Legislature(2007 - 2008)HOUSE FINANCE 519
11/08/2007 09:00 AM House FINANCE
| Audio | Topic |
|---|---|
| Start | |
| HB2001 || HB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB2001 | TELECONFERENCED | |
HOUSE BILL NO. 2001
An Act relating to the production tax on oil and gas
and to conservation surcharges on oil; relating to the
issuance of advisory bulletins and the disclosure of
certain information relating to the production tax and
the sharing between agencies of certain information
relating to the production tax and to oil and gas or
gas only leases; amending the State Personnel Act to
place in the exempt service certain state oil and gas
auditors and their immediate supervisors; establishing
an oil and gas tax credit fund and authorizing payment
from that fund; providing for retroactive application
of certain statutory and regulatory provisions relating
to the production tax on oil and gas and conservation
surcharges on oil; making conforming amendments; and
providing for an effective date.
KEVIN MITCHELL, VICE PRESIDENT, FINANCE AND ADMINISTRATION,
CONOCOPHILLIPS, provided a brief PowerPoint (Copy on File).
He summarized that CSHB 2001 (RES) represents a less
attractive climate for investors in Alaska, with a
significant tax increase, not only in the context of tax
rates and progressivity. He strongly emphasized that the CS
would have an impact on investment decisions.
Mr. Mitchell spoke to the proposed tax system. He noted the
increased base rate from 22.5 to 25 percent and that
progressivity is significantly increased over PPT amounts.
In addition, the progressivity has a tie to the gross
component to the absolute price. ConocoPhillips has been
consistent in emphasizing the need for all aspects of the
tax rates to be on a net basis, whenever those rates have a
gross component that can have a distorting impact. Net rates
adjust for changes in cost and margin; gross rates can be
negatively impacted. Lastly, the reduction of transitional
investment expenditure (TIE) credits penalizes investors who
have been consistent in their investment plans. He asserted
that TIE credits soften the impact of tax changes and
provide stability for investors.
9:21:46 AM
JIM TAYLOR, VICE PRESIDENT, COMMERCIAL ASSETS,
CONOCOPHILLIPS, referred to Slide 3, "Tax System and
Investments," depicting a graph with the Department of
Revenue's eight year forecast of production. He noted that
ConocoPhillips has been an aggressive investor in the North
Slope, investing over $12 million and participated in all
levels of the upstream business. He maintained the graph
represents those elements of the upstream business it will
need to arrest the production decline occurring on the North
Slope. The green wedge on the graph represents new field
development, the yellow represents other currently operating
fields, and the red and blue represent the two large fields
that have been referred to as the legacy assets.
Mr. Taylor asserted that investment is the key to North
Slope production sustainability. Without investment, the
blue area could decline as much as 15 to 20 percent per
year. The red wedge represents investment opportunities,
such as infill drilling, heavy or viscous oil, and handling
ever-increasing volumes of water and natural gas associated
with oil production. Infill drilling opportunities represent
less than 30 percent of the investments required to sustain
production in the legacy fields.
Mr. Taylor said originally estimates of North Slope oil were
around 24 billion barrels. Approximately 11 to 13 billion
barrels of that will come out of the existing Prudhoe Bay
field. The investments of the future are not the same as the
investments of the past. The single largest known reserve
potential in the North Slope contains approximately 26
billion barrels and lies underneath the permafrost between
the current producing zones, in the viscous and heavy oil
layers. Drilling for and recovering this oil will involve
many challenges, more risk and higher costs.
Mr. Taylor summarized that about 40 percent of production in
the red wedge will come from the existing fields, and
consist of handling water, gas, and heavy and viscous oil,
all of which cost more to develop.
9:26:07 AM
Mr. Mitchell listed the provisions beyond the base rate
increase that amount to a tax increase and add complexity to
administration (Slide 4):
· Out of state exclusion
· Topping plant exclusion
· DR&R [dismantlement, removal and restoration]
exclusion
· "Reasonable" transportation costs
· Exploration confidentiality
· 6 year statute of limitations
· Retroactive implementation
Mr. Mitchell argued that many out-of-state costs are
legitimate expenses for a project. The topping plant
exclusion targets one aspect of North Slope operations and
adds complexity to the process for both industry and
government, with significant effect on operations. He
maintained that DR&R costs are legitimate expenditures and
are typically an allowable expenditure world wide. He
pointed out that the industry is already governed by two
regulatory authorities and "reasonable" transportation costs
add additional complexity of administration for both
government and industry.
Mr. Mitchell discussed exploration data and confidentiality
provision changes. The provision restricting data
confidentiality to two years is a disincentive to
exploration credits. The six year statute of limitations has
the effect of extending the time it takes to complete and
close an audit. Increased interest costs resulting from the
additional time allotted would result in a significant
penalty. It will also take time to develop new regulations
to cover additional provisions, especially the retroactive
implementation. The industry is concerned about significant
costs in penalties and interest. He pointed out that tax
changes are generally phased in.
Mr. Mitchell summarized the impacts on the investment
climate. He acknowledged that the enhanced exploration
incentive credits (EIC) would be beneficial. More is at
issue than a 25 percent base rate and higher progressivity.
Some of the issues are too complex to be modeled yet. He
concluded that the added provisions create barriers to
investment.
9:33:38 AM
Co-Chair Chenault led a discussion about question and answer
protocol.
CLAIRE FITZPATRICK, COMMERCIAL VICE PRESIDENT, BP, provided
a PowerPoint presentation on the impacts of CSHB 2001 (RES)
(Copy on File). She observed that BP was not able to fully
review the legislation and its impacts because they received
the bill less than 48 hours previously. She acknowledged
that there are good business opportunities [in Alaska], but
expressed concerns.
Ms. Fitzpatrick reviewed the guiding principles for the
petroleum production tax (PPT): fair revenue to the state,
creating an attractive investment climate for new
exploration and reinvestment, and transparency. She
maintained that the current bill and the HRES version are
making a trade-off between short-term gain and long-term
risk, but to different degrees. An attractive investment
climate is one where the state recognizes the need to
increase investments. Alaska still has the highest tax rate
in North America. Future opportunities are not easy and the
cost base for the total activity set remains high.
Ms. Fitzpatrick asserted that the new administrative
provisions for transparency will make it difficult to
forecast, administer, and comply with the tax law. Fiscal
systems globally recognize that it takes a couple of years
to implement and evaluate new systems. She maintained that
the bill turns what they thought was a manageable system and
moves it into an inherently moving target. She acknowledged
that some of the provisions will make it easier for the
state to collect data, which they agree with as long they
are implemented correctly, but she questioned if companies
will be able to come up with consistent data, comply with
unknown rules, and do forecasting to an accuracy of 0.1 or
0.2 percent.
9:40:35 AM
Ms. Fitzpatrick compared some of the proposed measures to
their perception of the guiding principles. Gross
progressivity is a net trigger applied to the gross and adds
complexity. She concluded that gross progressivity would
impact investment decisions. She explained that under normal
circumstances companies would expect to pursue new
technology and investment opportunities if the price
environment remained above $52 per barrel for a sustained
period time. She maintained that gross progressivity would
impact these activities.
BERNARD W. HAJNY, MANAGER, PRODUCTION TAXES AND ROYALTIES
ALASKA, BP, expressed concerns about using joint interest
billings as a starting point for what is deductible under
PPT. The current bill would repeal the Department of
Revenue's (DOR) statutory authority under AS 165 (c) and (d)
to authorize the operator's use of [joint interest]
billings. He echoed concerns put forth by Conoco Phillips
regarding deductions of out of state costs. The current
legislation requires that costs most be physically located
in the state, while removing language clarifying that the
costs do not need to be in located on or near the unit,
field or exploration prospect.
Mr. Hajny discussed issues related to transportation costs.
He maintained that there is not a problem that needs fixing.
Any retroactive tariff adjustment applicable to any of BP's
taxable oil would be adjusted in future tax returns, along
with any associated interest. He stressed that the
Regulatory Commission of Alaska (RCA) and Federal Energy
Regulator Commission (FERC) are already charged with the
task of determining "just and reasonable" tariffs. He
thought the most straightforward approach is to continue
utilizing the Trans Alaska Pipeline System (TAPS) tariff.
Ms. Fitzpatrick added that BP executed the year's activity
in good faith that the tax principles were in place. She
suggested the committee answer the question whether the
retroactivity application is "reasonable" or "fair".
9:44:47 AM
Ms. Fitzpatrick noted that infill drilling noting is
profitable to both the state and industry, but emphasized
that infill drilling is only one element of future
development. The future is going to also require satellite
development, heavy oil, new technology, and infrastructure.
Building new, more efficient facilities will make the North
Slope viable for both existing and new developers.
Ms. Fitzpatrick addressed the issue of heavy oil and said
the current gross progressivity structure acts as a gross
tax when companies are making investment decisions. If there
is little or no upside potential, there is no incentive for
companies to increase risk for challenging projects like
heavy oil.
