in 1984 and 1985 represent the sum total of the sub-
surface knowledge.
MR. DECKER addressed the USGS map of the 1002 Area on slide 6
depicting the discovered oil and gas accumulations around the
edges of the Arctic National Wildlife Refuge. He pointed out
that the football-shaped area is a schematic depiction of Point
Thomson which has oil, gas, and condensate. The green boxes
indicate wells that have discovered, including several in the
offshore and along the shoreline, as well as just south of Point
Thomson at Sourdough. The red boxes indicate gas accumulations,
Kavik and Kemick, both discovered in the late 1960s and located
a little bit farther into the foothills where the area tends to
be more gas prone. He called attention to the undeformed and
deformed areas of the 1002 Area, explaining that deformed is a
geologic term for rocks that have literally been deformed,
meaning the layers of rocks have been bent, broken, folded, and
faulted. It is associated with the tectonic compression of the
area, with tectonic forces squeezing Northern Alaska to create
the Brooks Range. An analogy would be to imagine a snowplow
advancing from south to north, the blade pushing the snow in
front of it. The undeformed area would represent the part of
the parking lot that the snowplow hasn't gotten to yet. The
deformed area would be the portion in front of the plow where
the snow is munged up and compartmentalized into little bits and
pieces instead of the nice original layers. This geological
complexity of building the Brooks Range also has temperature
implications in addition to the structural implications.
1:55:36 PM
REPRESENTATIVE SEATON inquired whether those are the same kind
of differential structure found between Kuparuk and Prudhoe Bay.
MR. DECKER replied it is a very different style of deformation
along the Barrow Arch between Prudhoe Bay and Kuparuk, which has
not at all felt the snowplow, so to speak. The undeformed area
would be more akin to Prudhoe Bay with caveats. Prudhoe Bay,
Kuparuk, and most of the major fields have not felt the impact
of the snowplow. That is part of the reason why the undeformed
area is believed to be considerably more valuable in terms of
oil habitat - it is much more likely to have more oil in the
undeformed area than in the deformed area.
1:56:40 PM
MR. DECKER addressed slide 7 entitled, "USGS 1998 Resource
Assessment Undiscovered, Technically Recoverable Resource." He
noted the map on the right side of the slide highlights in
yellow the undeformed area of the 1002 Area. The numbers in the
blue box on the left are estimates of undiscovered, technically
recoverable resource. It is not looking at reserves yet - just
undiscovered resource that is judged to be technically, not
necessarily commercially, recoverable. It is only talking about
the volumes of oil that could be recovered by the technology
available at this time; so, obviously, very speculative numbers.
The only way to arrive at a meaningful answer on that kind of a
question is to create a range of outcomes, a probability
distribution, and that is what is depicted by the three columns
of numbers in the blue box. The low-side estimate is the "F95"
column, meaning a 95 percent confidence that the actual volume
of undiscovered, technically recoverable oil would be larger
than that number. The "F05" column is the number at the upper
end of the scale, meaning a 5 percent confidence that there is
more resource than that. The "Mean" column is not necessarily
the center or the "P50," it is the average of the entire
probabilistic distribution. In this assessment the USGS looked
at the federal 1002 lands, the Native lands around Kaktovik, and
the state waters going out to three miles from the shoreline.
The average, or mean, estimate for the entire assessment is
about 10.4 billion barrels of recoverable oil. Within just the
federal lands, the mean estimate is about 7.7 billion barrels;
and, of that, the mean estimate for the undeformed part is about
6.4 billion barrels and about 1.2 billion barrels for the
deformed part. So, according to this prediction, the undeformed
area only represents about one-third of the 1002 Area, yet it
has about five times as much oil as the other two-thirds that is
deformed area. That makes the undeformed area about 10 times
more valuable on a barrel-per-acre basis, and key is that it's
adjacent to state lands, including Point Thomson and Sourdough.
1:59:28 PM
REPRESENTATIVE TARR asked whether the 1998 USGS resource
assessment is based on the 2-D technology of the 1980s and the
one well that was drilled.
MR. DECKER responded the one well very likely is not included in
that assessment because that well has been held confidential to
the parties involved; a couple of oil companies that are left
still have access to that data. Because the well was drilled on
Native lands it has been legitimately held confidential for all
these years.
2:00:11 PM
MR. DECKER defined some exploration terminology (slide 8), but
qualified the definitions are informal. A "play" in exploration
terms is a set of known or hypothetical accumulations of
hydrocarbons that are closely related to each other because of
some shared geologic characteristic. Typically the shared
characteristic is the reservoir rock unit, so the oil and gas is
predicted or known to occur within a certain age reservoir
formation. A "prospect" is one of the postulated hydrocarbon
accumulations that can be identified from geological and
geophysical information; it is a discreet potential accumulation
and typically hasn't yet been confirmed by drilling a discovery
well. This same word is also used to describe discoveries that
have not yet been commercially sanctioned, that still need some
delineation. An "accumulation" is oil or gas that is known to
be trapped in a viable reservoir rock with enough saturation of
the hydrocarbons that it can be recovered by drilling wells,
drawing down the pressure, and sucking it out. "Reserves" are
not the same as resources; rather, reserves are the class of
resources that have been discovered and are commercially
producible. Reserves does not apply to undrilled prospects or
undiscovered resources; therefore, a key point is that there are
no reserves in the Arctic National Wildlife Refuge at this time.
MR. DECKER noted the graphic on the left of slide 9 represents a
stratigraphic column from the 1998 USGS assessment of the Arctic
National Wildlife Refuge. It summarizes the rock layers: where
the source rocks are, where oil and gas may be present, and how
the different plays are broken out for the assessment. The
column represents the oldest and deepest rock layers at the
bottom and the youngest and shallowest rock layers at the top.
The ages of the rocks span hundreds of millions of years. The
greatest resource potential lies in some of the younger Cenozoic
rocks, which are the sand-bearing formations depicted in yellow
and specifically the Sagavanirktok Formation. He said the two
charts on the right side of slide 9 represent histograms of size
class, what the USGS calls field size classes. Each column in
the charts represents a size class that is double of the next
smaller size class to the left. The upper graph shows the
number of accumulations, with the deformed area depicted by
green bars and the undeformed area depicted in yellow bars.
