Legislature(2007 - 2008)BUTROVICH 205
10/30/2007 09:00 AM Senate JUDICIARY
| Audio | Topic |
|---|---|
| Start | |
| SB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB2001 | TELECONFERENCED | |
SB2001-OIL & GAS TAX AMENDMENTS
9:17:36 AM
CHAIR FRENCH announced the consideration of SB 2001. Before the
committee was CSSB 2001(RES), labeled 25-GS0014\M. He said a BP
representative had testified yesterday that repealing AS
43.55.165 (c) and (d) would send a signal that the commissioner
would no longer have the discretion to allow or require the use
of billed or billable costs. He asked Mr. Bullock to discuss
joint interest billings and the repealer of two subsections in
AS 43.55.165.
9:18:33 AM
DONALD BULLOCK, Counsel, Legislative Affairs Agency, said any
time you repeal something it raises the question of what it
means. In isolation, if you repeal it, then there would be the
implication that you can't look at that any more. However, you
can't look at the repealed subsections of AS 43.55.165 (c) and
(d) in isolation; they're part of a larger bill. Included in
this larger bill is the amendment to AS 43.55.165(a), which is
in Section 19 of CSSB 2001(RES) and in Section 56 of the
governors bill (SB 2001).
MR. BULLOCK said his reading of AS 43.55.165(a) gives the
department the discretion to determine whether costs are
allowable under the standards that are presented there (page 16,
line 2, of CSSB 2001(RES)). Costs must be incurred upstream of
the point of production for oil and gas; the costs must be
ordinary and necessary costs of exploring, developing, and
producing; and the exploring costs must be direct costs. This
language doesn't preclude the department from looking at those
costs. Perhaps the repeal puts less emphasis on the use of those
costs, "but the department's given the discretion in the
amendment to .165(a) to put whatever is out there -- to see if
the costs meet the criteria that are established in .165(a)."
9:20:23 AM
CHAIR FRENCH said that the PPT was enacted just one year ago and
in it the commissioner was granted authority to look at those
costs in the two subsections that are now being repealed. It
isn't as if the PPT has 20 years of fights in court about what
costs are allowed and what aren't. So repealing it wouldn't be
undoing a long standing practice.
MR. BULLOCK agreed and said he didn't believe an audit of the
returns that were filed on April 1 had been completed. Under
current law, the department has three years to complete that
audit. The legislature can put on the record the interpretation
that the department can continue to consider these things in
determining the ordinary and necessary costs. Alternatively, a
clearer message in .165(a) could say that the information the
department may look at may include the type of things that were
in (c) and (d), but he didn't think that was necessary.
9:22:32 AM
SENATOR THERRIAULT asked if putting something in statute would
be harmful.
MR. BULLOCK replied that putting it in statute would create a
lot of appeals. If it says "may consider" the department would
be challenged to say why it didn't consider it or give it more
weight. To give the department the broadest discretion to use
whatever information it feels is relevant to support its
assessment, it is best to leave it as the legislative record.
9:23:56 AM
JONATHAN IVERSEN, Director, Tax Division, Department of Revenue
(DOR) agreed with Mr. Bullock. He said the department still has
authority under its general powers to require any information it
needs in order to reach a calculation of the tax. However, he
pointed out that the reporting requirements in section 16(f)(5)
of the CS expressly reference joint interest billings. So, the
department can look at those.
In regard to the repealer, AS 43.55.165(c) and (d), he pointed
out that the department has several concerns. One is from Gary
Rogers, supervisor, of the Oil and Gas Revenue Audit Section, on
an administrative standpoint that starts with .165(c) posing the
question of whether the taxpayer has substantial consistency
between the joint interest billings and the standards that are
set forth in the statute and the department's regulations. If
the department makes a finding referring to costs that are
billable as lease expenditures under the joint operating
agreement, AS 43.55.165(d) takes that a step further by also
posing the question to the department of whether there is
substantial incentive and ability to effectively audit by the
other working interest owners. This poses an administrative
problem because the audit is looking in the past to determine
whether there has been substantial consistency and the incentive
and ability to audit to determine the future. Also, these
agreements are moving targets. The accounting procedures in
these joint interest agreements are not set in stone. The
department would essentially be auditing the agreement and then
auditing the joint interest audit. This creates a multi-track
administrative problem.