Ms. Fitzpatrick discussed long-term planning and the
variables that impact the process. Increased taxes reduce
the cash available to fund business. She stressed that BP
will continue to do business in the state. The amount of
increased development and exploration will be determined by
how much risk the company feels they can take under a given
tax regime. She maintained that the pace and scale of what
the company is able to do would change according to the
legislature's actions.
9:48:13 AM
CRAIG HAYMES, PRODUCTION MANAGER, EXXON MOBIL ALASKA,
presented an executive summary on HB 2001 (RES). He reviewed
written testimony and gave a PowerPoint presentation (Copies
on File). He observed that Alaska has great resource
potential and oil and gas with world class results. He
pointed out that currently production levels are down to one
third of its peak, which was 2.1 million barrels per day in
1988. According to the U.S. Geological Survey and the
Minerals Management Service, Alaska still has undiscovered
recoverable resources of over 53 billion barrels of oil and
259 trillion cubic feet of gas. Only one quarter of this
potential has been produced. Alaska's world ranking of
thth
proven reserves has dropped from 14 in 1977 to 30
currently. Prudhoe Bay and Kuparuk represent over 70 percent
of the current total North Slope production. These fields
will continue to act as hubs for future satellite
developments that would not be economic without their
infrastructure.
Mr. Haymes described Alaska as a high cost environment due
to its severe climate, remote location, sensitivity of the
environment, and exploration restrictions. Effective
application of technology is critical to future development.
He gave examples of leading-edge technology that has been
successful. In ten years, 75 percent of oil production will
come from new investments, which would require over $30 to
$40 billion, or double the current investment levels per
year.
Mr. Haymes maintained that Alaska needs a long-term resource
development policy, including (Slide 3):
· Characterization of state-wide resource potential
· Identification of key issues challenging exploration
and development
· Determination of key factors that impact resource
value
o Research and technology required
o Exploration development costs
o Regulatory and environmental considerations
o Land access challenges
· Establishment of goals and measurement of progress
· A fiscal policy that will encourage development of
remaining resources
· Regular meetings with industry and agency
representatives
Mr. Haymes proposed a collaborative approach to develop a
sustainable policy. The question is how Alaska's full
resource potential can be commercialized.
Mr. Haymes pointed out that industry needs a predictable
fiscal environment. Investments are capital intensive and
typically evaluated over decades. Changing the fiscal
environment for capital projects reduces the attractiveness
of investments.
9:55:16 AM
Mr. Haymes explained that Exxon Mobil supports the concept
of a net-based tax structure. He said that PPT has only been
in existence for just over one year; DOR has not completed
regulations nor commenced a PPT audit. Exxon Mobile met with
DOR to improve the ability to forecast revenues and is
willing to keep working to improve the department's
understanding of joint interest billings. Exxon Mobile
believes the policies established today will impact the
attractiveness of potential future projects.
9:56:29 AM
Mr. Haymes stated that the proposed tax increase is more
complicated than a tax increase. First, it would cause
uncertainty in the following ways:
· Sections 34(b) and 34(c) propose a number of different
reporting requirements for exploration tax credits. The
credit qualifications are linked to the release of
proprietary data. He argued that this is not the norm
throughout North America and that the release of
proprietary data would concern to any explorer, in
addition to increasing their costs. This would create
more uncertainty as to whether credit would be applied
for. In addition, exploration confidentiality
protection is diminished to a very short two years.
· Section 44(f) proposes additional information requests,
which they feel are ambiguous. "Other records and
information the department considers necessary" is of
concern. He maintained that any information required
beyond what is submitted with their current tax filings
needs to be carefully considered.
· Sections 48 and 49, which propose that the department
can, at any time, substitute the determination of
reasonable costs for transportation instead of the
taxpayer's actual costs.
· Sections 53 and 54 propose a limit on qualified lease
expenditures, restricted to those incurred on the lease
producing oil and gas. Exxon Mobile believes this will
decrease the attractiveness of opportunities and create
uncertainty.
· Page 42, subsection (19) proposes the disallowance and
limitation of costs associated with refineries or heavy
oil topping plants. He pointed out that there are
significant costs associated with meeting the
regulatory requirement of upgrading topping plants to
comply with the state and federal mandates for ultra
low sulfur diesel. He noted that they could deduct
costs if they trucked out the diesel at an additional
environmental cost. The potential environmental
exposure and risks from increasing truck traffic on the
roads needs to be seriously considered.
9:59:25 AM
Mr. Haymes continued that second, the proposed tax increase
would increase administrative burden.
· Section 36 proposes to increase the statute of
limitation from three to six years. He spoke against
the change and pointed out that extensions have been
historically granted when requested. The change would
increase the company's administrative burden and costs.
· Section 59 eliminates requirements for joint interest
billings as the starting point for audits. He thought
this would be a disadvantage as each year operators are
subjected to extreme audits. Exxon Mobile spends over
100 staff weeks each year auditing joint interest
billings.
Mr. Haymes added that the CS has a number of unreasonable
excessive components:
· Section 29 reduces the transitional tax credits from
six to three years. This provision was put in place in
recognition of the long term investment requirement,
and to encourage increasing investment.
· Sections 25 and 45 have excessive late filing and
document submission penalties. For example, there is a
$1,000 per day penalty for "each report, statement or
document" that is not produced "at the time required."
He maintained that the provision could result in
amounts that are disproportionate to the severity of
the offense.
· Section 57 proposes the publication of certain
proprietary tax information when the information is
aggregated among three or more producers or explorers.
He supported the desire to obtain additional
information under the PPT framework, but expressed
concern that the aggregation of three companies would
allow competitors to determine proprietary information.
He stressed the importance of protecting tax payer
confidentiality.
Mr. Haymes closed by emphasizing the need to collaborate on
a long-term investment development policy that increases
investment, develops resources, mitigates production
decline, recognizes the high cost environment, and provides
fiscal predictability for industry.
RECESSED: 10:03:16 AM
RECONVENED: 10:18:52 AM
Co-Chair Chenault invited questions for the panel of
industry representatives.
Co-Chair Meyer asked for clarification of definitions
regarding infill drilling, joint interest accounting, TIE
credits, and the discounted price for oil.
Mr. Taylor defined infill drilling as the initiation of the
drilling of a new well in an existing oil reservoir. The
geological risk is greatly reduced when a new well is begun
in a known deposit.
Mr. Hajny explained that joint interest accounting is
important to PPT as a basis for cost deduction. One of the
principles behind developing PPT was the ability for
producers to use the joint interest billing statements as a
basis for deducting cost. The majority of North Slope fields
use joint operating agreements. These agreements set out
procedures by which BP, as operator for Prudhoe Bay, bills
interest owners for their share of legitimate costs
associated with BP's operation of the field. A bill is sent
every month to Exxon Mobile, ConocoPhillips and Chevron for
their percentage share of the costs. This is the only basis
the companies have for determining what costs should be
deducted when filing estimated payments.
10:24:00 AM
Representative Hawker asked about the internal audit
procedures within the companies. Mr. Hajny observed that the
billings have a three year audit provision. There are
different audit provisions within each company. Companies
are billed as the costs are incurred by the operator.
Interest owners can deduct these costs from their PPT.
Representative Hawker asked if an audit process was in
place. He spoke to the permissive language in the original
PPT allowing the use of the joint interest billings. Ms.
Fitzpatrick commented that each joint billing is subject to
an audit each year by the parties who are not the operators.
For example, Prudhoe Bay would be audited by Exxon Mobile,
ConocoPhillips, and Chevron. The auditing is thorough,
detailed, and rigorous, and done from people outside the
organization.
10:27:58 AM
Representative Nelson asked for more clarification regarding
joint interest billings. Ms. Fitzpatrick explained that
there are different teams working on each field. Audit teams
bring in additional challenges. Auditing occurs externally
as well; there are a number of checks and balances.
Representative Nelson asked about the external auditing.
Ms. Fitzpatrick reiterated that they are audited by
independent companies and the results are publicly reported.
She observed that DOR has not started PPT auditing. She
pointed out that the department must wait until after the
company has filed to begin. She did not believe the
department was behind.
10:30:48 AM
Mr. Mitchell explained that TIE credits were put in place in
PPT legislation to provide some form of compensation for
those who had invested in the past under a previous tax
regime but were moving into a new tax environment. The
credits apply to investments, for example, that took place
in the 2003-2005 timeframe when there were no capital
deductions or credits on the investments. By the time the
assets were producing revenues, they were in the PPT
environment and being taxed at a 22.5 percent rate. The TIE
credits allowed for a five year look-back period and
additional credit could be taken that provides some form of
compensation. The credits require historic investment during
the timeframe and future investment in order to be
applicable.
10:32:56 AM
Representative Joule asked about the increase to Exxon
Mobile's profit. Mr. Haymes answered that Exxon Mobile does
not release earnings statements for Alaska, only quarterly
and annual reports. He stated that they had received
Representative Gara's letter requesting profit amounts and
were preparing a response. At today's prices, ACES would
represent a production tax increase of 350 percent since
2005. With the HRC version of HB 2001, the production tax
would increase by 470 percent since 2005. In the U.S., taxes
paid have exceeded earnings for the company. Since 2001 to
2005, Exxon Mobile profits were $40 billion. In that same
time frame, $60-70 billion of taxes were paid.