Most of the predicted accumulations, outlined by the red box,
are going to be in the three size classes between 32 million
barrels and 256 million barrels, which are smaller fields than
Prudhoe Bay. Thirty-two million barrels would probably be
really pushing it to be economically recoverable, but 250
million barrels would very likely be commercially viable. The
lower graph shows the volume of undiscovered oil resources and
how it is predicted to fall out in the various size classes.
Most of the oil is predicted to occur in accumulations that are
between about 128 million and a billion barrels in size, as
outlined by the red box. The oil in those size classes would
very likely be economic to recover it accessible to oil and gas
leasing and development. He pointed out that the graphs
represent the average, or mean, case.
2:04:54 PM
REPRESENTATIVE SEATON requested Mr. Decker to further explain
the graphs on the right side of slide 9.
MR. DECKER explained the top right graph is the number of
accumulations - the number of discreet prospects envisioned by
the USGS in each size class. The tallest bar on the graph
represents the field size class of 64-128 million barrels and
the USGS expects there to be about 8 accumulations of that size
in the undeformed area and just under 1 accumulation in the
deformed area. Because it is a statistical way of doing this,
the numbers are not round.
2:06:12 PM
MR. DECKER resumed his presentation, turning to slide 10 to
discuss the major exploration plays in the assessment area. He
explained that when all of the oil assessed in the mean case is
allocated to the various plays, or suites in which it is
predicted to be present, it is almost ranked by age as well as
by size class. As was seen in the stratigraphy column, it's the
youngest suite of rocks that has the largest resource potential.
In particular are the Brookian Topset and Brookian Turbidite
plays. These are nearly age equivalent of each other, but the
Topset is sandstones, conglomerates, and reservoir rocks
deposited in shallow water, whereas the Turbidite is sandstones
and mudstones deposited in much, much deeper water. The
Brookian Topset play is the most prospective at 6.2 billion
barrels. Actual accumulations representative of the Topset play
include the Hammerhead discovery and the Kuvlum accumulation
offshore in the outer continental shelf (OCS). Representative
of the Turbidite play are places like Badami, the Flaxman
discovery at Point Thomson, Sourdough just south of Point
Thomson, Yukon Gold, and the Stinson accumulation. The other
plays listed on slide 10 are, for the most part, also-ran
contenders. Brookian Topsets, Brookian Turbidites, Brookian
Wedge, and the Thomson and Kemik Sandstones are likely to be
present in the undeformed area because they can all form
stratigraphic traps, so there is no sole reliance on structural
traps to actually find compartments to trap the oil.
MR. DECKER drew attention to the block diagram of the Brookian
sequence depositional model on slide 11. He said the mountains
in the diagram represent the Brooks Range, with the rivers
spilling out of the mountains carrying sediment. The sediment
deposited onshore and near shoreline - the fluvial and deltaic
systems - is the Topset play. The sediment carried across the
continental shelf and down the continental slope onto the basin
floor of the ocean - creating fans or aprons - represents the
Turbidites or deepwater plays.
2:09:30 PM
MR. DECKER displayed a well log [slide 12] for the Brookian
Topset play as manifested in the Hammerhead discovery located
not very far offshore in eastern Beaufort OCS waters. He
explained the non-marine, fluvial-deltaic, and shallow marine
sandstones and conglomerates are separated from each other by
intervening siltstones and mudstones that create seals that
contain the oil and gas. The hallmark is high reservoir quality
- great porosity, great permeability - but only a fraction of
the interval is actually pay zones. The red arrows show the gas
pays and the green shows oil pay. Both oil and gas occur in
this accumulation and occur in stacked, relatively thin zones
that are 10-50 feet thick. This is a very different style of
reservoir than the Prudhoe Bay reservoir where there may be 400
feet of continuous light oil and gas.
MR. DECKER turned to slide 13 to show two well logs for the
Brookian Turbidite play, one a Badami well and one from the
Flaxman discovery at Point Thomson. He said Badami has never
really performed as hoped due to compartmentalization and a
variety of other geologic complications. The Flaxman discovery,
however, looks like a much better reservoir, on the order of 100
million barrels, plus or minus. The relatively thin test
interval in the Flaxman well flowed at rates of 2.5 thousand
barrels of oil per day, as well as a couple of million cubic
feet of gas. With Point Thomson going to development, it is
anticipated that some of these Brookian discoveries in the unit,
and maybe nearby, could also come on line and it is hoped they
will perform better than Badami.
2:11:55 PM
MR. DECKER called attention to the map on slide 14 depicting
existing wells with red dots and the 2-D seismic data with red
lines that was used in the 1998-1999 USGS assessments. The KIC
1 well is the only well located within the 1002 Area, he said,
and it is still confidential. The other wells are located in
state waters, on state lands, and in the OCS and were drilled
over the last several decades. The geology of the Arctic
National Wildlife Refuge was worked out by interpolating
inwards. The 2-D seismic, acquired in 1983, 1984, and 1985, was
very challenging acquisition and very difficult geology to image
properly. The seismic spacing is on the order of three to eight
miles between lines and a lot can fall through a sieve that
coarse. So, about a year and a half ago the state proposed
acquiring its own three-dimensional (3-D) seismic surveys across
the entire Coastal Plain [slide 15]. This would not be cheap,
but the value would be new data - state-of-the-art technology
that could be acquired in prioritized areas, starting with the
undeformed area, then moving next to the Marsh Creek Anticline
Area, and then progressing east and then south across these five
areas over a period of about three years. It would be a very
ambitious program. While not all of the data may get done, it
could begin with the prioritized area. This proposal made it
all the way to a formal application to the Department of
Interior for a seismic permit to do the work.
2:14:12 PM
MR. DECKER moved to slide 16, explaining the rational for the
State of Alaska's proposal for 3-D seismic in the 1002 Area.