9:28:19 AM
SENATOR WIELECHOWSKI joined the hearing.
9:28:50 AM
GARY A. ROGERS, CPA, Supervisor, Production Tax Audit Group,
Department of Revenue, added that in writing regulations to
implement 165(c) and (d), he is being asked to write regulations
that make subjective judgments about whether or not Alaska has
industry standards. He hired consultants who came up with a
variety of agreements on what "substantially consistent" means,
and he decided that rather than create administrative fights in
the future, he wanted to publish the department's own standard
of what lease expenditures are. He said that (d) also asks the
auditors or the regulation drafters to make the subjective
judgment of what is effective auditing if the joint interest
parties are auditing each other. "How do we define effective?
How do we know that what was effective in the past has continued
in the future?" His division is put in the position of auditing
their auditors rather than the tax returns.
CHAIR FRENCH noted that Senators Stevens and Thomas had joined
the meeting a while ago.
SENATOR HUGGINS asked if current language allows, but doesn't
require, the flexibility to look at the joint interest billings.
MR. ROGERS replied that is correct. Any auditor, whether state,
federal or independent, auditing oil and gas lease expenditures
that are subject to unit operating agreements would look at the
joint interest billings and unit agreements.
MR. IVERSEN noted the policy concern of these provisions. His
staff are put in a tenuous position because they haven't done
any activity under this section. The concern is shifting the
determination of what costs are allowable to the taxpayer. The
department would be moving from its normal "trust-but-verify
perspective" to a scenario of the taxpayers saying "trust us,
but let us verify it ourselves," and particularly in .165(d).
He said these sections also reference the final resolutions of
these claims that are contested between the parties to the unit
operating and joint interest agreements, and they won't
necessarily be aligned with the state's interest. Another
concern, he said, is a potential gap between statutory standards
and whatever "substantial compliance" means. Because of this
gap, there can be another gap as to how this provision is
administered between taxpayers, because one can't be treated
differently than another.
9:33:27 AM
MR. IVERSEN said ultimately this concept sets another layer of
ambiguity and shifts responsibility to where it shouldn't be. He
stated that the responsibility should lie with the department
and that the additional language should give him the affirmative
responsibility to set forth in regulations what allowable costs
are.
CHAIR FRENCH said it occurs to him that since there is no body
of law and precedent with respect to what his practices are
going to be, that at this stage of the game, to repeal these two
permissive practices doesn't take away his authority to use them
if he decides to. But it doesn't bind him to use them either.
SENATOR THERRIAULT asked if that is how the CS is written.
MR. BULLOCK replied yes.
9:34:44 AM
CHAIR FRENCH turned to the issue of corrosion starting at
section 21, AS 43.55.165(e) on page 19.
MR. IVERSEN said this provision intends to hit the same policy
objectives expressed in SB 80 but with a different take. It has
a different trigger point and takes the auditor away from making
a determination of improper maintenance or negligence, which
really isn't their purview. Those are legal or engineering
issues. The provision refers to unscheduled interruptions or
reductions in production or spills/releases of a hazardous
substance. The costs incurred for repair or replacement or
deferred maintenance of facilities, equipment, and structures
(with a carve-out for wells) would be excluded from lease
expenditures, which means they would be excluded from both the
deductions credits. The reason for the well carve-out is because
there is a greater degree of geologic uncertainty associated
with wells. The end of the section inserts a quasi force majeure
provision that is the same as language in CERCLA (Comprehensive
Environmental Response, Compensation and Liability Act of 1980)
- that basically excludes liability for the repair or
replacement if it was necessary due to an act of war, an
unanticipated grave natural disaster, or some other sort of
inevitable phenomenon - as long as the effects of that could
not have been reasonably prevented or was not from intentional
or negligent acts of a third party - as long as the operator
acted with due care.