Representative Joule referenced the issue of audits and
questioned why the state should not be ruthless in the
auditing process also. Ms. Fitzpatrick thought they should
be but was not sure they would be. Representative Joule
recalled that the permissive language was a compromise.
DAN SECKERS, SENIOR TAX COUNSEL, EXXON MOBIL, agreed. The
legislation would repeal Sections 165 (c) and (d). Those
sections, which are not mandatory, provide that DOR can
start its audits by looking at the joint interest billings.
It does not have to, but can. He thought that was a good
action because the joint interest billings are thoroughly
audited. There is no economic incentive for anyone to pay
anybody else any more money than necessary. There are
internal rules, zero tolerance policies that do not allow
paying one cost from one field to another.
Mr. Seckers stated Exxon Mobile's concern regarding
repealing the sections. If the legislature grants authority
and then removes it, the concern is that DOR will no longer
look at the joint interest billings.
Representative Nelson understood that. Mr. Seckers stated
that a cost has to be valid in order to be paid. Their
accounting rules and internal ethics will not allow another
action.
Representative Kelly asked Exxon Mobile's opinion about what
the administration said regarding the provision. Mr. Seckers
replied that the administration has indicated that auditing
is mandatory; however, 165 (c) and (d) are not mandatory,
but permissive. He did not understand why. The industry
expects to be audited. He thought it would be a waste of
time. Representative Kelly noted that the administration has
said that they are not trying to eliminate the provision and
asked why they wanted it removed. Mr. Seckers did not know.
He reiterated that it is permissive.
Mr. Haymes added that if a DOR auditor requested a listing
of payments, there is nothing to go by except the joint
interest billings as a starting point. The industry spends
many staff hours and almost $500,000 dollars a year auditing
the other companies. He urged joint interest billings as the
starting point. The current language makes it exclusive and
creates ambiguity. He stressed that joint venture billing
experts do the auditing. They know what to look for.
10:44:32 AM
Representative Hawker wanted the external professional
standards applicable to internal auditors. Mr. Seckers
assured him that joint issue billings are looked at in
accordance with GAP [Government Accountability Project]
standards, which has specific guidelines as to what is
allowable as an expense.
Representative Crawford requested guarantees and described
his experience with failed expectations of guarantees
related to the oil industry. He stated concerns about
keeping taxes low without guarantees that money will be
reinvested in Alaska. He recommended a higher tax rate to
help create incentives to explore and develop more oil. Mr.
Taylor replied that there are no guarantees. He thought
encouraging investment and raising taxes had already
occurred since PPT mechanisms are in place to raise taxes
and introduce progressivity. Industry is saying that the
changes already took place last year and are being
revisited, creating uncertainty. He thought the investments
were there, but the elevated price is causing the industry
to reevaluate Alaska commitments. Investments are occurring
and the element of progressivity has already been
introduced. He emphasized that changes slow the process
down.
Representative Crawford pointed out that his question was
answered by ConocoPhillips, the company that has done the
most investment. He wanted to see more investment in Alaska
from the other companies. Ms. Fitzpatrick argued that BP has
increased investment; depending on what is passed, they will
continue consideration. She suggested extending rather than
curtailing TIE credits.
10:54:37 AM
Mr. Haymes added that Exxon Mobil has invested over $20
billion dollars in Alaska, with 900 new wells in the last
seven years. He stated that they invest on a par with BP and
ConocoPhillips. Exxon Mobile believes that the development
of resources is global and competitive world wide. There is
significant resource potential, but Alaska has unique
challenges. He stressed that Exxon Mobile wants more
competition on the North Slope; the more development, the
lower the cost for infrastructure and operation, and the
more oil that can be produced for everyone. He urged
encouragement of independent companies.
Mr. Taylor agreed that investment is happening. Mobilizing
takes time and the market is expanding. He believed that
letting the system work would bring new players, ranging
from smaller consortiums like Brooks Range Petroleum through
major international oil and gas companies like Anadarko. He
spoke against raising taxes because they create instability.
Representative Crawford understood that to mean that taxes
should not be lowered. Ms. Fitzpatrick responded that
accelerating the pace was not on the table.
11:00:06 AM
Representative Gara asked about the 350 percent tax increase
mentioned earlier by Exxon Mobile. He was concerned with
companies misleading the public to undermine the efforts of
the legislature. Public relations information put out by
Exxon Mobile has suggested that ACES would triple industry's
taxes. He requested accurate information. According to his
calculations, the total tax burden has increased less than
30 percent under ELF [Economic Limit Factor], prior to PPT.
He asked for an estimation of total tax burden in the
current year compared to that under the ELF system.
Mr. Haymes responded that the comment was in regard to
production tax. Using the DOR model, at the current oil
price, under the ELF system the tax burden for the industry
would have been $1.1 billion. Under the ACES proposal, that
number would be $4.9 billion, a 350 percent increase.
Comparing the $1.1 billion under ELF at today's prices with
the HRC version, it is currently at $6.4 billion, a 470
percent increase.
Representative Gara reiterated that the total tax burden
includes royalties, corporate income tax, and property tax.
There have been ads supported by Exxon Mobile saying that
their tax burden has already tripled. He asked if comparing
the total tax burden under the ELF and last year under PPT
would translate closer to 25 percent. Mr. Haymes commented
that present testimony specifically referenced the
production tax. The numbers are accurate with respect to the
ELF system of 2005. When additional taxes such as federal
and state corporate taxes, property taxes, and the
royalties, the amount of tax increases significantly.
Representative Gara requested totals for tax payments under
the current system compared to payments under the ELF. He
stressed that the taxes have not tripled as media ads are
claiming. Mr. Haymes agreed to get he totals. He asked to
discuss total government take as well.
Mr. Hajny commented that the impact to BP was an increase
from approximately $180 million under ELF to over $520
million under PPT for the last three quarters of 2006,
nearly a tripling of taxes during that period. He did not
know the impact of the state income tax; the property tax
has also increased from roughly $3.3 billion to $4.5
billion. The $1.2 billion dollar increase was at a mill rate
of two percent.
Representative Gara pointed out that production tax
increased under the ELF because at almost every field in the
state they were zero. He referred to annual reports by BP
and ConocoPhillips from the previous year. Profit margins
were reported of 36 and 37 percent respectively, roughly
over $2 billion in profit from Alaska on roughly $6 billion
of income. He asked if Exxon profits margins were higher
than those reported by BP. Mr. Haymes stated that they are
not required under the Securities and Exchange Commission
(SEC) to disclose profits. They are not attempting to hide
the information; they do not report it that way. Current
production is 150,000 barrels per day. He understood the
desire to see the information to help with projections for
tax and revenues; Exxon Mobile is willing to work with DOR
to provide it.
Representative Gara stressed that not having the numbers
makes it difficult for the state to adopt a fair profit tax.
The state's consultants say the internal rate of return is
an important number as well as the profit margin number. He
requested information from the three companies for the past
fiscal year.
Mr. Haymes responded that internal rate of return is only
one measure used to look at profitability of investments.
There are other factors considered. The internal rate of
return is confidential, competitive, and proprietary
information. However, the annual report does indicate those
numbers on a world wide basis.
Ms. Fitzpatrick explained that internal rate of return is an
investment metric over a long period in the life of a
project. On an annual basis it would be return on capital
employed. She offered to calculate that based on public
information.
Mr. Mitchell added that the calculation would be difficult,
although the financial results are disclosed in the SEC
filings by region, including Alaska. There is a variety of
information, including historic invested capital.
Mr. Taylor stated that the planning horizon is an ongoing
process in a company. ConocoPhillips is constantly looking
for investment opportunities that will benefit shareholders
and other recipients of benefits, including state and local
governments. In the past three to five years there has not
been an $80-90 price horizon. The market is heavily
influenced by geo-political factors. There are profits
associated with the actual profits. When looking at Alaska's
potential, the question is how Alaska competes. The largest
resource on the North Slope continues to be in more
challenging projects. That situation is different than in
the past, but price encourages taking more risk and higher
costs from capital exposure and operating costs. The
investments of the future are different than those of the
past. Considering the changes, uncertainty causes investors
to pause. He concluded that the internal rate of return
ranges from the very high numbers suggested in previous
simulations to very challenged numbers.
11:15:17 AM
Representative Gara commented that keeping tax rates down
does not lead to more investment, which is why investment
credits and bigger deductions are being considered. Under
the ELF system, a virtually zero percent tax rate did not
increase investment. Keeping the tax rate down has not kept
the money in Alaska. Giving money back seems to the only way
to encourage industry to invest in Alaska. He asked why so
much money left the state under ELF and PPT, and if the
companies would be more likely to invest with incentives
like the credit and deduction systems.
Mr. Taylor reiterated that a change had already occurred in
terms of raising taxes and progressivity with PPT last year.
He emphasized that stability is the best thing to continue
development. He did not think raising taxes would encourage
investment. Incentives do help, but the legislation is
getting more confusing, making it difficult for investors
and slowing investment down.
