Legislature(2009 - 2010)SENATE FINANCE 532
02/17/2010 01:30 PM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| Operating and Capital Expenditures | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
SENATE FINANCE COMMITTEE
February 17, 2010
1:32 p.m.
1:32:F20 PM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 1:32 p.m.
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
Cherie Nienhuis, Petroleum Economist, Department of
Revenue; Marsha Davis, Deputy Commissioner, Department of
Revenue.
SUMMARY
Oil and Gas Overviews:
PRODUCTION TAX LEASE EXPENDITURE REGULATIONS
OPERATING and CAPITAL EXPENDITURES
^OPERATING AND CAPITAL EXPENDITURES
1:33:25 PM
CHERIE NIENHUIS, PETROLEUM ECONOMIST, DEPARTMENT OF
REVENUE, informed the committee that she would present an
update of operating and capital lease expenditures based on
information acquired since the state changed its tax system
to a net profit system. She explained that some of the
information presented was acquired either through the
former profits tax called the Petroleum Profits Tax (PPT)
or through the Alaska Clear and Equitable Share (ACES) tax,
which has been in place since the PPT.
Ms. Nienhuis provided a PowerPoint presentation, "Operating
and Capital Lease Expenditures, Senate Finance Committee,
February 17, 2010" (copy on file), and outlined the agenda:
· Lease Expenditure Sources
· Total North Slope Lease Expenditures
· Standard Deduction Provision
· $0.30/barrel Capital Expenditure Exemption
· Trends in North Slope Spending
Ms. Nienhuis turned to slide 3, "Lease Expenditure
Information Sources," and delineated the sources available
to the department:
· Capital expenditure information
· Monthly expenditure estimates
· Annual expenditure information, 2006 - 2009
· Future expenditure projections from North Slope
operators
· Manual processing of all expenditure information
Ms. Nienhuis detailed that the capital expenditure
information was historical, current, and projected. The
Department of Revenue (DOR) receives monthly expenditure
estimates from companies spending money in the state's oil
and gas operations. The state has also received annual
expenditure information from tax returns for calendar years
2006 through 2008; 2009 returns will be received March 31,
2010.
Ms. Nienhuis explained that all the information regarding
lease expenditures is received in various manual forms,
including Excel sheets, PDFs, and sometimes hard copies.
1:37:02 PM
Ms. Nienhuis provided more information related to capital
expenditure information. She reported that during the PPT
discussion, there was reference to transition investment
expenditure credits (TIE); TIE credits still exist but have
changed since the inception of ACES. The TIE credit set up
a system whereby companies could receive credit for
expenditures between the years of 2001 and 2006; the
department received information regarding estimated capital
expenditures during that time period.
Ms. Nienhuis noted that the department began getting
monthly expenditure estimates in May 2008. The ACES tax
system set up a structure requiring companies that were
spending money in oil and gas operations to submit monthly
estimated expenditures and tax payments. She underlined
that the monthly expenditures are only estimates, not
audited documents. The numbers are used by the economic
research group to forecast tax revenues for the state.
Ms. Nienhuis listed details regarding annual expenditure
information:
· Auditable production tax returns, due March 31 of each
year
· First filing March 31, 2007 (first under PPT)
· Second filing March 31, 2008 (first under ACES)
· Third filing March 31, 2009 (second under ACES)
Ms. Nienhuis emphasized that DOR had tax returns without
some of the calculation information that would ordinarily
be on a standardized return because during the whole period
of time the department was working on regulations and
defining such items as lease expenditures. Returns were
submitted manually. The department hopes to have a
standardized form developed within a year.
Ms. Nienhuis reported that the department receives
expenditures based on projections. Two forecasts are done
each year, one in the fall and one in the spring. Prior to
the forecast, operators are asked to submit their best
projections for capital and operating expenditures, by
unit, for up to five years. Statute limits the
communications to what the operators share with working
interest owners; a special projection is not prepared for
DOR. As a result, projections vary by operator and by
property. Some projections categorize costs and others do
not.