9:38:45 AM
MR. IVERSEN said that (a), (b) and (c) of this section delineate
what costs include and the meaning of hazardous substance (oil
is included). Replacement includes renovation and improvement.
He said Pat Martindale from Martindale Consulting helped draft
this provision.
9:40:43 AM
CHAIR FRENCH asked him about the corrosion provision in SB 2001.
PAT MARTINDALE, Martindale Consultants, Oklahoma City, OK,
testifying via teleconference, gave his background in oil and
gas auditing.
CHAIR FRENCH asked if he has had experience working with these
types of provisions that try to exclude the deduction of costs
that are due to unscheduled interruptions or reductions in rates
of production due to problems with improper maintenance.
MR. MARTINDALE replied that his experience is working with
industry in writing language to identify [indecipherable] …
productions cost statutes in the mid 1990s.
CHAIR FRENCH asked him to walk through a couple of scenarios
this provision would apply to.
9:45:36 AM
MR. MARTINDALE described a circumstance where an oil company had
to repair or replace its infrastructure where preventative
maintenance might have kept it from happening.
9:47:16 AM
MR. IVERSEN clarified that Mr. Martindale was involved with this
statute as an advisor; he didn't draft the provision itself. He
asked Mr. Martindale, because he is a contract auditor, how this
would be audited.
MR. MARTINDALE explained that most companies would capture costs
(repair and replacement) with work order project numbers. The
current PPT audits would target each of the projects and
determine whether costs apply appropriately for either operating
or capital expenditures. The project would have to be described
and reviewed with documentation. Having this provision might
cause a taxpayer to be reluctant to describe a project, so some
work would be required to look at the underlying vouchers and
other documents to see if the project is legitimate.
9:51:41 AM
CHAIR FRENCH thanked Mr. Martindale and went on to the issue of
gas turbine maintenance. The turbines are frequently taken down
for maintenance, and such a problem would be difficult to pick
up on. He asked how narrow an application the language is for
specific pieces of equipment, like the turbines.
9:52:56 AM
MR. IVERSEN responded that part of this question goes to the
underlying policy of scheduled proactive maintenance that is
linked to a scheduled shutdown. If a turbine is replaced on a
regularly scheduled basis, this provision wouldn't pick up on
that - "it wouldn't even be on the radar screen." It would
exclude the cost of repairing or replacing turbines from an
unscheduled shutdown that is attributable to a turbine that just
blows out. This is a brighter line and broader than in SB 80 in
terms of the potential number of events, but it gets the state
out of a deeper hole in the sense of actually making the
determinations and the fights that are going to ensue regarding
what is or isn't negligent.
CHAIR FRENCH asked how the public would be able to tell if such
costs have been deducted.
MR. IVERSEN directed the committee to the monthly reporting
requirements in Section 16 of the CS. Section (f)(3) requires
reporting of any unscheduled interruption or reduction in the
rate of oil or gas production. That would be the first tip off.
A dip in production would also be apparent to him in looking at
regular production reports. That would be questioned on an audit
and depending on the response it might be looked into deeper.
9:55:49 AM
MR. ROGERS concurred with Mr. Martindale who said that a company
is normally going to establish some sort of cost center, project
number, AFE, or work order number to track costs related to some
sort of incident or unscheduled breakdown, and the auditors
would look at the backup documents for those.
CHAIR FRENCH pointed out that those work orders wouldn't come
with flags on them.
MR. ROGERS said experienced auditors know what to look for.
9:57:25 AM
SENATOR WIELECHOWSKI said the thing that offends most Alaskans
about the North Slope situation is that companies have acted
negligently and are able to deduct those costs. This is very
different than SB 80.
MR. IVERSEN replied this is actually more of a strict liability
type of statute and, in his mind, it is broader.
SENATOR WIELECHOWSKI said the difference is if a company on the
North Slope has been negligent for years and then schedules a
shut down to fix that negligence, it can deduct those costs and
essentially the people of Alaska end up paying for the repairs.
MR. IVERSEN replied if it's part of their scheduled regime, then
that is correct. Last year the incident was triggered by a leak
and wasn't part of a scheduled maintenance program. At some
point the state will have to draw the line as to what is not
related to an incident.