Section 1002(a) of ANILCA, he reiterated, set aside the 1002
Area specifically to assess the area for a variety of resource
values and assess whether it would be a good place to explore
for oil and gas in the national interest. [In the division's]
view, the data from the mid-1980s is wholly unsatisfactory for
making a high resolution final management decision especially
one that would make it all off-limits forever. [The division]
believes the newer technology would give a much better
resolution and a better understanding of the probability
distribution. The state took the point of view that the
authority to conduct exploration of this sort had never really
expired. Since it is winter-only seismic exploration, it is low
impact and would have very minimal permanent impacts. However,
the Department of Interior's response to the state's proposal
was that it has expired and would take an act of Congress to
open it back up.
MR. DECKER turned to slide 17, pointing out the aforementioned
is not the first time the State of Alaska has taken an interest
in trying to maintain the Arctic National Wildlife Refuge as an
area that could be opened to exploration. In 2003 the Division
of Oil & Gas put together a report entitled, "Oil and Gas in the
ANWR? It's Time to Find out!" Available on the division's web
site, this report is an in-depth explanation of how the USGS
conducted its analysis in its 1998-1999 assessment. The report
stressed the differential importance and value of the undeformed
area and also stressed the importance of modern 3-D seismic to
making a good assessment. Also stressed in the report is the
decrease in footprint in terms of winter-only ice pad drilling,
as well as today's smaller development footprint with gravel and
year around access. More wells than ever can be drilled from a
smaller pad with a larger sub-surface drainage area through
deviated and horizontal well technologies. The Alaska State
Legislature has also taken a number of actions since 1993,
including a number of endorsements and appropriations to promote
public education on the issue, proposing exploration and
leasing, and opposing Wilderness designation.
2:17:24 PM
REPRESENTATIVE HERRON noted the President of the United States
recently said the federal government will consult with State of
Alaska officials and indigenous people when there are any
decisions to make in an Arctic matter. He inquired what the
division's counterparts in the federal government say when asked
that question. He surmised the division's federal colleagues
choose to consult with the state when they choose to.
MR. DECKER replied the division has, for the most part, an
exceptional working relationship with its federal colleagues.
The division keeps it mostly at a professional level rather than
straying into questions of politics. However, he continued, the
division has called out its good friends and colleagues in the
USGS for instances where the division felt the communication
could have been better, one example being the 2010 USGS
reassessment of the National Petroleum Reserve in Alaska. The
USGS took it upon itself to update the previous resource
assessment in the petroleum reserve and the division felt that a
better outcome would have been yielded had the division been
consulted throughout the process. In this case, the division
sent a letter directly to the Secretary of Interior and the USGS
director. He said Representative Herron's point is well taken
that more communication is always beneficial.
REPRESENTATIVE HERRON surmised that the division's written and
verbal communications are still asking the question, "How come
you don't want to have a complete conversation?" He asked what
the federal response to that is.
MR. DECKER confessed that since the announcement came out about
the new CCP he has not reached out to his federal colleagues to
have this conversation; therefore it would be speculative of him
to try to predict how his professional colleagues would react to
that. The decisions being made, he added, are being made at a
much higher level than the geologists he is dealing with. The
geologists he is aware of all share the view that the 1998-1999
resource assessment is still the best estimate of the resource
potential in the area and it could be improved upon.
REPRESENTATIVE HERRON opined that many people in the Capitol and
around Alaska are frustrated. For example, an environmental
impact statement (EIS) for the [proposed] safety corridor
through the Izembek [National Wildlife Refuge] was done by
indigenous people, the State of Alaska, and the U.S. Fish and
Wildlife Service (USFWS). However, USFWS officials in Alaska
were taken by surprise when others higher up in the federal
government made the decision to say no. He expressed his fear
that this could happen to the state elsewhere, and maintained
that it has happened.
2:21:50 PM
MR. DECKER resumed his presentation, addressing slide 18. He
said [the division's] 2013 application to conduct seismic
surveys in the 1002 Area was about making informed decisions.
The Alaska State Constitution says the state's objective is to
manage its resources by making them available for the maximum
use consistent with the public interest. Decisions need to be
made that are based on current information and not 30-year
technology, he argued. [The division] believes that whether the
resources are on state or federal lands, consideration must be
given to both the state and the federal interest. [The
division] is not at all convinced that setting this land aside
is in the national interest, much less in the state interest.
Further, the National Environmental Policy Act (NEPA) process
cautions against making decisions based on incomplete or
unavailable information.
MR. DECKER turned to slide 19, saying [the division] believes
the plan it put forth was in compliance with ANILCA and was
consistent with federal regulations governing exploration plans.
The Department of Interior turned down the plan in support of
the USFWS conclusion that any new exploratory activity is
prohibited by ANILCA, rather than authorized by ANILCA, and that
it would require an act of Congress to reauthorize.
MR. DECKER drew attention to slide 20, relating [the division's]
belief that significant questions remain unanswered. He said
describing something so uncertain must be done by a probability
distribution. The right answer is unknown to the question of
where on the probability distribution the resource potential is
for oil in the 1002 Area. Another question is whether the
undeformed area adjacent to state lands is significantly richer
and more cost effective than the deformed area. These questions
translate to the question of, What is the best decision for the
United States and the State of Alaska? He said [the division's]
pitch is to know before walking away forever (slide 21).
2:24:31 PM
REPRESENTATIVE TARR asked whether the state's position is that
all areas should be available for oil and gas exploration and
leasing activities. The state's position on the 1002 Area has
been clearly outlined today, she said, but she is asking whether
there are any areas within the state that have been suggested as
not being suitable for oil and gas.
MR. DECKER answered the Department of Natural Resources (DNR),
and the technical staff at the Division of Oil & Gas, can
identify significant areas of the state that have very low oil
and gas resource potential. When it comes to land selections
and processing the over-selections, some parcels may be
evaluated as having no resource potential for oil and gas. For
example, volcanic or igneous rocks may be very prospective for
hard mineral deposits but have essentially zero potential for
oil and gas. Additionally, [DNR] recognizes conservation units,
state parks, and national parks and would never advocate for oil
and gas extraction [in those areas].