1:40:37 PM
MARSHA DAVIS, DEPUTY COMMISSIONER, DEPARTMENT OF REVENUE,
added that the form for the annual return has been
completed and issued, and will be required for March of
2011. The department will not require that the standardized
form be used for March of 2010 because companies will need
time to merge their software into an Excel format.
Co-Chair Stedman requested more detail regarding transition
credits. Ms. Davis replied that an individual breakdown of
credits would be provided in the credit section of a future
hearing.
Ms. Nienhuis directed attention to a graph on slide 6,
"North Slope Operating and Capital Expenditures, Reported
and Projected." She noted that the numbers were not audited
but totals received by looking at annual tax returns, and
that the numbers shown for 2010 and 2011 are projections.
Operating expenditures are shown in blue and capital
expenditures in orange. She pointed out that capital
expenditures have grown each year since the inception of
the net profits tax and that operating expenditures are
expected to decrease in the future. In general, there are
overall increased expenditures for the North Slope.
Co-Chair Stedman asked whether a future hearing would cover
the sources of capital expenditures. Ms. Davis replied that
detail regarding capital and operating expenditures would
be covered at the present meeting and that the next day's
hearing would cover how credits were applied for.
Co-Chair Hoffman pointed out that the projected capital and
operating expenditures for 2011 are the highest of the past
five years. Ms. Nienhuis agreed that the projections were
higher than any previous year.
1:44:01 PM
Ms. Nienhuis turned to a graph on slide 7, "Capital
Expenditures per Barrel, Total North Slope." She emphasized
that capital expenditures, unlike operating expenditures,
do not always coincide with active production. Capital
expenditures normally precede production; the increase of
capital expenditures per barrel depicted on the graph
reflects spending and a steady or slightly declining
production base. The fact that capital expenditures per
barrel are on the rise says more about future production
than about current production.
Co-Chair Stedman asked whether the barrels were net or
gross. Ms. Nienhuis replied that they were taxable barrels.
Ms. Nienhuis noted that the graph on slide 8, "Operating
Expenditures per Barrel, Total North Slope" shows total
reported operating expenditures; the standard deduction
provision is not included. The numbers reflect what was
reported to the department through annual returns in some
cases and through monthly returns in others. She
highlighted a decrease starting in FY 10, and explained
that operating expenditures are more or less costs to do
day-to-day business on the North Slope; expenditures coming
down could point to efficiencies or to services costing
less.
Senator Egan asked where maintenance costs fell. Ms.
Nienhuis replied that maintenance generally falls into the
operating expense category.
Ms. Davis clarified that they would be talking later about
the standard deduction, but she wanted to clarify related
to the slide that shows the real, actual operating
expenses. She noted that under the tax provision there was
a temporary cap on the operating expense deduction at
Prudhoe and Kuparuk; the capping is not reflected in the
graph.
Ms. Nienhuis added that the figures are unaudited, company-
reported figures; they could change with an audit.
1:47:25 PM
Ms. Nienhuis moved to slide 9, "Prudhoe Bay Operating
Expenditures per Barrel, as Reported and Forecast," a graph
covering 2003 to 2010. She commented that the chart is
included in the department's ACES review. She highlighted
the significant rise in operating expenditures in 2006 and
2007, numbers consistent with published documentation by
Cambridge Energy Research Associates regarding similar
trends worldwide. Costs are shown coming down in 2009 and
2010, reflecting operating expenditure trends everywhere.
Co-Chair Stedman detailed for the public what the dollars-
per-barrel figures on the graph represented. He pointed out
that each 2010 penny translates to about $2.4 million;
producing 240 million barrels per year has huge impact.
Ms. Nienhuis observed that the price of oil needed to be
considered when discussing operating expenses. She
elaborated that there was an increase in the price of oil
along with the increase in operating costs per barrel. The
department believes that the price of oil and the price of
doing business in oil and gas operations are directly
correlated, although possibly lagged; increases in the
price of services, lease expenditures, and various items
are related to increases in the price of commodities,
including oil. She hoped the price decline seen in 2008 and
2009 would help drive operating costs down.