CHAIR FRENCH said he didn't know if a body of historical records
existed that would allow the department to challenge whether a
piece of maintenance has been scheduled or unscheduled.
MR. IVERSEN answered that the trigger would be the shut down
with a dip in the production report.
10:01:36 AM
CHAIR FRENCH used the recent BP spill as an example and asked
about spotting a leak and calling for a "scheduled" shut down.
MR. IVERSEN replied that the department needs to keep the
legislative intent in mind in writing the regulation for
scheduled maintenance. The scheduling has to be reasonable.
10:03:14 AM
SENATOR HUGGINS posed a scenario of installing a valve that
fails the following day that causes an interruption and asked if
that would qualify.
MR. IVERSEN replied yes, but he said he was trying to reduce
ambiguity and get out of those gray areas.
CHAIR FRENCH wondered how removing "unscheduled" would put
parameters on the meaning of what scheduled means.
MR. IVERSEN replied that the issue with scheduling versus
unscheduling goes to the underlying policy of setting some sort
of standard for pro-active maintenance to keep production going.
10:06:13 AM
SENATOR THERRIAULT said that taking a turbine down for scheduled
maintenance would cause an interruption so he didn't think that
word could be deleted.
CHAIR FRENCH agreed.
SENATOR THERRIAULT asked what "irresistible" is in the force
majeure definition of exceptional, inevitable, and irresistible
character.
MR. IVERSEN replied that those terms are almost redundant and it
means something that reasonably could not have been prevented -
such as an earthquake.
CHAIR FRENCH said he thought some eager lawyer had just started
adding adjectives in there. On natural disasters, though,
clearly a pipeline or a facility ought to be able to withstand a
tremor, and he asked where one would draw the line between a
tremor and an earthquake.
MR. IVERSEN said that gets to the secondary area, which becomes
an evidentiary matter. He didn't know enough about earthquakes
to draw a line at the point where a tremor would inevitably rip
apart any pipeline no matter how well constructed. This language
triggers times when the event is unforeseen.
10:09:34 AM
CHAIR FRENCH said it's his intention that the facilities should
be built to withstand the terrible weather on the North Slope,
like 70 mph winds and ice storms.
MR. IVERSEN agreed.
SENATOR THERRIAULT asked what "in privity of contract with" on
lines 29-30 means.
MR. IVERSEN said it means an oilfield contractor, for example.
SENATOR THERRIAULT said last year in the Special Committee on
Natural Gas that he offered Amendment 9 and part of the
discussion on it was not only about the capital costs, but what
happens to operating costs in a shut down. At the time it was
estimated that 375,000 barrels/day of production would be lost.
If there is a shutdown in Prudhoe Bay and half the production
goes away, the fixed costs of $1 million/day don't go away. Part
of it gets attached to every barrel that gets produced. Those
may double on the remaining production. He asked if disallowing
those costs was discussed. His amendment suggested that there
should be a way of disallowing them - maybe through regulations.
10:13:19 AM
MR. IVERSEN said the express topic of cost-per-barrel of capital
expenses wasn't discussed.
SENATOR THERRIAULT said they wouldn't be capital costs.
MR. IVERSON said this provision would exclude both capital and
operating expenses. So he thought perhaps additional language
was needed. He said this language is fairly broad in that the
costs are going to be those that are "in response to or
otherwise associated with."
SENATOR THERRIAULT said his interpretation is that this language
does not address those fixed costs.
MR. IVERSEN said the legislature might want to clarify that.
10:15:30 AM
CHAIR FRENCH asked how this proposal treats well costs.
MR. IVERSEN explained that the carve-out for a well is that it
would be the costs incurred for repair, replacement or deferred
maintenance of the facility or pipeline structure other than a
well. It is still allowing the costs that would be associated
with wells, recognizing the uncertainty in drilling.
MR. ROGERS said he would echo that comment. Lots of things that
can't be anticipated can go wrong "down-hole" in a well that you
really can't control or observe as with above surface equipment.