Ms. Fitzpatrick agreed.
Mr. Haymes echoed Mr. Taylor's comments. He thought the net
structure is a step in the right direction. The issue is
complex; Alaska is a high cost environment with unique
challenges. There is a lot of land access not available for
exploration activities. Industry exists to find, develop,
produce, and market energy and will continue to do that as
long as it is attractive and makes sense.
Mr. Mitchell added that investment does not happen
overnight. A change in tax structure does not bring sudden
investment. It has been only a year since PPT has been
implemented. More changes create uncertainty.
11:21:11 AM
Representative Kelly strongly encouraged industry
profitability but wanted to guarantee that same
profitability for Alaska. He was convinced that what is
being offered is a robust and profitable system. He believed
the changes being worked through would guarantee
profitability for both the state and the industry.
11:24:04 AM
Representative Hawker stated concerns about the credibility
of the process, especially a statement regarding
significantly inflated cost claims with the intent to
deceive DOR. He asked if any of the industry present had
intentionally inflated their numbers. He asked for
assurances that they would not or could not inflate numbers
because of internal accounting controls. He referred to the
Sarbanes-Oxley Act, which establishes consequences for
misleading financial reporting.
11:28:07 AM
Mr. Seckers declared that Exxon Mobil has strict internal
policies prohibiting falsifying records or returns; the
consequence is immediate termination and severe penalties.
The joint interest billings are audited independently and
scrutinized in accordance with GAP. Tax returns are filed in
accordance with the law.
Mr. Hajny echoed Mr. Seckers. He stated definitively that
within Exxon Mobile there has been no intent to inflate or
file erroneous tax returns. When PPT was put in place, it
was highly scrutinized because it was a new tax. Policy was
created to make the tax work. He noted that not all
regulations were currently out.
Ms. Fitzpatrick explained that Sarbanes-Oxley requires that
companies document internal controls to ensure there is
appropriate financial reporting and that all the risks are
identified and key controls in place. There must be both
monitoring and verification of those processes and controls.
There is an internal group in BP as well as an external
group that confirm that activities and controls are in place
and operating as they should. There are also third-party
external auditors.
Mr. Mitchell explained that ConocoPhillips has clearly
defined Sarbanes-Oxley procedures and controls that are
audited annually in addition to the standard external audit.
In addition, every employee is required to adhere to an
internal code of ethics and make an annual attestation that
they have complied. This covers a broad range of aspects of
the law. By the time the SEC filings are made, they are
signed off on at a corporate level by a comptroller and a
chief financial officer, with criminal penalties for
fraudulent statements.
Representative Hawker maintained that there is a legal as
well as administrative control system to assure results.
11:35:05 AM
Representative Gara wanted assurances that tax returns would
be as creditable as possible. He questioned if there were
penalties under Sarbanes-Oxley for state fillings or just
SEC filings. Ms. Fitzpatrick responded that Sarbanes-Oxley
governs a company's financial reporting under SEC
guidelines. With respect to PPT filings, the same
information goes into external reporting; a subset goes into
the PPT filing. The actual costs are claimed with good
faith. There are situations where interpretation of a
guideline is subject to debate. If they have clarity about
what they are filing against, BP's objective is to file a
100 percent compliant tax return for any of the taxes.
Representative Gara asked if there were Sarbanes-Oxley
penalties for overstating deductions or credits under the
PPT return in SEC filings. Ms. Fitzpatrick explained that
Sarbanes-Oxley does not apply to state tax filings. She
thought there were other provisions that covered the filing
of state tax returns.
Mr. Seckers explained the process in more detail. When BP,
for example, sends Exxon Mobile a joint interest bill, the
comptroller along with the engineers go over it repeatedly.
It is then reviewed by the law department to make sure it
complies with the joint interest billings that are allowed
under the unit operating agreements. Then the tax
accountants look at it before sending it to the tax lawyers
who make sure it complies with the PPT tax law. The return
is prepared. The return is reviewed by the superiors of all
the auditors, tax accountants, and lawyers to make certain
it is correct. Then the return is signed and sent out. Every
year Exxon Mobile employees have to sign an ethics agreement
to make sure they are complying. In addition, the state of
Alaska has other penalties, interests, and fines in place
for fraudulent and late returns and so on. Federal laws also
apply.
11:39:28 AM
Representative Gara reiterated concerns that the PPT
projections understated costs and overstated revenue. He
felt that the industry should have advised the legislature
if they felt costs were understated during the PPT debate.
Ms. Fitzpatrick believed her counterparts had repeatedly
attempted to discuss the costs. Current numbers for both
capital expenses and costs are blended for the whole of the
North Slope. She added that BP numbers are higher than the
numbers listed for 2007, and will be higher still in 2008.
Mr. Mitchell added that ConocoPhillips testified during PPT
hearings regarding the trend toward an increase in costs.
11:42:38 AM
Co-Chair Chenault invited closing statements from panel
members.
Mr. Taylor of ConocoPhillips agreed that profitability is
not a bad thing and added that a healthy investment
environment should benefit the state as well. Changes in the
tax structure cause disruption. He stressed that whether
taxation and progressivity are applied to the net or to the
gross is an important distinction. Net taxation would create
a healthy investment environment; taxation to the gross
would be very challenging, especially to higher cost
potential development.
Ms. Fitzpatrick asserted that BP did not think the original
bill at the start of the special session improved new
investment or reinvestment. The HRES version is
significantly worse and would require them to revisit their
business plans. She emphasized that the quality of the oil
as it gets thicker affects costs. At one point there was a
$14 difference between ANS crude and heavy crude. That price
difference may be larger still, and this is one of the many
challenges that face the company as they try and come up
with an economically viable project for a challenged
product.
11:46:10 AM
Mr. Haymes of Exxon Mobile stressed that in 10 years 75
percent of oil production will come from new oil that
conservatively needs $30-40 billion in new investment. The
resource potential for Alaska is significant. Policies
established today will impact the attractiveness of future
projects. The proposed CS of HB 2001 adds layers of
complexity, increased taxes, and other measures that have
been discussed. He pointed to detailed write-ups on those
issues in submitted testimony. For the production tax, ACES
proposes a 350 percent increase since 2005; the current bill
would mean an increase of over 400 percent.
11:47:57 AM
Representative Gara pointed out that the lower the tax rate,
the more unstable it will be. He spoke in support of
proposals by Representative Kelly.
RECESS: 11:49:40 AM
RECONVENED: 12:47:24 PM
Co-Chair Chenault introduced the second panel of presenters.
ANADARKO
MARK HANLEY, MANAGER, PUBLIC AFFAIRS, ANADARKO PETROLEUM
CORPORATION-ALASKA spoke in support of net taxation.
Anadarko feels a flat gross system over-taxes some fields
and under-taxes others. Costs are not included. The new
investment needed, whether for exploration, infill, or heavy
oil, tends to be more costly than for existing fields. The
net system attempts to incorporate costs.
Mr. Hanley pointed out that the net system, however, does
not necessarily take risk into account. An infill well
cannot be profitable in the current environment. To
establish a tax rate on that would cause over taxation.
Heavy oil does not have the same economics. He acknowledged
that credits help. Anadarko supported PPT as an improvement
in exploration economics, but preferred the progressivity be
on the net.
Mr. Hanley warned that the 0.2 escalator on the gross is
more like a 0.25 on the net if the tax rate is 25 percent,
and represents a significant increase. He described the
change from an annual basis to monthly as an added
difficulty.
Mr. Hanley supported the net operating loss carried forward
as an equity issue that was adequately addressed in the HRES
version. Anadarko also supports an in-state gas use
provision. Generally, they support the changes made to the
exploration incentive credits, although they are retroactive
to January 1, 2007, which is not the benefit it seems. The
new program under the EIC requires permission from the
commissioner before drilling a well to get those credits;
wells drilled the previous year could not technically get
permission.
Mr. Hanley spoke to costs. He stated frustration with debate
during PPT that companies were over-estimating costs in
order to make returns look lower. He disputed the idea that
increased taxes make it more attractive for companies to
invest.
Mr. Hanley maintained that legitimate costs should be
allowed to be deducted. He questioned Section 53, which he
says modifies Section 52 due to the potential of court
proceedings. He felt the bill went too far.
1:02:34 PM
PIONEER NATURAL RESOURCES
PAT FOLEY, MANAGER, LANDS AND EXTERNAL AFFAIRS, PIONEER
NATURAL RESOURCES ALASKA, presented a brief PowerPoint
presentation ("Pioneer's View of CS HB 2001 (RES)," Copy on
File). He noted the difficulty of the issues. He focused on
the unique aspects of Oooguruk and its net profit share
leases, consisting of a government take of 83 percent. He
asked that the net profit share payment be creditable
against the progressive element of PPT.
Mr. Foley explained that Pioneer entered Alaska in 2002 to
drill exploration wells at Oooguruk that led to a successful
development. Pioneer also owns an asset in Cook Inlet called
Cosmopolitan where they hope to have a development project.
They have 1.5 million acres on the North Slope, mostly on
the National Petroleum Reserve Alaska (NPRA). Their
exploration partners are ConocoPhillips and Anadarko.