Ms. Davis elaborated that as the price of oil goes up, it
becomes much more lucrative to be in the oil and gas
business, and that the resulting pressure to move quickly
is more costly. An intense amount of demand can be placed
on services and equipment; a higher demand on the commodity
can translate to increased prices. Conversely, when oil
prices drop, demand goes down, commodities lag, and prices
of services have to go down.
1:51:14 PM
Co-Chair Stedman pointed out that the 2010 operating
projection was roughly $2 billion. Ms. Davis added that the
$2 billion was the total for the North Slope.
Senator Thomas asked whether the significant increase in
operating expenses was related to maintenance difficulties
in Prudhoe Bay in 2006. Ms. Davis replied that in absolute
dollars there is an increase in operating expenses
associated with repair work. She added that the actual
costs associated with the spill and corrosion event are not
allowed to be deducted as lease expenditures and would not
show up on returns. However, after a spill a company would
proactively replace other lines. She cautioned that that
alone would not explain the increase in operating expense
on a per barrel basis.
Co-Chair Stedman requested dollar per barrel information
related to Prudhoe Bay as well as other expenditures
outside of Prudhoe Bay. He wanted information separately
for Prudhoe Bay and Kuparuk. Ms. Davis explained that there
was data for Prudhoe Bay operating expenses and not for
Kuparuk.
Co-Chair Stedman suggested dividing the data up between
Prudhoe Bay and all other units. Ms. Davis did not know if
there was a total North Slope operating expense figure for
2003, 2004, or 2005.
1:54:45 PM
Ms. Nienhuis observed that the department publishes
material on a much higher scale in the Revenue Sources
Book, including total North Slope expenditures. She
believed the most recent projection split capital and
operating expenses at about $9 per barrel. She offered to
verify and get more information.
Ms. Nienhuis directed attention to slide 10, "Standard
Deduction Provision at AS 43.55.165(j)." She explained that
the standard deduction provision refers to a limitation
placed on lease expenditures in Prudhoe Bay and Kuparuk
units. The amount was limited to the lease expenditures
that were set in calendar year (CY) 2006, the first year of
the net profits tax, and adjusted so that it could be
inflated by 3 percent each year. The standard deduction was
in place for CY 2007, CY 2008, and CY 2009; the provision
sunset at the end of CY 2009. She reported that the
department had not yet received its first monthly report
without the standard provision; the first was due at the
end of February.
Ms. Nienhuis turned to slide 11, "Prudhoe Bay Opex per
Barrel, as Reported and with Standard Deduction." The blue
bars in the graph depict the same figures as the blue bars
on slide 9, with the operating expenses (opex) per barrel
allowed under the standard deduction shown in the orange
bars from 2007 to 2009. She noted the clearly widening
differences for those three years. The 2010 projection
shows the gap narrowing, which she believed was related to
operating expenses coming down in general on the North
Slope and in Prudhoe Bay in particular.
1:57:34 PM
Ms. Nienhuis considered the "Impact of Standard Deduction"
(slide 12):
· Held operating expenditures fairly level for 3 years
· Expenditures more predictable for forecasting
· Difference between standard deduction and total
reported costs greater at Prudhoe Bay unit than
Kuparuk unit
· Impact on state revenues more significant as oil
prices increase
Ms. Nienhuis detailed that the monthly forms asked how much
was deducted under the standard deduction and how much was
actually spent in the unit. Ms. Davis added that one
speculation about the difference in cost between the two
units was that since Prudhoe Bay is in an active mode of
repair and addressing corrosion issues, there was less
discretion regarding what they would and would not spend
relative to operating expenses, whereas the Kuparuk unit,
which is not in a crisis, could shift expenditures
elsewhere and had more ability to stay closer to the cap
limit.
Ms. Nienhuis moved to slide 13, "Increase to State Revenue
from Standard Deduction Provision." The blue portions of
the bar graph show the amount of North Slope production tax
paid in FY 07, FY 08, and FY 09, and the impact of the
standard deduction is shown in gold. She noted that the
impact in FY 07 was fairly slight as the standard deduction
was only in place for half of the year. In addition, oil
prices were not as high as they were in subsequent years.