REPRESENTATIVE TARR asked whether areas that [DNR] might
recommend for conservation would only be recommended after [DNR]
could say they weren't available or didn't suggest them for oil
and gas exploration or leasing.
MR. DECKER replied he sees it as a question of timing. Drawing
attention to the Alaska land status map displayed on the wall in
the committee room, he noted the state lands are shown in blue
and said those lands identified as having oil and gas potential
were recognized two or more decades ago. Very prospective for
oil and gas, as seen by the division's area-wide lease sale
areas, are the central North Slope, state waters just offshore
of the North Slope, onshore down into the foothills, the rest of
the onshore North Slope, the National Petroleum Reserve-Alaska,
and the Coastal Plain of the Arctic National Wildlife Refuge.
Cook Inlet represents another highly productive hydrocarbon
basin. Also identified are the southern shores of Bristol Bay,
the Alaska Peninsula area-wide sale where over a million acres
are available on annual area-wide lease sale terms, just like
Cook Inlet and the North Slope lease sales. The aforementioned
represent the lion's share of the oil and gas resource potential
in the state. Other basins are still in an early phase of
exploration for oil and gas, such as the Nenana, Copper River,
Yukon Flats, and Susitna basins. Most of the lands that are
truly prospective for oil and gas were recognized as such some
time ago, and the set-asides for other conservation reasons are
largely independent of those lands.
2:28:59 PM
REPRESENTATIVE SEATON pointed out that state selections occurred
before the time of shale oil and gas. He asked whether there
are additional areas that are now prospective oil and gas with
the addition of tight shale.
MR. DECKER responded that, for the most part, the best place to
explore for shale is the North Slope and, in his view, even that
is currently very challenged given today's price environment.
Once shale is commercially viable, the North Slope would be the
place to start looking given its world-class oil and gas source
rocks and that they are at the right thermal maturity. The
other parts of the state don't tend to see that same richness of
source rock at the right thermal maturity to be highly
prospective for source rock reservoir or shale oil.
REPRESENTATIVE SEATON referenced slides 10 and 20 and the
concept of a Brookian Topset play that is 6.2 billion barrels of
technically recoverable. He inquired whether there could be
economically recoverable oil there.
MR. DECKER answered the aforementioned is a common question when
talking about resource assessments that specifically refer to
undiscovered, technically recoverable resource numbers. It is
tempting to ask how much of this will actually be gotten. He
said he tries to avoid falling into this trap because it varies
from assessment area to assessment area. A certain fraction of
the oil is going to occur in accumulations that are too small to
warrant economic development. A certain size accumulation is
needed to make it viable commercially and that size is going to
vary depending on how close it is to other infrastructure, the
flow rates that can be established, and a variety of other
parameters. There is both the size class issue and the price
issue. The Department of Revenue will speak next about a USGS
follow-up assessment that attempts to look at how much of that
is commercially viable and how that varies with price and costs
of services.
REPRESENTATIVE SEATON recalled Dan Seamount of the Alaska Oil
and Gas Conservation Commission (AOGCC) telling the committee on
2/20/15 that if Prudhoe Bay was re-pressurized to its original
4,500 pounds per square inch (PSI), an addition one billion
barrels of oil would be recovered. He asked whether this means
that re-pressurization would be one-tenth the size of the entire
1002 Area or equal to the 1002 Area. Saying he is trying to
determine comparative values, he further asked whether it would
be expected to be able to recover a billion barrels out of the
plays listed on slide 10.
MR. DECKER replied it would be valuable to hear the Department
of Revenue speak in regard to this direction.
The committee took an at-ease from 2:35 p.m. to 2:41 p.m.
2:41:35 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
began with slide 2 of his PowerPoint presentation, stating that
the 1002 Area of the Arctic National Wildlife Refuge is the most
promising unexplored area in Alaska. A large amount of resource
is believed to be in that relatively compact area. At 1.5
million acres, or 2,300 square miles, the 1002 Area is about the
size of the City and Borough of Juneau or the state of Delaware.
Development of Point Thomson suddenly brings the Arctic National
Wildlife Refuge much closer to existing infrastructure, allowing
the refuge to be built up without a lot of new work in virgin
territory.
MR. ALPER turned to slide 3 and cautioned that talking about
revenue from the Arctic National Wildlife Refuge is highly
speculative. He said the Department of Revenue (DOR) worked
with the Department of Natural Resources (DNR) to identify
consensus estimates from the previous federal reports. This is
an undiscovered, technically recoverable resource, so DOR can do
its best to say what would happen if it is developed, but cannot
say that it will be able to raise this money. At this point,
the refuge's proven reserves remain at zero. Before putting any
numbers before the committee, he said he wants members to first
understand DOR's assumptions.
2:44:07 PM
MR. ALPER called attention to the source documents highlighted
on slide 4: the 2005 "Economics of 1998 U.S. Geological
Survey's 1002 Area Regional Assessment: An Economic Update,"
and the 2008 "Analysis of Crude Oil Production in the Arctic
National Wildlife Refuge." He explained that the 2008 report
[by the U.S. Energy Information Administration (EIA)] was in
response to a question from U.S. Senator Ted Stevens to look at
some economic potential and was focused more on a replacement
for imports and an effect on the U.S. oil market. The USGS
report included a statement that said assuming the price of oil
is over about $55 a barrel, 90 percent of the oil is going to be
recoverable economically. The gap between technical and
economical becomes relatively narrow at $55. Since that was in
1998, the number now would be somewhat higher.
MR. ALPER spoke to slide 5, "Assumptions: Total Volume," saying
DOR is working under the assumption that because the largest
fields would be brought on first and because those largest
fields are the ones that will be inherently the most economical,
the great bulk of what is considered technically recoverable
will be economically recoverable in DOR's modeling. He said the
chart on this slide is directly from DNR's presentation and uses
the USGS numbers. The mean number of 7.69 billion barrels is
for the federal 1002 Area, and the mean number of 10.36 billion
barrels is for the entire study area, which also includes state
land, near offshore, and the Native corporation land near
Kaktovik. Thus, roughly 75 percent of the oil is going to be
from federal land and developed under federal rules, and the
other 25 percent will be different.