10:16:56 AM
CHAIR FRENCH noted that AS 43.55.165(e) has a general
prohibition that lease expenditures do not include "costs
arising from fraud, willful misconduct, gross negligence,
violation of the law, failure to comply with an obligation or a
lease permit or license." If drilling operations get too far
outside the bounds of normal behavior, there is a cutoff point,
but in general well-drilling costs can be deducted whether
something goes wrong on the rig floor or down-hole that causes a
problem in "the normal course of drilling operations."
MR. IVERSEN responded that is correct to the extent other
exclusion provisions would affect wells and the normal course of
business stuff isn't going to be picked up here.
10:18:18 AM
CHAIR FRENCH said that administration could offer a rebuttal.
The committee took an at-ease from 10:18:35 AM to 10:39:14 AM.
CHAIR FRENCH said the committee will hear from the industry.
10:39:37 AM
MARILYN CROCKETT, Executive Director, Alaska Oil and Gas
Association (AOGA) introduced Mr. Williams who would present
AOGA's testimony.
TOM WILLIAMS, Chair, AOGA Tax Committee, said the comments he
made yesterday about the repeal of Section AS 43.55.165(c) and
(d) were made for AOGA and not as a BP representative.
10:40:48 AM
He read the following testimony pertaining to corrosion:
The administration's proposed paragraph (19) to be
added to AS 43.55.165(e) would, unless a situation is
caused by a "super" force majeure, disallow any cost
incurred for the repair, replacement or deferred
maintenance undertaken in response to failure, problem
or event the results in an unscheduled interruption of
or reduction in the oil or gas production or is
undertaken in response to or is otherwise associated
with an unpermiteed release of hazardous substance of
gas. Not only is the language of this proposed
revision ambitious and likely to lead to additional
audit exceptions and disputes, the entire provision is
unnecessary.
The proposed provision states that otherwise ordinary
and necessary, and thus deductible, costs would be
disallowed if the Department of Revenue determines
such costs were in response to a 'failure, problem or
event' that results in an unscheduled interruption or
reduction in production. What constitutes a 'failure,
problem or event' and under what standards would any
of those be determined? Cost associated with any
temporary, unforeseen shutdown or minor interruptions,
regardless how minor, could now be disallowed by an
auditor even when such an event arises despite
otherwise prudent and necessary business operations.
Yet the issue of determining what portion of any
maintenance costs should be disallowed, if related to
improper maintenance or production interruption, was
thoroughly debated when the legislature was
considering the PPT and again in recent legislative
sessions. Each time amendments such as the one the
administration is now advocating failed because the
difficulties with such subjective standards were
immediately apparent. The state turned to Dr. Pedro
van Meurs, an international gas consultant retained by
the state, who recommended a flat 30 cent/barrel
exclusion from what would otherwise be a producer's
capital portion of its lease expenditures. As Dr. van
Muers explained:
It should be noted that in most oil and gas
fields, assets will have to be replaced
after the technical life of such assets has
expired. Therefore, such replacements are
reasonable lease expenditures and required
to protect the health and safety of the
workers and to protect then environment. The
US $0.30 per BTU equivalent barrel is based
on reasonable capital maintenance costs of
fields for which I have (confidential)
information.
Dr. van Meurs further testified that:
Maintenance is a reasonable deduction for
PPT; but it is sometimes hard to decide
which expenditures fall into that
classification. The simplest solution is to
take some base expenditure that really will
be replacement and over the next 20 - 30
disallow a modest floor of the capital
expenditures.
MR. WILLIAMS said if you assume that production is 250 million
barrels/year, which is a little less than 700,000 barrels/day,
the 30 cents exclusion comes to $75 million (capital
expenditures that collectively the industry would incur on the
Slope) that will be disallowed from either being deducted or
giving rise to credits. He continued:
At a 25 percent tax rate, that disallowance is $75
million and equates to $18.75 million. The 20 percent
credit on that $75 million equates to another $15
million. That's over $33 million a year of tax
reduction that occurs because of the 30 cents
disallowance. Thirty cents doesn't sound like much,
but $33 million a year is quite a lot. That's the
point. We believe that over time that's, as Dr. van
Meurs believed, that that's going to more than be
adequate for the situations you will be concerned
about.