Pioneer has drilled 11 exploration wells and has local staff
of 35. Oooguruk, their cornerstone project, is an off-shore
development that is about 70-90 million barrels in size.
Production should start in 2008 and at peak should produce
between 15,000 to 20,000 barrels per day for a period of 25
years.
1:05:59 PM
Mr. Foley explained that Pioneer is the first independent
North Slope operator. Production will go through a line and
connect to the Kuparuk River unit, which will process their
crude. He said many potential investors are assessing the
success of this project.
Mr. Foley spoke to the condition of local industry. Pioneer
thinks there is limited activity for new players. The North
Slope has been dominated by the major producers. He
questioned if Alaska was attractive to independents for
investment. He provided a list of the companies that drill
the most wells in the lower 48. Pioneer and Anadarko are the
only ones on that list that are in Alaska. He thought Alaska
should decide if their policies are attractive to
independent investors.
Mr. Foley explained that in the Lower 48, there is a shorter
cycle time and profits are greater. One of the reasons is no
progressivity, so companies can capture the price upside.
1:11:13 PM
Mr. Foley stressed that progressivity is an attempt to
capture the windfall of upside prices. He maintained that
for leases with a net profit share payment, the upside is
already being captured. At Oooguruk, leases have a 30
percent net profit payment. They pay a royalty, a net
profit, PPT, state, and federal taxes. The company take is
17 percent. The government take on Oooguruk is 83 percent
based on total life cycle costs and a $70 deck, and it is
all discounted. There is almost nothing that can reduce the
government take at Oooguruk to less than 80 percent.
Mr. Foley explained a pie chart on Slide 6 that details the
numbers:
· 18 percent to Alaska royalty;
· 8 percent to property tax;
· 18 percent to net profits;
· 9 percent to progressivity;
· 4 percent represents the base tax; and
· 15 percent to PPT.
Mr. Foley asked for a change in the bill that would allow a
net profit payment directly creditable against
progressivity.
1:15:34 PM
Mr. Foley displayed a map with the leases and numbers from
the Division of Oil and Gas website with 2006 net profit
share payments totaling $87 million. The biggest payee is
BP.
Mr. Foley discussed concerns with changes to the EIC
program. He maintained that the proposed program would be
cumbersome and reduce incentives and concluded that a
program without certainty discourages investment and
exploration drilling. He pointed out that the bill requires
geologic logs and "all derivative work products." He
contended the impossibility of compliance.
1:19:53 PM
Mr. Foley concluded that Pioneer has been an aggressive
investor in Alaska and hopes to continue to pursue their
goals. They worry about the balance tipping. Currently, the
vast majority of Pioneer's investment opportunities are not
burdened by progressivity. Their price upside is retained.
He emphasized that at higher prices, Alaska opportunities
are less competitive. Under progressivity, if the piece is
taken off the upside in Alaska but not in Texas for a
comparable project, the investment will be diverted to
Texas. He reiterated their request to have the net profit
share lease be credited against the progressive element of
the production tax. Pioneer has earned all of the allotted
TIE credits. The money was spent on wells, which resulted in
Oooguruk. Pioneer would lose $33 million with a cutoff date.
Mr. Foley asked members to consider if the bill motivates
the desired behavior.
1:24:18 PM
CHEVRON
JOHN ZAGER, GENERAL MANAGER, CHEVRON-ALASKA, provided
members with a PowerPoint presentation ("Testimony on
SB2001/HB2001," Copy on File). Chevron is increasing
investment in Cook Inlet and North Slope exploration under
PPT. He stressed that they have over 500 employees and
contractors, which will increase if their operations
continue.
1:26:53 PM
Mr. Zager pointed out that taxing the upside will deter
investment. Slide 3 depicts possible outcomes for well
success and failure. He demonstrated the concern that the
tax is being added after companies have taken a carefully
calculated risk and succeeded. Even the most positive
outcome is significantly impacted. A change to the tax
changes the risk and will influence decisions to drill.
1:30:51 PM
Mr. Zager asserted that the legislation has moved in only
one direction. He thought the base tax rate will likely
increase. Alaska has a resource that it is trying to sell or
lease. The customer is the oil and gas industry. The price
is the government take, which must be compared on a
worldwide basis. He gave examples of sales and asserted that
industry is sending the message that the product and price
in Alaska is not competing. He asked for consideration of
that while determining the base tax and progressivity.
Mr. Zager stated concerns about TIE credits. He clarified
the usage of the terms income, earnings, and profit. Profit
is related to PPT. Both earnings and income have
depreciation included in the calculation. Early on it was
decided that depreciation would not be allowed in the
calculation under PPT. This means that credit could not be
gotten for money invested in the previous year, and becomes
a tax on cash flow. The decision was made to include the TIE
credits as a proxy for that. The new bill would reduce or
eliminate TIE credits.
Mr. Zager spoke against the retroactive effective date. He
did not think the impacts from the disallowance of costs are
known. It would either disallow very important costs-in
effect, a tax increase-or create incentive to be
inefficient. The language in SB80 and ACES had problems.
Disallowing unanticipated downtime is problematic. Things
such as compressors fail in the normal course of a project.
He cautioned that the language should be kept simple.
1:39:11 PM
Mr. Zager cautioned that provisions weakening tax payer
confidentiality are problematic. He discussed the multiple
layers of penalties for mispayment or errant reporting. He
questioned the reasonableness of the legislation.
1:41:25 PM
Mr. Zager addressed committee member concerns about industry
misrepresentation of costs. Slide 5 includes excerpts from
2006 testimony to the House Finance Committee regarding
accelerating costs. He asserted that industry had been very
clear about rising costs.
Mr. Zager closed with questions for the members (Slide 6):
· To what degree are you willing to risk future oil and
gas investments in Alaska? He differentiated between
PPT and ACES. He thought PPT put incentives in place to
encourage investment. He did not think the new
legislation would; the discussion was the degree to
which it would hurt investment.
· To what degree are you willing to risk the Alaskan
economy?
· Is Alaska "open for business"?
· Will Alaska have more or less opportunity for our
children after this bill passes?
1:45:54 PM
ALASKA VENTURE CAPITAL GROUP/BROOKS RANGE PETROLEUM
EDGER DUNNE, MANAGER, ALASKA VENTURE CAPITAL GROUP
(AVCG)/BROOKS RANGE PETROLEUM, PRESIDENT DUNNE EQUITIES,
(testified via teleconference), read testimony by Ken
Thompson, AVCG Managing Director (taken from "Comments on
ACES Petroleum Tax Proposal, October 2007," Copy on File):
Alaska Venture Capital Group is a privately held
member company with a technical and operational
services' subsidiary company called Brooks Range
Petroleum, with offices and staff in Anchorage. In
Alaska and on the North Slope, we operate under
the name Brooks Range Petroleum. AVCG has lease
holdings and explores currently only in Alaska,
nowhere else. AVCG/Brooks Range likes to think of
our company as "Alaska's Independent Oil and Gas
Company." We have been very active in the past
seven North Slope area wide lease sales and active
in acquiring acreage held by other companies where
we see potential. We and our partners currently
hold over 300,000 acres of exploration leases in
five exploration prospect areas on the Slope. Our
exploration strategy is to explore in the central
part of the North Slope for fields in the 10-100
million barrels range.
This past winter for the first time, our
operations subsidiary, Brooks Range Petroleum
operated the drilling of two exploration wells and
ran a 130-square mile 3D survey over our acreage
and surrounding area in the Gwydyr Bay area on the
North Slope. This past drilling season, our group
invested over $44 million on land, seismic and
drilling activities. This winter our group will be
among the most active of explorers as we plan to
shoot over 200 square miles of new seismic data on
the extreme western and eastern sides of the
Central North Slope and to drill up to four
exploration wells. Our group will spend over $40
million on seismic and exploratory drilling in
winter 2008. At the end of next season, AVCG since
1999 and our partners since last year will have
jointly invested over $100 million in Alaska even
though none in our group have generated any
revenues yet from Alaska oil, so we sincerely
appreciate being listened to. We think in the long
run we can bring substantial, incremental value to
the State of Alaska.
Our company prefers that the PPT be allowed to run
its course in the next few years, and that ACES
not be approved with its current provisions. Here
are some suggestions of things not to change in
the ACES proposal:
1) Keep the exploration and development investment
tax credits. For a small explorer startup company
like AVCG, the exploration economics with the
exploration tax credits ranging from 20-40 percent
as provided by PPT and with ACES are more
favorable with an improvement in the investor's
rate of return as compared with Alaska's old
severance tax system.
2) Keep the "standard tax deduction/exemption" for
smaller companies. The "Small Producer Tax Credit"
that exempts up to the first $12 million in
production taxes for smaller companies can allow
us to return a larger share of our annual cash
flow for exploration and investment while we build
the company to a critical mass of reserves and
production necessary to expand staffing and have a
routine level of major capital spending each year.