MR. ALPER addressed slide 6, "Assumptions: Distribution of
Volume," explaining that for purposes of modeling DOR presumed
[most of the resource is in] the undeformed part [of the 1002
Area] and DOR estimated that 15 percent would be state oil and
10 percent would be oil on Native corporation land.
2:45:59 PM
MR. ALPER reviewed slide 7, "Assumptions: Production Timeline,"
stating the EIA report laid out a production timeline that would
take about 10 years from the moment permission is given to
explore for oil. Assuming permission is given in January 2016,
it would take [until 2019] to get the plans together and the
leases and permits issued, so exploration would begin in about
2019. Assuming the first field is found three years later in
2022, and development takes four years, the first production
would be in 2026, consistent with the EIA report timeline of 10
years after authorization. From there DOR used its own
speculation of how to do this, which would be starting with the
largest fields, bringing one new field on line every two years,
totaling 25 new fields being brought on line over a period of 50
years, and adding up production and consequent revenue through
2075. He said this is very much outside of the standard
workload done by DOR, given the department typically projects
production and revenue about 10 years into the future. Beyond
that it ceases to be material for budget purposes for projecting
the state's revenues, but DOR was happy to do this projection
when asked by the committee co-chairs to provide this analysis.
MR. ALPER noted the graph on slide 8, "Assumptions: Field Size
Distribution," comes from the USGS. He said the white, black,
and grey bars on the graph represent the low probability, the
mean, and the best case or high probability for the number of
accumulations. The Y axis is the number of distinct oil fields
of these different sizes. Turning to slide 9, "Assumptions:
Field Size Development," he said DOR ran a model in three
different cases. In the high case, two of the twenty-five
fields are at more than a billion barrels and the smallest of
the twenty-five fields are at 128-256 million barrels. In the
low case, there are no billion barrel fields, two 512-1024
million barrel fields, and [three] fields of [32-64 million
barrels]. The total number of barrels that would be produced
through [2075] would be 4.5 billion, 7 billion, and 9.7 billion
barrels in the low, base, and high cases, respectively. In
response to Representative Seaton, Mr. Alper clarified that the
total number of barrels would be the aggregate production over
the 50 years of oil production starting in 2026, with the
fiftieth year of production of oil being in 2075.
2:49:19 PM
MR. ALPER drew attention to slide 10, "Assumptions: Production
Profile," pointing out the graph depicts a fairly standard alga
rhythm for how a new oil field is ramped up, peaked, and then
declined. The graph includes curves for the seven different
sizes of fields. It takes two to three years for production to
go up, a few years at the top of production, and then a decline
at about 6 percent [per year] as per DOR's standard curve.
MR. ALPER discussed slide 11, "Assumptions: Price of Oil." He
said these assumptions are getting a bit more speculative, but
most important is that throughout the study [all prices and
costs assume] 2015 constant numbers. This was done because the
numbers sound highly distorting when inflation is built into
them going 50-60 years into the future. For example, $110 with
2.25 percent interest 60 years from now is about $400 a barrel
for oil. Putting $400 barrels on the screen would just confuse
the issue, ne said. The number of $110 is not particularly
magical: the DOR Revenue Sources Book projects a 2024 price of
$134.39 a barrel; backing that price to current dollars at 2.25
percent gets to within a few cents of $110 a barrel. So, DOR
used that number for the modeling purposes. Scenarios were also
run at a higher and a lower price, which he will review later.
MR. ALPER turned to slide 12, "Assumptions: Gas," noting DOR
chose not to bring gas into the modeling at this point primarily
because it would have complicated the work beyond what DOR was
capable of doing in the three days that were had to generate
this. Also, the gas resource information is far less defined;
there is no geology or reports that tell roughly in volumes how
much gas there is. Further, DOR didn't worry about the cost of
handling the injecting and so forth of associated gas. The
reality is, should the Alaska LNG Project (AK LNG) move forward
on the anticipated timeline, the known reserves that are
essentially part of the initial production will have tapered out
and there will be room in the AK LNG line around 2045 or 2050,
which works out nicely with the development of the Arctic
National Wildlife Refuge that is being envisioned in this model.
2:51:34 PM
MR. ALPER moved to slide 13, "Assumptions: Costs," saying that
companies are spending money to do this. He explained that an
annual exploration cost of $500 million is assumed beginning in
2019 because it is roughly twice what is being spent on
exploration right now on the North Slope. After 10 years when a
good exploration regime will have been undertaken, annual cost
assumptions are cut in half to $250 million and continued onward
after the 10 years. If/when accumulations are found, the
development capital expenditures are assumed to be $10 per
barrel based on the size of the field, with that concentrated
over an eight-year timeline at the beginning of the development
of each field. Once oil is being produced, another $5 per
barrel in capital expense is assumed to be maintenance spending.
Once oil is being produced, an operating cost of $20 per barrel
is assumed for running the fields. The aforementioned costs are
important for calculating the profits-based tax because these
are lease expenditures. The netback, or tariff, cost is $12.25
per barrel; that takes DOR's estimates of 2024 and brings them
back to 2015 dollars and adds a little bit for the new feeder
line bringing the new oil from the refuge over to pump station 1
of the [Trans-Alaska Pipeline System (TAPS)].
MR. ALPER reviewed slide 14, "Assumptions: Fiscal (Royalty)."
A royalty rate of 12.5 percent was assumed for the sake of
simplicity, he explained, but a wide range of different royalty
rates is possible given three different land owners and that
there will be a number of different lease offerings. The 12.5
percent correlates with the major state-owned fields in the
North Slope. For federal royalties, DOR assumed current law,
which is the state gets 90 percent. This assumption could be
controversial, he allowed, because it is reasonable to think
that before the federal government would allow something
tremendous like this to go forward, it would insist on a
different split arrangement. He also pointed out that under
Alaska's production tax law, private royalties are subject to a
5 percent gross production tax. Thus, the KIC royalties would
be subject to a 5 percent gross production tax, which was
recognized in DOR's royalty calculation.