So, Dr. van Meurs' recommendation was adopted and
became section 43.55.165(e)(18) of the PPT. The flat
30 cents per barrel exclusion sets a floor for
maintenance costs and avoids the problems of case by
case decisions as to whether maintenance (repair or
replacement) is required because equipment or
facilities have been improperly maintained or result
in an unscheduled interruption. To adopt the
administration's proposed amendment while leaving the
flat 30 cents per barrel exclusion in the law would
result in a double disallowance of the same costs. The
flat 30 cents exclusion also avoids all questions and
disputes about which categories of costs were incurred
due to a triggering event and are nondeductible as a
result - and also disputes about how much was incurred
in each cost category.
Finally the 30 cents per barrel exclusion applies
every year, whether there is a triggering event or
not. Over time the 30 cents figure may well prove to
be a reasonably accurate approximation of the average
amount of costs that would be disallowed by auditing
and verifying exactly which cost categories are
disallowed under the proposal and how much costs is in
each such category. A flat rate disallowance greatly
furthers the goals of clarity, certainty and
efficiency in tax administration, enforcement and
compliance. Paragraph (19) in contrast would undercut
each one.
10:46:32 AM
SENATOR WIELECHOWSKI asked what it cost BP to repair the
corrosion on the North Slope.
MS. CROCKETT cautioned the committee that Mr. Williams was here
on AOGA's behalf, not on BP's. So, it's not appropriate for him
to answer questions relating to his company's activities.
SENATOR WIELECHOWSKI said they were trying to figure out if this
is a reasonable amount.
10:47:37 AM
MR. WILLIAMS responded that AOGA doesn't have information about
what oil transit line costs are for Prudhoe Bay. He said the
committee could get an estimate by remembering how many
instances of the type they are concerned with and they already
know that disallowed costs amounted to $33 million/year. He said
AOGA doesn't have the information to answer the question.
CHAIR FRENCH said they would not go forward without the answer
to the question, because it is relevant to know if the 30 cents
really captures extraordinary events that will take place with
respect to production. Those are the things that subsection 19
is trying to address and he said, "Frankly the oil spill on the
North Slope a year ago was one of them."
10:50:25 AM
MR. WILLIAMS recalled that Mr. Suttle's letter mentioned that BP
had a $13 million tax effect. Here they're looking at a 30 cent
exclusion that totals a third of a billion over a 10-year
period. He suggested that they get someone else to speak for BP.
CHAIR FRENCH said it's important to take into account the
unavoidable event that is driving this provision.
10:52:51 AM
SENATOR THERRIAULT asked if Mr. Suttle's number was an estimate
of the tax consequences at that time or the ultimate tax
consequence.
MR. WILLIAMS said that it talked about the effects during 2006.
CHAIR FRENCH asked if he had to choose between the language in
SB 80 and in SB 2001, which he would choose.
10:54:08 AM
MS. CROCKETT replied that AOGA's belief is the 30 cents per
barrel provides the protection they are looking for and the
language in both bills is not necessary.
MR. WILLIAMS said he would have to ask the tax committee what
its preference was.
SENATOR THERRIAULT remarked that all members would have to agree
because AOGA is a consensus organization.
10:55:26 AM
MR. IVERSEN agreed that this adds another item to their audit
and that acts of negligence are included in this sort of strict
liability provision. He pointed out that there is some dispute
regarding what this 30 cent provision covers. Senator Wagoner
said it was originally intended to bring the tax closer to a
gross system and statements have been made that it's supposed to
cover regular maintenance.
CHAIR FRENCH asked his view of the 30 cents.
MR. IVERSEN replied that it seems the discussions originally
began with Senator Wagoner asking Dr. van Meurs about bringing
the system closer to a gross and hitting costs that would be
regular maintenance. This would be picking up a different sort
of item than what either SB 80 or HB 2001 is addressing.