In FY 08, there were high oil prices, which increased the
tax rate and therefore the impact to the state of the
standard deduction provision. In FY 09, the impact went
down again, reflecting lower oil prices.
Co-Chair Stedman queried the total for the standard
deduction. Ms. Nienhuis answered [$611 million].
Co-Chair Stedman wanted to consider credits created in
Prudhoe Bay and Kuparuk, and how various factors acted as
stimulants and suppressants. He stated that one of the
questions was the effect of the 20 percent credit in
Prudhoe and Kuparuk, and how much the credit was offset by
the standard deduction, if at all. Ms. Nienhuis replied
that analysis has shown an operating expense component to
capital expenditure.
Ms. Davis added that a standard deduction only operated
relative to the operating expenses, not the capital
expenses, so it would not have had an impact on the value
of capital investment in the 20 percent tax credit; it
would have impacted the overall base tax rate of the 25
percent in the progressivity rate.
Co-Chair Stedman asked how much the standard deduction
diluted the credit stimulation. He thought that the purpose
of the credit was to stimulate in-field drilling and to
access heavy oil. Ms. Davis agreed.
Co-Chair Stedman pointed out that $611 million was a lot of
money. He understood that the standard deduction did not
apply to the capital expenditure side, but may possibly
have inhibited capital decisions to go forward and try to
extract more oil at Prudhoe and Kuparuk.
2:03:32 PM
Ms. Nienhuis directed attention to slide 14, "Capital
Exemption of $0.30 per barrel at AS 43.55.165(e)(18)."
· AS 43.55.165(e)(18) exempts $0.30 per barrel
o Initially intended to address costs of
maintaining and upgrading pipelines and
facilities
o Applies to all barrels produced, regardless of
property
· Impact of Capital Exemption
o Reduced reported capital expenditures by close to
$70 million per year
o Expenditure forecasts indicate maintenance and
upgrade of several hundred million
o Maintenance and upgrade expenditures could be
amortized over 10 to 20 years
· AS 43.55.165(e)(19) addresses unplanned maintenance;
Some reporting of unplanned maintenance expenditures
by companies
Ms. Nienhuis explained that the capital exemption was a
provision retained in ACES from PPT that exempts $0.30 per
barrel of capital deductions from the ACES tax calculation.
The provision was added relatively late in the
deliberations on the tax and was initially intended to
address costs of maintaining and upgrading pipeline and
facilities.
Co-Chair Stedman asked for more information. Ms. Nienhuis
believed the $0.30 per barrel exemption was a break for the
state as the state would not have to pay to upgrade aged
infrastructure and facilities on the North Slope concerning
capital credits.
Ms. Nienhuis noted that the exemption applies to all
barrels produced, regardless of where the oil comes from.
The impact to the capital exemption was that the state had
reduced capital deductions by close to $70 million per year
(the exemption is per barrel, so would go down as
production decreases). The department was asked to evaluate
whether the [exemption] was sufficient to cover the
maintenance and upgrade of facilities on the North Slope.
She reported that there has been some infrastructure
renewal, which can cost from tens of millions to hundreds
of millions of dollars. She observed that it was not clear
whether the improvements were because of the aging
infrastructure or were part of the project plan. The
department calculates that a several hundred million dollar
improvement would last 10 to 20 years, which could add up
to enough to cover the maintenance and upgrade.
Ms. Nienhuis pointed out that a provision added through
ACES (AS 43.55.165(e)(19) addresses unplanned maintenance.
The provision is an exemption; companies are not allowed to
deduct capital or operating expenditures incurred because
of an unplanned event such as an unforeseen equipment
breakdown or malfunction. She noted that since ACES, some
companies have self-reported unplanned events that they are
not deducting.
Ms. Nienhuis briefly reviewed slide 15, showing the per
barrel decline in capital expense exemption, reflecting oil
production decline.