3) Keep the new ACES tax credit allowance for
qualified delineation wells. A new proposal in the
ACES bill that was not in the PPT law is the
possible tax credit allowance for the investment
in up to two delineation wells following a
discovery. This would be very helpful to small
explorers as well as for large companies on the
North Slope where often one well is not enough to
determine if field size is large enough to warrant
development.
4) Keep the revised progressivity tax rate at 0.2
percent per dollar increase in oil price.
5) Do establish the Oil and Gas Tax Credit Fund
for the purposes of purchasing certain tax credits
from explorers and producers. This is extremely
important for AVCG to then be able to plow those
credits back into seismic and exploration on the
North Slope.
Four things to change in ACES:
1) Change the recovery of tax credits from two
years as proposed in ACES back to the recovery of
credits in one year currently provided for in the
PPT law. For a small company like ours, this will
definitely affect our capital spending in a given
winter as we plow all the credit refunds back into
seismic or exploration drilling. We hope full
credit can be applied for and refunded in a given
year.
2) Change the base tax rate in ACES from 25
percent back to the PPT tax rate of 22.5 percent,
and re-review again in 2011 as allowed for in
current law. In other producing states that
compete for investment by our AVCG investors, the
state and federal combined government takes in
2006 averaged 45-57 percent. This was from the
Gulf of Mexico, Colorado, Wyoming, Kansas, Texas,
New Mexico, Oklahoma, California, and Louisiana.
Those figures include a 12.5 percent royalty.
These states do not have the added progressivity
surcharge tax which further separates Alaska in
government take from these competing states.
Alaska should have a government take of 55 percent
if we were to maintain long-term competitiveness
with these other states for investment dollars.
Some of these states do not have the prospectivity
of Alaska, so Alaska could command some premium in
take, but not as high as being proposed in ACES.
3) Change the trigger price to $40 per barrel net
and not $30 per barrel. If the government take is
to be the fair and equitable 60 percent and not
the unfair 68 percent, the trigger price should
stay the same as in the PPT law, i.e. $40 per
barrel net. If Alaska is to share in high prices
with the progressivity surcharge tax, then Alaska
should share in the pain of low prices.
4) Consider some type of TIE credit. This
provision allowed for in PPT was repealed in ACES.
While this provision does not greatly benefit our
company because we did not have large seismic or
exploration drilling costs between March 31, 2001,
and April 1, 2006, it is important to other major
investors in Alaska. As an example, the largest
explorer and developer in Alaska, ConocoPhillips,
now with the ARCO heritage assets was hardest hit
in tax exposure with the change from the old
severance tax law to the PPT and now to ACES.
Allowing a good steward who is the largest
explorer in Alaska some transition allowance to
ease the pain of greatly increased taxes is the
right thing to do and can only build better, more
trusting relationships.
In conclusion, we've tried to share the
perspective of an independent exploration company
that only invests in Alaska. My ultimate wish
would be to leave PPT alone and re-review it under
the law as planned in 2011 or perhaps even in
2010. I urge you to at least consider the five
things our company would not change in this bill
and the four things we would change.
1:57:39 PM
ALASKA OIL AND GAS ASSOCIATION
MARILYN CROCKETT, EXECUTIVE DIRECTOR, ALASKA OIL AND GAS
ASSOCIATION (AOGA), read from testimony ("Testimony of AOGA
to the House Finance Committee Regarding CSHB 2001 (RES),
November 8, 2007," Copy on File). She described AOGA as a
trade association for the oil and gas industry in Alaska
with 17 member companies, including the Agrium plant,
Alyeska Pipeline Service Company, and three in-state
refineries. These companies account for the majority of oil
and gas exploration, development, production,
transportation, refining, and marketing activities in the
state.
Ms. Crockett explained that when AOGA voices a position,
regulators and legislators can be assured that it is the
position of the overwhelming majority of Alaska's oil and
gas industry because AOGA provides a forum for its members
to reach agreement about industry positions. On tax issues,
the AOGA tax committee requires complete consensus.
Therefore, there is no dissent among AOGA membership
regarding this testimony.
2:00:08 PM
Ms. Crocket pointed out that AOGA has focused their comments
on two key areas: first, declining production levels and the
importance of investment to address that; and second,
through the tax committee, which has many member companies
and extensive experience, AOGA wants to respond to technical
issues raised by the new legislation. She added that the tax
committee has not had the time to generate qualitative
analysis on the proposed options and will submit that later.
Ms. Crockett commented on accusations that industry intends
to take advantage of the state and cheat on their taxes,
even to the point of deducting costs such as lobbying
expenses. She pointed out that this would be against the law
and is an insult to the employees of the companies.
Ms. Crockett described the rigorous auditing provisions
within the industry. Individuals would not cheat on their
taxes if they knew there was a 100 percent chance of being
audited, as oil companies are. Every return filed by the oil
industry is audited by the state by high qualified auditors.
2:03:04 PM
Ms. Crockett stated concerns about the Gaffney Kline
economic model. It was designed to focus on a single
investment decision in legacy fields and does not take into
account investments in heavy oil and the investment
challenges of exploration activity, and other things. She
cautioned against using only that model and its results.
Ms. Crockett addressed declining production levels. Nearly
90 percent of the state's discretionary money comes from the
oil and gas industry, making production levels the
cornerstone of Alaska's economic future. She referred to a
chart on page four of her written testimony depicting
declining North Slop gas production. North Slope production
has declined at a rate of 6 percent between 1997 and 2007;
Cook Inlet has declined by 8 percent during the same time.
She maintained the 6 percent rate is the result of continued
investment by the companies, and would have been 15 percent
without these investments.
Ms. Crockett spoke to the mechanical capacity of TAPS, which
is 200,000 to 300,000 barrels per day. Different decline
rates are outlined in the charts on page 5. The chart of the
left shows the time to decline from 740,000 barrels per day
in FY 2007 to a 200,000-barrel-per-day threshold, the one on
the right shows the time to get to 300,000 barrels per day.
At a 6 percent rate of decline the 200,000-barrel threshold
is hit in 21 years, but at a 3 percent decline it would take
43. If the threshold is 300,000 barrels per day, it would be
hit after 15 years at 6 percent and 30 years at 3 percent.
Ms. Crockett stated that opportunities exist that should
allow the rate of decline to be slowed to below 6 percent.
These opportunities are in oil and gas exploration, in the
development of the huge resources of heavy and viscous oil
that are already known to exist, and in the renewal and
continued development of existing fields. She referred to
previous testimony explaining different kinds of investments
and production levels needed if Alaska is to meet the
challenge of production decline.
Ms. Crockett emphasized that heavy and viscous oil lie
within the areas of the so-called "legacy fields," as does
the preponderance of the remaining opportunities for
obtaining more "conventional" oil out of currently producing
fields. The renewal of the existing fields will become
increasingly important, as the existing production
facilities need to be adapted, retrofitted, or even replaced
in order to be fit for service for the coming decades.
Ms. Crocket added that infill drilling to drain the spaces
between the existing wells, or develop new oil, offers the
best promise of slowing decline in the short term. The
pattern and timing of the cash flows are very different
between infill drilling and renewal of major production
facilities on the surface. Even within a legacy field,
without considering its resource of heavy and viscous oil,
there is significant variation among the investments to be
made, the economics for those investments, and the
incentives. She felt it would be a serious mistake to treat
the legacy fields as economic monoliths, impervious to how
they are taxed and unaffected by the incentives that may be
granted or withheld.
Ms. Crockett spoke to stability. In 2005, the industry was
faced with a $120 million tax increase. She pointed out that
implementation of PPT increased the tax by $800 million
during the first nine months of 2006. The HRES version
proposes to increase the production tax again to $1.5
billion, over the PPT currently in place.
Ms. Crockett maintained that there are serious
misconceptions about the models that are being used to
demonstrate potential impacts of a tax increase on
investment decisions. She stressed that there has been a
serious underestimating of the effects on future investment,
especially regarding exploration, heavy and viscous oil
development, and renewal of conventional fields. The laws of
economics stipulate that there will be an adverse effect on
investment decisions if the House CS becomes law. She
asserted that the future of Alaska was at stake and urged
the legislature to pull back.
2:11:56 PM
Co-Chair Chenault referenced the Gaffney Kline economic
model and noted that Mr. Rich would be provided an
opportunity to testify at a later date.
RECESSED: 2:13:19 PM
RECONVENED: 2:16:29 PM
Representative Hawker questioned the rules related to net
profit share leases (NPSL). Mr. Foley explained that NPSL
are 30 percent of net profits paid directly to the state in
addition to 12.5 royalties. The cost of doing business is
royalty plus net profit share, deductable against PPT and
state income tax. There is a difference between a deduction
and a credit.
Representative Hawker observed that the standard royalty
payment is 12.5 percent. He pointed out that Pioneer has
filed for and secured royalty relief, so it is not 12.5
percent. Mr. Foley agreed and explained that 80 percent of
the Oooguruk resource falls on four NPSL with a one-eighth
royalty and a 30 percent net profit. He added that 20
percent of the resource falls on other leases with a one-
sixth royalty. Royalty reduction was received and takes all
of the royalties to a floor of 5 percent until payout, which
is at the same time that the net share profit account pays
out. The royalties begin to increase with the NPSL payments
over a level three-year period back to current rates. At
payout, the royalty jumps from 5 percent to 6.875 percent.