He discussed the 30-cent per barrel exclusion. It is a per
barrel amount; it isn't an exclusion that's going towards
negligence or unscheduled interruptions. As production declines,
the 30-cent amount the state gets declines. The real tension is
if it's declining because of poor maintenance practices, the
state actually gets more money taken away because it's based on
a per barrel amount. The way the calculation actually works is
counter to the concept of covering these items.
MR. IVERSEN also pointed out that the 30-cent exclusion applies
to everyone regardless of their behavior. And it's based on
their production; it's not going toward negligence; it's not
going toward improper maintenance; it's not going towards
unscheduled shut downs in production. "It's a blanket that hits
everyone in the entire state."
CHAIR FRENCH said it's almost a gross tax floor.
10:59:43 AM
MR. IVERSEN agreed. With that in mind, the 30-cent provision
compared to SB 80 or HB 2001 is not a double disallowance
because they are hitting different things. The 30-cent provision
does not further the policy of promoting planned maintenance and
planned shutdowns. Costs associated with deferred maintenance
will rise in the future. Under the current regime it's $150
million, but if they want to stick with the exclusion (from
capital costs), it could be increased to include operation
expenditures as well or maybe a more realistic assessment of
what costs are - and put that 30 cents up to 50 cents. He
clarified that BP is just one of several working owners in that
unit, and its reported $13 million tax effect is just a fraction
of the effect on the state.
11:04:11 AM
SENATOR WIELECHOWSKI asked if the state knows the cost of the
corrosion repairs.
MR. ROGERS replied it does not.
SENATOR WIELECHOWSKI asked if he has authority to get that
information.
MR. IVERSEN replied if the department has a provision that makes
that a tax effect by statute, he could, at audit. Otherwise he
can't. Without language from SB 80 or SB 2001, the state is on
thin ground.
SENATOR WIELECHOWSKI asked what the loss to the state was from
the other groups.
MR. ROGERS answered that he could look up the working interest
owners' shares in the unit operating agreements, and he recalled
that BP owns about 26 percent of Prudhoe Bay.
SENATOR WIELECHOWSKI asked if the state lost about $50 million.
MR. IVERSEN replied yes - for one year. The expenses are
supposed to span the course of two years. So those repairs would
amount to about a $130 - $150 million tax impact to the state.
SENATOR WIELECHOWSKI asked if those costs would be covered if
the governor's section on this issue was passed.
MR. IVERSEN replied:
To the extent that any of those costs are associated
with a spill...or an unscheduled interruption in
production and there were those as well, then those
would be excluded. At some point we will have to draw
a line as to both in time and scheduling as to how far
that goes....
SENATOR WIELECHOWSKI asked if the state would be able to capture
more of the $150 million loss if SB 80, which includes a
negligence standard, were to be passed.
MR. IVERSEN replied: "Since there has been a plea of criminal
negligence, if there is a negligence standard that we're looking
at, then I would have to look at the actual plea agreement to
determine exactly what that covers." One of the things he
wrestled with is that gross negligence is currently excluded
under statute. But the challenge with a negligence decision, he
said, is if BP decides to replace the entire pipeline, deciding
what percentage of that replacement would have been done anyway
and what percentage is actually attributable to negligence. He
opined that the language in Version M is tighter in terms of
precluding an argument.
SENATOR WIELECHOWSKI said the administration supported SB 80
last year.
11:11:42 AM
CHAIR FRENCH asked Mr. Iversen to bring the committee something
more definitive on the tax consequences of the spill on the
North Slope: what they are under current law and what they would
be if SB 2001 passed.
MR. IVERSEN said that request brings up a couple of
complications. The first is that this is under investigation by
the Department of Law (DOL), so he can't speculate about the
actual damages. In addition, he doesn't know what the costs are;
he only has heard what they might be.
CHAIR FRENCH asked where the $250 million to $300 million number
comes from.
MR. IVERSEN said they were in articles that came out when the
incident happened.
SENATOR HUGGINS recalled that $250 million came out in Resources
along with an inflationary figure of 5 to 10 percent. He thought
BP was the source.