2:53:52 PM
MR. ALPER called attention to slide 15, "Assumptions: Fiscal
(Production Tax)." Under the current tax regime established by
Senate Bill 21, he noted, these new fields will be eligible for
the 20 percent gross value reduction (GVR). Also included in
Senate Bill 21 for new fields was a per-barrel production credit
of $5. Because DOR is keeping the price of oil at 2015 levels
going forward, the $5 subtraction factor is reduced at the same
inflation rate - so that $5 is decreased to a smaller number
going further and further into the future for the purpose of
calculating production tax. It is also assumed that this will
be a single stand-alone company, thereby avoiding issues of
blended taxes. As well, DOR is not considering any impact on
the current producers within the North Slope and how it might
impact their taxes. It is a simplifying mechanism, but the net
effect is roughly the same no matter how it is done.
Additionally, if companies are operating in the red during the
early years - spending money and not yet producing - Alaska's
tax system considers that to be net operating loss and the state
currently reimburses those as a 35 percent credit under the
carry forward annual loss credit. That is seen as a negative
cash flow to the state during some of the early years of this
project.
MR. ALPER discussed slide 16, "Assumptions: Fiscal (Other
Taxes)." He said the corporate income tax is an apportionment
formula that works out to be about 6.5 percent of after-
production tax profits, and DOR used that 6.5 percent number in
this analysis. Corporate income tax cannot be negative or zero,
so there is no carry forward. For property tax, current
collections are about $1.25 per produced barrel, but that is an
aggregate. These numbers are shared with local jurisdiction
because nearly all the associated infrastructure is within the
North Slope Borough. The current apportionment is about 92.5
percent to the borough for comparable assets, so only 7.5
percent of that $1.25 goes to the state.
2:55:56 PM
MR. ALPER then turned to slide 17 to review the total projected
volume of oil produced and the total projected net revenue to
the state for the study period of 2016-2075, based upon the
aforementioned assumptions and caveats. Regarding projected
total volume, he reported that 7.1 billion barrels of oil would
be produced under this model at the base case; at the high case,
which is considered 5 percent likely, it would be 9.7 billion
barrels; and at the low case, which is considered 95 percent
likely, it would be 4.5 billion barrels. Regarding projected
total net revenue in constant 2015 dollars, he reported [$94.8]
billion at low case, $210 billion at high case, [and $150.9
billion at base case] over the 50 years of production.
MR. ALPER displayed slide 18 to show how the aforementioned
[hypothetical] production volume would look in graph form for
the low, base, and high cases. He pointed out that in the base
case (blue line), production peaks at 550,000 barrels a day in
the early 2040s, which is roughly the size of current North
Slope production, and then production declines in the years
after that. In the high case [green line], production peaks at
over 700,000 barrels a day and in the low case [red line] the
production peak is about 350,000 barrels a day. He moved to
slide 19 to present a production graph for the base case that
shows the volumes of the 25 fields layered on top of each other.
2:57:17 PM
REPRESENTATIVE JOSEPHSON referenced slide 18 and concluded that
DOR's projections for the refuge are that it will be larger than
Kuparuk but smaller than Prudhoe Bay.
MR. ALPER replied the Arctic National Wildlife Refuge is many
small fields, so in aggregate it would produce oil that is
larger at its peak than Kuparuk and smaller than Prudhoe Bay.
He would be cautious, he advised, to say it is larger because
there is no single accumulation within the refuge presumed to be
at that type of field. In the high case the largest single
field is in the level of one to two billion barrels in place.
REPRESENTATIVE JOSEPHSON inquired why it is projected that it
would take 10 years from discovery to production given there is
already a pipeline in place, unlike during Prudhoe Bay's
development from 1967-1977.
MR. ALPER responded DOR used certain estimates from the EIA. He
said he is not an engineer and will not speculate too far as to
how that might go. Permitting is different than it was in the
late 1960s and early 1970s. The 1969 discovery was at the tail
end of an exploration period where people had been up there
looking for oil for several years. Built-in within that 10
years is the initial offering of leases and the initial
exploration that might lead to a discovery. Between the
discovery and first production is only about four years,
basically the construction time of getting the field itself
developed and the feeder pipeline. The Point Thomson feeder
line that is in place can handle about 70,000 barrels per day.
So, if the volumes started increasing to the substantial numbers
DOR is talking about, it would take a new and larger pipeline
going all the way back to Prudhoe Bay.
2:59:40 PM
MR. ALPER provided the projected lease expenditures in graph
form [slide 20], with the spending broken into the categories of
startup capital, ongoing capital, operating costs, and
exploration capital. He said these very large spending numbers
will have massive economic impact within Alaska, with corporate
spending being between $4 and $7 billion a year for many years.
MR. ALPER displayed what state revenue would look like in graph
form for the base case scenario [slide 21]. He explained
exploration spending would begin in 2019 according to the
assumptions, but without any production these early expenditures
would be eligible for the net carry forward annual loss credit.
Once oil production starts, royalty revenue and property tax
would begin, and several years' later revenues would begin from
production tax and state corporate income tax. In constant 2015
dollars, revenues would reach a maximum of about $4.5 billion
per year, tapering down slowly to about $3.5 billion per year in
the far out years of the study period.
MR. ALPER turned to slides 22 and 23 to break out the key
components of revenue in the base case scenario. He noted the
red curve for royalties on slide 22 is the same as the red band
within the mixed curve on slide 21. He pointed out that 75
percent of this oil is federal oil; of that federal oil, the
state is getting 90 percent of the royalty. Should the royalty
split be different, then this red curve would be somewhat
smaller, although it would not in any way change any of the
other economics. Also, whatever the number is within this red
area, 25 percent of that number goes directly to the permanent
fund; in other words, the red curve is all royalty, including
royalty that will go to the permanent fund. Moving to slide 23,
he discussed the component of production tax revenue in the base
case scenario. He drew attention to the credits [that would be
paid out by the state] in the early years, but noted large tax
revenues would be realized once there is substantial levels of
production. Production tax [net of all credits] would be $1.5-
$2 billion per year [from about 2038-2075].