2:07:32 PM
Co-Chair Stedman noted for the public that a future meeting
focusing on the credit will show how much of the credit is
applicable to exploration development and how much for
general maintenance; $0.30 per barrel was put in to help
protect the state from the 20 percent capital credit that
went to normal maintenance on an older field rather than
going to getting more oil out of the ground.
Ms. Nienhuis continued with slides 16-17, "Lease
Expenditure Information Mixed Bag":
· Is lease expenditure categorization required?
o Monthly information forms NOT REQUIRED
o Annual production tax returns - NOT REQUIRED
o Future expenditure projection form North Slope
operators - NOT REQUIRED; However…
· SOME operators provide categorization in very broad
categories on SOME properties
Ms. Nienhuis explained that information is received about
lease expenditures through hard copy, Excel, and other
forms. The "mixed bag" refers not only to the different
forms the information is received in, but the types of
reporting. She pointed out that there have been questions
regarding whether the lease expenditures are going towards
maintenance, rate-adding, or other programs. She added that
the reason there is inconsistency in the information
received is that companies have not been required to report
how they spend the money. The monthly information forms,
the annual production tax returns, and the future
expenditure projections do not include a break-out of
expenditure types other than capital and operating.
Ms. Nienhuis reported that some operators provide the
information in the form of future expenditure projection;
however the information is provided on some units, not all.
She explained that the department does its best to sift
through and classify the information, and she provided
examples of categories:
· Expense Workovers
· Major Repairs
· Seismic Acquisition and Testing
· Major Accident Review
· Facility Integrity
· Wellwork
Ms. Nienhuis added that the process of sorting the
information is further complicated by the fact that
different companies can give different labels to the same
thing.
Co-Chair Stedman sympathized.
2:11:56 PM
Ms. Nienhuis turned to slide 18, "Composition of North
Slope Capital Expenditures" and discussed the process of
classifying information received from companies:
· Based on review of company confidential cost
information, capital expenditures are placed into two
categories:
· "Resource or Development-related"
o Drilling & Wellwork
o Enhanced Oil Recovery Projects
o Seismic
o Facilities at New Fields (e.g. PT Thomson, WRD at
PBU)
· Other Capital Expenditures
o Major Repairs and Work on Existing Facilities
o Corrosion-Related Expenditures
o Safety Upgrades
Ms. Davis interjected that one of the challenges in
splitting the costs into categories was the question of the
relevance of any given activity. She referred to requests
from legislators regarding the cost of maintenance versus
the cost of production. She urged people not to lose sight
of the production impact of maintenance activities that
upgrade existing infrastructure. She stressed that
lengthening the life of existing fields flattens out the
decline curve of a field.
Co-Chair Stedman stated that he wanted to get a feel for
the workability of the 20 percent credit and to discern
what creates the capital credit and whether it enhances oil
recovery or is used for maintenance. He understood that the
operating and capital expenses were distinct.
2:15:57 PM
Ms. Nienhuis agreed and noted that there is usually an
operating component that compliments the capital; drilling
and wellwork, for example, incur expenses on both the
capital and operating sides.
Ms. Nienhuis directed attention to slide 19, "Share of
Planned North Slope capital Expenditures for 'Resource and
Development' Related Costs." The graph, put together from
the information received and categorized, shows projected
expenditures reaching a peak of nearly 75 percent in 2010
and then tapering off. She warned that the numbers were
based on projections that changed every six months.
Co-Chair Stedman referred to slides 7 and 8, regarding
total North Slope capital and operating expenditures per
barrel, which show increases in FY 11, and asked how that
relates to the decrease shown in slide (19).
Ms. Nienhuis commented that the department is seeing
increasing expenditures on the North Slope in general; from
the received projections, some of the costs are declining
percentage-wise, but only from 73 percent to 71 percent.
The portion of expenditures going to non-resource
development is still not significant.
2:19:06 PM
Co-Chair Stedman asked for dollar amount comparisons in
order to better understand the different slides, as two use
dollar amounts, while slide 19 uses percentages. He
suggested using gross dollars to avoid using the barrel
conversion.