There would be additional increases of 1.875 percent in each
of the next two years, which takes them to their full
royalty amount.
Representative Hawker understood that the royalty relief
provisions phase out over time. Mr. Foley stated it was
totally dependant upon price. At $70 dollars, the effective
royalty rate payments, discounted at the weighted average,
is a little more than 8 percent plus 30 percent net profit.
Without royalty relief the effective rate would be closer to
13.5 percent.
2:22:55 PM
Representative Hawker summarized that NPSL are uncommon in
Alaska at this time. Mr. Foley agreed that they are fairly
uncommon. In the 1980s, the state started issuing leases
with a fixed net profit component, such as the North Star
leases. The North Star leases were subsequently amended and
a sliding scale was applied. Pioneer is unique in that more
than 80 percent of their resource falls on net profit share
leases. He named other units that had NPSL.
Representative Hawker wondered at the uniqueness of the
circumstance and questioned if NPSL should be considered for
Point Thomas in the future. Mr. Foley responded that the
issue is appropriate for all NPSL. The progressivity is an
attempt to capture the price upside. A large portion of the
upside would already be captured by NPSL, greater than
through progressivity.
Representative Hawker acknowledged the merit of the debate,
but encouraged members to look for parity. He summarized
that the excess of the aggregate payment over 12.5 percent
would be applied to relief, but would not be applied against
base state taxes, just progressivity. Mr. Foley agreed and
hoped it would be applied against progressivity. He
emphasized the importance of having a relatively level
playing field. He referred to Oooguruk with a government
take of 83 percent, even with the benefit of royalty
reduction. Without royalty reduction, the number would be
even more favorable to the state.
2:28:12 PM
Representative Hawker argued that the issue of equity was
merited.
Representative Gara claimed that DNR would have a different
perspective. He observed that royalty relief was granted to
Pioneer under the prior administration just before
implementation of PPT. According to DNR, the economics of
Oooguruk after royalty relief was better under PPT than
under ELF. The net present value increased because they
could write off their deductions and credits right away,
which they could not do under the old ELF system. Department
staff recommended a less generous royalty relief than the
prior commissioner had granted. He concluded that the dollar
value of Oooguruk doubled in terms of net present value from
ELF and royalty relief to PPT.
Mr. Foley stressed that their request for royalty relief was
made through an open and transparent process, but emphasized
that the pricing environment is different today. Actual
costs were higher. Determinations are made on estimates, but
oil has not been produced yet. When the royalty reduction
was granted, the project showed a modest rate of return. He
maintained that the project would not have happened without
royalty reduction. The type of return their project delivers
is dramatically less than some of the numbers suggested
would apply for an infill well in the North Slope field.
2:32:45 PM
Representative Gara assumed that Pioneer did everything
properly. He observed that progressivity does not apply
until there is $30 in profit above costs. Mr. Foley stated
that originally under PPT, progressivity was designed to
counteract the regressive nature of royalty. Take would stay
relatively constant as price increased, but the take goes up
as the progressivity amount is increased. He felt there was
a shift between PPT and the current conversation.
Representative Gara observed that Oooguruk would be more
profitable now than under ELF at lower prices. Mr. Foley
acknowledged the higher prices, but questioned if they would
remain over time.
2:34:52 PM
Representative Kelly asked about the uplift credit, which
was intended to help launch the project. He proposed that
progressivity is what a company should be paying.
Co-Chair Chenault suggested that members interested in the
subject get together with DNR and Mr. Foley to address the
issue.
2:37:11 PM
Representative Foster referred to an interaction he had with
Chevron in rural Alaska in the late 1970s that illustrated
that the price would never go down.
Co-Chair Meyer pointed out that Chevron, while sitting with
the small companies, is one of the largest. Mr. Zager
explained that Chevron is the second largest U.S.-based
company with a market cap of $200 billion and interests
worldwide. Co-Chair Meyer questioned how Alaska looks in
comparison to other places in terms of investments. Mr.
Zager observed that U.S. production is about 320,000 barrels
per day and noted that Chevron has major operations
throughout the world. He detailed some of their operations.
He reports to [Chevron's] North America organization. Most
of the capital competition is with other areas in the Lower
48. However, the North Slope exploration program was
evaluated against other projects around the world.
Co-Chair Meyer asked about investments in Africa versus
Alaska. He questioned Alaska's competitiveness. Mr. Zager
answered that Alaska is having difficult competing for
capital. He pointed to lease sales, and observed that people
are not coming to Alaska. Most of those in the lease sale
were already in Alaska. There are large resources in the
other international countries such as Angola that have large
government takes. He acknowledged security risks, but
stressed that they are minimized by being offshore. Security
risks are not huge in terms of financial risk. Government
takes cannot be viewed independently of the resource. He
suggested that there would be aggressive bidding on ANWR
because of the perception that it is a world class field.
Offshore terms in the gulf are also attractive.
2:46:06 PM
Representative Gara observed that Gaffney Kline's model is
for a five-year drilling program. This would explain the
results Ms. Crockett obtained when she put zero in as a
value.
Representative Crawford asked if who controls the lease
field would affect the lease sales. He observed that control
of the deep Gulf is not yet established, which would explain
the interest. Mr. Zager agreed that there is competition for
infrastructure in the deep Gulf. New fields in the North
Slope are assumed to be small enough to be dependent on the
current infrastructure. Producers would not be concerned
about going through Kuparuk or Prudhoe Bay if they thought
there was a billion barrel field.
Representative Crawford acknowledged that billion barrel
fields are common, but felt 50 million barrel fields could
pay if there were not barriers to access. Mr. Zager stressed
the difficulty of facility sharing agreements, which require
complicated negotiations. He maintained that being an owner
does not guarantee access.
2:53:06 PM
Representative Kelly asked if the access issue was in the
realm of reasonable. Mr. Foley observed that there have been
lengthy negotiations with Kuparuk related to access. He was
pleased with their progress and anticipated positive
results. He did not feel the current owners were a barrier
to entry, although there were challenges to the process. The
agreement is complex and important, and takes time.
2:55:00 PM
Representative Kelly referred to the House version of
progressivity with a net trigger and gross application that
result in a higher effective rate. Something that appears to
be 0.2 is actually 0.25. He questioned if Pioneer would
prefer removal of the floor, or to pick up two tenths on
progressivity, assuming the gross would be adjusted to
reflect two tenths.
Mr. Hanley responded that the lower progressivity would be
better for Anadarko, although he had not modeled the
proposition because the floor did not affect them. Mr. Foley
noted that Pioneer was also not an owner and would not be
affected by the floor. He would trade a floor for
progressivity. Pioneer is affected by progressivity, but he
did not think it was a fair exchange. Mr. Zager noted that
they are small owners in Prudhoe Bay. He thought that
Chevron would oppose the floor based on a structural issue.
He suggested that there would be a relatively small
financial impact. He was opposed to the floor on principle.
He observed that PPT is a statewide tax that allows credits
to be moved. Profits come out of Kuparuk and Prudhoe Bay.
The inability to transfer credits can cause problems. He
felt that the floor should be removed and progressivity
reduced.
3:01:24 PM
Representative Gara suggested that the immediate receipt of
deductions and credits to new exploration was a positive
aspect of ACES or PPT, which is not a common feature most
places. Mr. Zager acknowledged that immediate receipt is a
favorable feature. He observed that production sharing
contracts (PSC) vary depending if it is current or existing.
Revenue is generally divided into cost or profit oil. Mr.
Hanley added that Alaska's winter drilling season is an
additional challenge. The exploration program ties money up
longer and the remedy would provide a slight benefit and
help offset the challenges of doing business in Alaska.
RECESSED: 3:05:09 PM
RECONVENED: 3:13:37 PM
RICH RUGGIERO, CONSULTANT, GAFFNEY, CLINE AND ASSOCIATES
INC., reviewed the modeling they provided. He explained that
modifiers do not change history, except on capital expenses.
All the money spent on the drilling program through 2006
demonstrates that extra oil and sales result in a 156
percent rate of return on investment. The control page shows
fixed prices. Field revenue is shown in line 16. The price
of oil only affects the future. Oil companies have
acknowledged that the model is an accurate reflection of
their infill drilling program. The model pertains to the
infill portion of the North Slope. ConocoPhillips and BP
testified that infill drilling represents 30 percent of the
oil or the business that is possible on the North Slope.
Mr. Ruggiero agreed that 300 percent is the actual capital
expenditures (CAPEX) since BP testified that they spent an
additional two dollars on injections and facilities for
every dollar spent producing a well. He maintained that
there would be a 22 percent return if all the oil is shut
off at the end of 2006. There would be a 55 percent return
for oil in the $40 range going forward. All the multipliers
aside from the CAPEX only impact the future from 2007. Any
result from putting in zero is the money the oil company has
already made from infill drilling.