3:02:07 PM
MR. ALPER displayed slide 24, explaining it is a graph of all
the components of state revenue for the high case scenario. He
noted that in the high case the amounts of oil are larger, but
all the other assumptions, such as the cost per barrel and price
of oil, are the same. Therefore, the revenues are another
couple hundred billion dollars higher. Drawing attention to the
graph on slide 25, he said it is the same components of state
revenue but for the low case scenario. The lower amount of oil
results in less revenue, but the revenue amounts are still
substantial for many years into the future.
MR. ALPER moved to slide 26, stating DOR also did an analysis of
state revenue at a higher oil price of $140 per barrel instead
of $110. He pointed out that the costs upfront - the credits -
are the same, but revenue in the out years is much higher,
peaking at about $7 billion per year in the base case scenario.
However, he continued while turning to slide 27, if the oil
price is low [$80 per barrel in the base case scenario], it
becomes a constrained project where the state may not see
sufficient revenues to warrant the investment undertaken by the
state. He qualified that an oil price of $80 going forward to
60 years from now seems a very unlikely scenario to him
personally, but DOR wanted to provide both high and low numbers
to provide a sense of what the state's potential options.
3:03:29 PM
MR. ALPER addressed slide 28, saying other benefits would accrue
to the state besides money once the Arctic National Wildlife
Refuge property is developed. The first benefit would be gas.
In addition to the billions of dollars in revenue from producing
and developing that gas, the life of the Alaska LNG Project
would be extended by decades. Because a lot of the AK LNG core
infrastructure would have already been paid for, this second
generation of gas would be even more profitable than the first.
The benefit to the Alaska economy of the base case investment
spending of almost $7 billion per year would be almost
incalculable. The state's economy would be tremendously
increased, as would the number of jobs for many, many years.
Another benefit would be extending the life of the Trans-Alaska
Pipeline System (TAPS). These hundreds of thousands of
additional barrels of oil would set aside for another generation
the issue of when TAPS is not going to have enough oil to
operate economically. Lastly are the local benefits; for
example, the North Slope Borough would be looking at a couple
hundred million dollars just within the borough every year in
property tax revenue.
MR. ALPER, speaking to slide 29, urged committee members to keep
in mind that this is just one possible view. It is by no means
a projection, and not a forecast. It is a model based on
parameters that DOR came up with that were reasonable based upon
the best available information. What could be produced over a
60-year period is entirely dependent on someone finding oil,
that oil being producible, and being able to bring the oil to
market under the terms and conditions that DOR imagined here.
Actual development could happen faster or slower. He made it
clear that DOR does not currently include any Arctic National
Wildlife Refuge production or revenue inside DOR's official
forecasts.
3:05:45 PM
REPRESENTATIVE TARR said she appreciates seeing the analyses for
high and low oil prices, but noted today's oil price is $55.
She inquired whether DOR has run the numbers for a price of $55.
MR. ALPER replied DOR has not specifically run the numbers at
$55. He offered his expectation that given the cost of bringing
this oil to market, including the remote location, it might not
pencil out very well if it was found that $55 was going to be
the price of oil for decades. The DOR Revenue Sources Book
anticipates this price will hold for a year or so and then there
will be a recovery by 2017 to something more like what was seen
in recent years before the $55.
REPRESENTATIVE TARR posed a scenario in which one of the three
major North Slope producers becomes involved in producing on the
Arctic National Wildlife Refuge. She asked whether during
development the producer would be able to apply the net
operating loss credits against its other production tax for
other oil revenue. She further asked whether that would cause a
shift in the state's other oil revenue receipts if this is done.
MR. ALPER responded that if development was done by the current
suite of producers in the North Slope, rather than by a new
company, the expenditure would result in a spending offset to
their profits for their other production within Alaska, not a
carry forward annual loss credit. It would be a savings at the
same rate - a 35 cent on the dollar reduction in their tax
liability, which the state would see on the revenue side rather
than on the expenditure side. Should the spending drive the
companies to a place where they are no longer profitable, the
companies would have to carry the loss on their books and hold
it against a future year's tax liability because a large company
in Alaska is not eligible to get a carry forward annual loss
credit reimbursed in cash. So it would shift some of the cash
flow to the right a little bit, but the net effect in dollars
would be roughly the same.
DAN STICKEL, Assistant Chief Economist, Tax Division, Department
of Revenue (DOR), added that, for this analysis, DOR did not
make any distinction between existing producer and new producer.
It was just the question, What is the net fiscal impact to the
state? It is a 35 percent credit and that is what is shown.
3:09:08 PM
REPRESENTATIVE SEATON, regarding the slides depicting components
of revenue, inquired whether [the net operating loss credit]
would be a cumulative outflow from state revenue of about $9-$10
billion.
MR. ALPER answered "more or less." Looking at the graph, he
said it would be a large cost to the state because of the large
capital spending and, under current law, the state would be
reimbursing 35 cents on the dollar. For example, for a company
coming to Alaska and spending $5 billion, the state's 35 percent
reimbursement to that company would be $1.75 billion.
REPRESENTATIVE SEATON, presuming a mix of developers, calculated
the state could be looking at reducing those taxes payable from
other oil and gas production to near zero, as well as looking at
reimbursement in the credits for the net operating loss carry
forward in the following year. He asked whether a mix of new
and existing players could result in diminishing then-current
revenue from oil taxes, as well as the state being liable to new
players for quite large directly reimbursable credits, like what
is being played out under the Point Thomson development.