Ms. Davis explained that the earlier slides depict the
entirety of all lease expenditures, both operating and
capital; the columns stand for the totality. Slide 19 shows
the percentage, and says that of the totality, 74 percent
of the column is associated with production-related costs,
meaning the other 27 or so percent represents the
maintenance or non-production activity. The slight dip in
2010 represents the total operating and capital
expenditures; of the slightly reduced total, there is a
tiny increase over the prior year associated with
production-related expenditures. The 2011 projection of a
record-high $5 billion includes 72 percent related to
production-related expenditures.
Co-Chair Stedman pointed to the 2012 bar showing about 68
percent. Ms. Davis explained that the percentage coming
down means the relative mix between production-related and
non-production-related expenditures is coming into better
balance and is not as production driven.
Co-Chair Hoffman noted an earlier statement that lower
operating expenditures are good and higher capital
expenditures are also good, but combining the two gets
confusing. Ms. Davis agreed and offered to split operating
and capital expenditures within the production and non-
production elements.
Co-Chair Hoffman pointed out the difficulty of telling when
operating costs go down when they are combined with the
capital expenditures. He suggested concentrating on the
fact that even though every year the operating costs go
down, they should be kept separate from the capital
expenses. He emphasized that every year since 2008 there
has been an increase in capital expenditures. Ms. Davis
agreed.
2:24:03 PM
Ms. Nienhuis agreed to come back with dollar amounts to
provide clarity.
Ms. Nienhuis directed attention to slide 24, "Recent Trends
in North Slope Costs":
· DOR has limited data to work with in analyzing
historic cost trends.
· Limited comparison of expenditures for three years
before and after PPT.
· Capital Expenditures at Prudhoe Bay
o Maintenance and corrosion repair expenses are not
the key driver behind the growth in capital
expenditures.
o Majority of the increase in capital expenditures
is due to drilling, seismic and projects (such as
development of the Western Region of Prudhoe
Bay).
· Operating Expenditures at Prudhoe Bay
o Major Repairs were a small part of total
operating expenditures pre-PPT&ACES and is still
a relatively small part of total lifting costs.
o Wellwork expenditures are the primary driver
behind the rise in Operating Expenditures.
Ms. Davis emphasized that the department currently has only
projection-type data and no way to verify that what was
projected to be spent was the way the spending actually
occurred. In future, operators may be requested to provide
data so that historical costs can be reported. She stated
that given the projections, DOR has concluded (at least for
Prudhoe Bay) that maintenance and corrosion repair expenses
are not the key driver behind the growth in capital
expenditures. She noted that maintenance and corrosion
repair expenditures grew between 2003 and 2008, but they
did not grow disproportionately.
Ms. Davis added that capital expenditures associated with
production-related activities also grew. In other words,
the growth in total capital expenditures was not simply
because of maintenance and corrosion repair expense.
Ms. Nienhuis commented that the majority of the increase in
capital expenditures was due to drilling, seismic, and
projects such as the development of the western region of
Prudhoe Bay.
Ms. Nienhuis reported that for the periods between 2003 to
2005 and 2008 to 2010, wellwork expenditures were the main
driver behind the rise in operating expenditures; major
repairs are a part of operating expenditures, but a
relatively small part.
Co-Chair Hoffman asked the amount of maintenance and
corrosion repair expenses relative to drilling, seismic,
and other projects. He wanted more detail than the
"majority of the increase in capital expenditures." Ms.
Nienhuis replied that there was generally about a $500
million per-year increase in capital expenditures from the
three-year period before PPT; about 60 percent of the
increase was due to drilling activities.
2:28:33 PM
Co-Chair Stedman questioned whether the increase included
the entire Prudhoe Bay basin. Ms. Nienhuis responded that
the numbers applied to the greater Prudhoe Bay/Pt. McIntyre
unit.
Co-Chair Stedman queried credits related to capital
expenditures created outside the described unit. Ms.
Nienhuis responded that the data over the longer time
related primarily to Prudhoe Bay. The analysis pertains to
Prudhoe Bay prior to and after PPT.