3:19:08 PM
Co-Chair Chenault clarified that CAPEX is on a five year
investment. Each year is an investment. He questioned why
companies are not investing in Alaska if the rate of return
is 53 to 55 percent. He concluded that it must more
profitable to invest elsewhere. He wondered what he was
missing. Mr. Ruggiero suggested that it is a reflection of
prospectivity. There are significant logistical issues to
operations in Alaska. People are the scarcest resource.
Opportunities must be significantly better to warrant the
movement of people.
3:23:26 PM
Mr. Ruggiero observed that the model would vary base rate
and a single progressivity factor, and stated that they
would attempt to allow for multiple progressivity factors.
DUDLEY PLATT, PETROLEUM ENGINEER, DEPARTMENT OF REVENUE
(DOR), claimed that the Alaska fields are healthy with a
reduction over the next eight years of 67,000 barrels per
day, including both state and federal oil. Filtering out the
federal oil, the state reduction is 39,000 barrels per day
for the next five years, when payback begins.
Mr. Platt constantly evaluates the producing characteristics
of the fields. The state of the fields is healthy; Prudhoe
Bay and Kuparuk are capable of producing. He verifies the
timing of new development projects, such as Oooguruk and
heavy oil. Adjustments result in a slight delay of six
months to a year, which is normal in new projects. The pace
of heavy oil development was slowed to reflect challenges
and commercial issues. The largest change falls into these
components. A larger expectation was included for downtime
attributed to both planned and unplanned events. Additional
downtime was been added for the impact of infrastructure
renewal. He concluded that there will be significant changes
in the five to eight year time frame.
3:27:21 PM
Co-Chair Meyer observed that the true challenge is the
decline of production, which has been masked by high oil
prices. He asked if raising taxes on the oil industry would
solve the problem of declining production. Mr. Platt was
unable to respond. In response to a question by
Representative Kelly, he said 25,000 to 30,000 barrels per
day is related to the two biggest factors of decline.
3:29:22 PM
Representative Gara asked for an estimate of daily
production for the next two years. Mr. Platt estimated FY
2008 production at 732,000 barrels per day, barring
unanticipated additional downtime and depending on winter
conditions. He did not know the estimate for the following
year.
3:29:57 PM
Co-Chair Chenault noted that it was not the intent of the
Resource Committee to delete the 25 percent cap from
progressivity.
BARRY PULLIAM, SENIOR ECONOMIST, ECON ONE RESEARCH,
CONTRACTOR, LEGISLATIVE BUDGET AND AUDIT COMMITTEE,
explained that he would detail the effects of different
components of the legislation working through the House,
using PowerPoint presentation "Estimating Financial Impacts
of Various Approaches to Current (PPT) Provisions," (Copy on
File). He reviewed the chart on Slide 2 depicting the base
tax rate change in different versions of the legislation
from 2008 to 2014, including HB 2001, the House Oil and Gas
(HO&G) version, and the House Resources (HRES) version. He
observed that the column of numbers beneath HB 2001 shows
the annual average difference attributable to moving from
the 22.5 percent rate in the current PPT to the 25 percent
in HB 2001. The next column, HB 2001 (O&G), did not change
the base rate from 22.5 percent, making those figures zero.
The HRES version was changed to 25 percent, so those numbers
match the HB 2001 column. He noted that the volumes included
come from the state estimates and will change.
3:34:02 PM
Mr. Pulliam spoke to the impact of the progressivity in the
various versions of HB 2001 (Slide 3). The Governor's
version starts at $30 dollar net and has a flatter (0.2
percent) slope. More money would be raised at the lower
price levels because the slope is smaller than the current
PPT; the progressive portion does not bring in as much as
the current PPT does, translating to positive numbers at the
$60 and $80 dollar per barrel level and negative numbers at
the $100 and $120 dollar level. The HO&G version has a
steeper slope that is tied to the gross, resulting in
greater revenue generated on the progressive piece. In the
HRES version (without a cap), progressivity is triggered at
different stages ($30, $40, $50, and $60 net) at different
factors (0.2 - 0.5 percent) applied to the gross. The HRES
version is the most progressive, even with the cap.
Representative Kelly asked if the cap would affect only the
bottom line. Mr. Pulliam thought it might affect the $100
level as well.
3:37:08 PM
Mr. Pulliam spoke to the TAPS tariff (Slide 4), which
applies in the HRES version. The current PPT and HO&G
versions have the tariff deducted based on whatever is filed
and approved by FERC. The HRES version also contains a
provision that allows the state to determine the just and
reasonable rate of the TAPS tariff based on actual costs,
regardless of the FERC outcome. If the state were to
determine the rate, and the numbers coincide with the DNR
estimate of $2.50 per barrel, there would be a reduction of
several dollars relative to what is currently on file with
FERC. These filings have been challenged by producers and
the state; the result of the regulatory FERC process could
be tariffs in line with intrastate tariffs. If the tariffs
remain as filed, the average tariff over the period through
2014 would be 90 cents per barrel lower than the current
projects over a number of years. That would generate around
$53 million dollars a year; most of the difference would be
in the next couple of years.
Representative Kelly wondered if only producers or TAPS
owners that would be affected, excepting Anadarko, who has
no pipe. Mr. Pulliam affirmed that would be true if they
actually ship and pay the higher rates.
Representative Gara thought the change may be worth $100
million a year. Mr. Pulliam did not think that the change
would rise to that level, but noted there could be greater
value in the next couple of years. The tariffs currently on
file are $5 per barrel. If FERC follows through with staff
recommendations, those tariffs would fall $2-3 per barrel
and generate, in the near term, around the $100/year. The
settlement is about to expire; the assumption is that rates
will fall with the expiration. He observed that $53 million
reflects an average.
3:41:54 PM
Mr. Pulliam spoke to how the different versions of the bill
approach TIE credits (Slide 5). The original HB 2001 version
does not provide for TIE credits, which would result in a
difference of $176 million per year over the 2008 to 2014
period. The credits phase out in 2013 for those that have
had production. Both the HO&G and HRES versions would limit
the TIE credits to a three-year period beginning in 2003.
This limitation would result in $47 million annual
difference relative to the current law.
3:43:15 PM
Mr. Pulliam spoke to the effective tax rate on the gross
value of the oil at different ANS price levels (Slide 6). He
compared different tax rates on gross taxable value. He
observed that PPT provides the lowest rate on average; HB
2001 raises the effective tax rate at lower prices. As a
result of lower progressivity, the difference narrows at
higher prices. The HO&G version is closer to PPT at lower
prices, but crosses over at $80 per barrel at higher
progressivity. The HRES version has the highest effective
tax rate overall because it combines a higher initial tax
rate and high progressivity. A cap of 50 percent would come
at just before $120.
3:45:22 PM
Representative Gara observed that the Governor has expressed
support for a 0.4 progressivity. Mr. Pulliam stated he would
provide information regarding the Senate JUD version of a
$30 dollar net trigger with a 0.4 progressivity.
Representative Kelly asked if the $30 net trigger with a 0.4
progressivity would be imposed on the graph and distributed
to the group. Mr. Pulliam agreed.
Representative Gara questioned if the 0.4 progressivity
proposal would start higher at the lower prices ($60 - $70
per barrel), but be lower at higher prices than the HRES
version. Mr. Pulliam observed that it would flatten out with
the cap. The HRES version would show more acceleration,
while the SJUD would be more linear in its increase if both
were capped. Representative Gara asked for clarification.
Mr. Pulliam thought the SJUD version would cross the
Governor's proposal at $55 per barrel. The HRES version
would be in the $50 to $55 per barrel range.
3:48:35 PM
Mr. Pulliam reviewed tables on Slides 6 and 7 regarding the
estimated average effective tax rate on gross taxable value,
and government share, marginal government share, and
estimated annual revenue impacts relative to current law.
He differentiated between the $80 and $100 levels; previous
charts topped out at $80 per barrel.
Mr. Pulliam highlighted that government share differs, but
relationships mirror the previous chart. Marginal government
take was introduced by DOR and represents the share of
revenues that would go to state and federal governments when
prices rise by $1 per barrel without any other changes. The
HRES version at $80 to $100 dollar per barrel results in
extremely high marginal takes. The collective take could
exceed the increase without a cap. He added that there would
be a volume adjustment of approximately 38,000 barrels per
day over the next six years, which would impact the revenue
forecast.
3:52:41 PM
Representative Hawker clarified that the same data points
were used throughout the report. Mr. Pulliam noted that
variance result from the impact of the floor.
Representative Kelly asked a question about real dollars.
Mr. Pulliam explained that the per barrel prices were in
real terms with inflation of 2.75 percent a year. Revenue
statistics are in nominal dollars.
3:55:18 PM
Representative Hawker asked if the fiscal note numbers were
consistent with DOR fiscal notes. Mr. Pulliam observed that
Econ One's analysis is within two percentage points of the
DOR's. He acknowledged that the department has more specific
information.
3:57:16 PM
Mr. Pulliam referred to a chart provided for the Senate,
which showed SJUD crossing the Governor's proposal around
the $50 to $55 per barrel range. He observed that the
highest rate tops out at 85 percent and then declines and
flattens as a result of the cap.
3:58:18 PM
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