MR. ALPER replied the number on the graph on slide 21, which is
roughly consistent in the other scenarios, is a sum total of
what Representative Seaton is describing as a mix of companies
doing the work. For those companies that are incumbent
producers having other ongoing profits in Alaska, the state
would see it as a reduction from tax. For the new players, the
state would see it as a credit paid out. However, the sum total
would be the number seen on the chart.
REPRESENTATIVE SEATON calculated that, depending upon the mix of
developers, the state could possibly not have any income from
production tax and only a small amount from royalty. He asked
whether, depending upon the mix, the state could get in a
situation where it didn't have any income or had very little
income, and would still have the expenses of the other portion.
MR. ALPER responded Representative Seaton is looking at the
early years of a massive project where there would be
potentially large cash outflows to the state. That would be
something the state would have to find a mechanism to finance,
or absorb, with the understanding and expectation that there
would be quite larger revenues coming to the state several years
afterwards when these oil fields are under production. It is
not terribly different from what is currently being discussed on
the gas pipeline where the state is going to have a major
investment component in the early years and a major tax impact
because of some of the work that's going to need to happen to
enable the gas pipeline to get built, yet the expectation is
that the billion dollars of annual revenue that comes in once
over that hump. There will, he said, most definitely be hump.
3:13:38 PM
REPRESENTATIVE JOSEPHSON pointed out that in today's scenario
the state is bringing in apparently about $2.5 billion of
revenue in the current fiscal year and will have a $3.5 billion
deficit. He recalled that this year the legislature's experts
have talked about revenue of $3.5 billion from a gasline. He
posited that if the state had a gasline and production from the
Arctic National Wildlife Refuge at the same time, the state
would be able to sock away billions of dollars every year. He
inquired whether that is possible.
MR. ALPER answered the expense side of the state's ledger is
beyond what was done in this analysis. But, yes, he allowed, it
does seem like a tremendous amount of money that will be coming
into the state at that point in the future.
3:15:06 PM
REPRESENTATIVE SEATON observed on slide 13 that the assumption
for development capital expenditures is $10 per barrel over an
8-year development timeline, the assumption for maintenance
capital expenditures is $5 per produced barrel each year, and
the assumption for operating cost is $20 per produced barrel
each year. He asked whether these figures are within the
ballpark of where the state is now at a $25 net operating cost,
the $20 operating cost plus the $5 maintenance. He further
asked whether that is the cost scenario range that the state has
in the current production tax or profit-based tax.
MR. ALPER replied the $20, $5, and $10 add up to a total of $35
per barrel in lease expenditure, which is in the ballpark and is
actually a little low for what is being seen right now. It must
be realized that what is happening right now is not just the
operation of current fields but the development of some new
large fields that aren't producing anything yet and those costs
get absorbed into the totals. The $10 per barrel development
capital expense on slide 13 represents working on next year's
oil field while building this year's oil field. These things
are all happening at the same time so it ends up being an
aggregate number that roughly lines up with what is the current
spending in the North Slope. The North Slope is pretty much
used as the model by DOR.
REPRESENTATIVE SEATON drew attention to the 35 percent credit
depicted on slide 21, saying he doesn't see any costs related to
production tax as those new fields come on. He inquired whether
he is misinterpreting that or whether it is a subtraction from
the aggregate of production tax received by the state.
MR. ALPER displayed slide 20 to respond, explaining it shows the
industry investment totals. A big bump in capital spending is
seen in the early years, primarily because the largest fields
are developed first and the largest fields have the highest
capital investment component to them. In those early years
production is small or nonexistent. The outflow of cash [from
the state] represents that large capital expenditure before
there are substantial amounts of revenue and production, and
that is cashed out to the developer at 35 cents on the dollar.
3:18:39 PM
REPRESENTATIVE TARR recalled that oil prices peaked at almost
$150 around 2008, but was around $60 just before that, and today
the price is $55. She asked how DOR accounts for that much
price fluctuation when modeling for a 60-year time period.
MR. ALPER answered that, without running a very different and
more complex modeling, DOR cannot. What was considered a
reasonable, average number was chosen and taken forward. He
recalled that Mr. Barry Pulliam of Econ One Research was before
the committee several years ago to talk about his expectation of
long-term oil prices. Mr. Pulliam made a compelling case for
$80 and $130 being a long-term low and high, $80 being the point
at which much of the more marginal current production might fall
off for being uneconomical and $130 at which a bunch of really
new production might come on line. Mr. Pulliam anticipated a
relatively stable time bouncing within that range going forward,
and $110 conveniently falls within that and also conveniently
lines up with DOR's own long-term projections. There is no
magic to this, he added, and the one thing he can guarantee
about this presentation is that DOR is wrong - it will not be
exactly what has been put before the committee.
3:20:13 PM
REPRESENTATIVE SEATON recalled some consultants were expressing
concern that under existing scenarios the state could be looking
at not making any money from some of the fields over time. He
surmised that while slide 21 doesn't include net present value
of the money expended and the money received, DOR's analysis
looks at this as being a profitable deal for the state over the
operating length of the fields.
MR. ALPER replied yes, explaining DOR also assumed roughly the
same economic profile for each of the 25 different fields,
meaning the same cost per barrel for the smaller versus the
larger fields. In real life, however, variation is expected due
to geological differences, some fields being more constrained,
and some that are more capital intense. So, it is possible that
some of the conditions being talked about by Representative
Seaton might come into play. Some of the inherently less
profitable fields might not pencil out for the state and they
might not get developed because they don't pencil out for the
producer either.
3:21:39 PM
ADJOURNMENT
There being no further business before the committee, the House
Resources Standing Committee meeting was adjourned at 3:22 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2.23.15 DNR ANWR HSE RES.pdf |
HRES 2/23/2015 1:00:00 PM |
|
| 2.23.15 DOR ANWR HSE RES.pdf |
HRES 2/23/2015 1:00:00 PM |
|
| 2.23.15 EIA ANWR Report 5-08 HSE RES.pdf |
HRES 2/23/2015 1:00:00 PM |
|
| 2.23.15 USGS ANWR Resource Study 2005 HSE RES.pdf |
HRES 2/23/2015 1:00:00 PM |