2:30:08 PM
Ms. Nienhuis moved back to previous slides, beginning with
slide 20, "Spending Trends":
· Company projection of expenditures changing
· Fall 2008 projected increased expenditures in most
units
· Fall 2009 projected divergence in plans
o Currently producing units - projected lower
expenditure
o Developing units - projected higher expenditures
Ms. Nienhuis detailed that the data is from company
projections operating on the North Slope in the spring and
fall of 2008, and the spring and fall of 2009. She reported
that in the fall of 2008, operators for most units
projected increasing expenditures in both capital and
operating expenditures. There was a change in the fall 2009
projections: some operators reported that they would invest
less in both operating and capital expenditures; others
reported that they would spend more in their fields.
Ms. Nienhuis remarked that DOR surmised that generally the
currently producing units were the ones that had projected
decreasing expenditures in fall 2009, while the developing
units projected higher expenditures going forward. The
developing units projecting higher expenditures going
forward included Point Thompson, Oooguruk, Nikaitchuq, and
the National Petroleum Reserve-Alaska (NPR-A). The
remaining units, Prudhoe Bay, Kuparuk, Milne Point,
Endicott, and Alpine, were projecting decreasing
expenditures going forward.
Ms. Nienhuis continued that the department thought it might
be detecting a trend and considered the data historically
as well as in projection. The bar graph on slide 21,
"Capital Expenditures by Type of Property," shows that as
far as the percentage of the total capital expenditures, in
FY 08 the underdevelopment category was around 25 percent
of the whole. In 2009 through 2010 (projected for 2011),
the underdevelopment expenditures comprise a greater
proportion of the total spending on the North Slope.
Ms. Nienhuis turned to slide 22, "Capital Expenditures on
Currently Producing Properties." She listed the currently
producing properties: Prudhoe Bay, Kuparuk, Milne Point,
Endicott, Northstar, and Badami. The fall 2008 projections
for the years of 2010, 2011, and 2012 total about $6.8
billion; the fall 2009 projections show the three years
totaling about $5.4 billion. She emphasized that the
Colville River unit is excluded in the calculations in each
bar because the department does not receive the same level
of capital projection as the others.
2:34:05 PM
Co-Chair Stedman believed that oil is more plentiful and
easier to find in currently producing Prudhoe Bay, Kuparuk,
Alpine, and Milne Point units, and that the state could
realize higher revenues. Ms. Nienhuis agreed that the units
provided the majority of the production tax.
Co-Chair Hoffman referred to an earlier presentation
regarding three categories of North Slope wells: wells
drilled in 2008, wells drilled in 2009, and wells that were
permitted and planned. He queried the relationship between
the three categories and the properties represented on
slide 21 ("Capital Expenditures by Type of Property"). Ms.
Nienhuis replied that the wells described in the earlier
presentation were exploration wells and would be under the
development category.
Co-Chair Hoffman asked whether that related to wells
permitted and planned. Ms. Davis explained that the
presentation was regarding exploration activity; under the
department's analysis [on slide 21] the same wells would be
called "under development." She added that the previous
presenter did not include a description of the wellwork and
extra wells being drilled in currently producing fields.
Co-Chair Hoffman surmised that the oil industry is saying
there is a lot less activity but in fact there is an
increase every year since 2008, 2009, and projected for
2010 and 2011. Ms. Davis replied that he was correct.
2:36:52 PM
Ms. Nienhuis concluded with slide 23, "Capital Expenditures
of Developing Properties," which shows a similar breakdown
on developing properties. The fall 2008 projections
received from the operators totaled $1.6 billion for the
three years; that increased significantly in the fall 2009
projections to $3.1 billion. She warned that the company
projections are not guaranteed and could change.
2:38:37 PM AT EASE
2:43:04 PM RECONVENED
ADJOURNMENT
The meeting was adjourned at 2:43 PM.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 2010 02 17 DOR Operating and Capital Lease Expenditures SFC.pptx |
SFIN 2/17/2010 1:30:00 PM |
Oil and Gas Production Tax Review |
| Agenda 021710 pm.docx |
SFIN 2/17/2010 1:30:00 PM |