CHAIR FRENCH went back to AS 43.55.165(e) on page 17 of the CS
that says "costs arriving from fraud, wilful misconduct, gross
negligence, violation of the law or failure to comply with an
obligation under a lease." He said BP's guilty plea is drop-dead
proof that any costs that arose from that violation would not be
deductible. He asked if he was interpreting that too broadly.
MR. IVERSEN replied on its face that would seem to be the case,
but he anticipated an argument that criminal negligence isn't
the sort of violation of the law that they would be looking for.
CHAIR FRENCH responded that his lawyerly sense says that he
could argue that the only cost that arose from that violation
was the fine paid, not the pipeline replacement and perhaps
that's why the language is needed.
SENATOR WIELECHOWSKI pointed out that there's still 74 percent
from the other operators who didn't plead negligence.
SENATOR HUGGINS asked Mr. Iversen if this provision is tighter
than SB 80.
MR. IVERSEN replied yes.
SENATOR HUGGINS asked him what happens to the money that comes
from the 30 cents/barrel provision.
MR. IVERSEN said that provision is an express exclusion from
lease expenditures under AS 43.55.165(e). That's the same
provision that sets exclusions for things like gross negligence,
fraud, the provision the Senator French mentioned a few minutes
ago, violations of law or lease expenditures, and others. It is
30 cents/barrel of capital costs, "so you take your taxable
production … which would be rate of production less royalty
barrels, multiply that amount times 30 cents a barrel, and then
you exclude that cost from allowable lease expenditures." It
isn't money sitting in a fund.
SENATOR HUGGINS said it is not to be used for maintenance work,
and it is important to recognize it as a flat tax or revenue.
11:18:58 AM
CHAIR FRENCH said he read that BP's costs to replace 16 miles of
pipe in Prudhoe Bay have increased slightly to as much as $260
million. So they are in the ball park with respect to cost
estimates or pipeline replacement on the North Slope.
MR. IVERSEN said the state is losing the time value of money for
seven years - a substantially larger loss to the state.
The committee took an at-ease at 11:21:09 AM.
11:22:01 AM
CHAIR FRENCH said they would discuss the issue of actual versus
reasonable, costs and he asked Mr. Burnett to discuss the pool
the ACES bill envisions.
JERRY BURNETT, Director, Administrative Services, Department of
Revenue (DOR), said the original ACES proposal has a provision
for setting up a tax credit payment fund and that was taken out
in Version M. He referred to the chart of tax credit payments
under the current PPT and under ACES. He said there are three
ways to pay tax credits - one is that a producer who has a tax
liability gets a reduction in his tax bill. Another is if he has
a transferable credit (someone who does not have a tax
liability) that can be sold to the producer that reduces the
producer's tax bill. "So it comes right out of the production
tax pool before that production tax goes to the general fund."
MR. BURNETT said a refundable tax credit (whereby a company with
no tax liability to the State of Alaska under the production tax
but with earned credits under the PPT) could be paid out of the
general fund through an appropriation.
11:24:11 AM
MR. BURNETT said rather than having an appropriation to the
operating budget and then paying the refundable tax credits, the
ACES proposal (Section 45 in the original SB 2001) sets up a tax
credit fund where an appropriation is made from the production
tax prior to it going to the general fund in a percentage.
11:25:31 AM
MR. BURNETT said producer transferable tax credits are handled
exactly the same as they are under the current PPT. Refundable
tax credits are paid from a tax credit fund that is funded from
the appropriation of a percentage of production tax liability.
It requires an appropriation into the general fund from the
legislature each year, and then the payments are made out of the
tax credit fund without further appropriation. This means that
the balance in the fund can be carried forward; the earnings
from the fund stay in the fund and the fund would not be swept
into the CBR (Constitutional Budget Reserve). It's not available
for appropriation because amounts in that fund do not require
further appropriation to be spent.
CHAIR FRENCH said it seemed to be an unusual arrangement.
MR. BURNETT said it isn't a unique example and the education
fund is similar example.
SENATOR THERRIAULT directed attention to page 30.
MR. BURNETT said that was the intent of the fund. He explained
that a concern with ACES is that tax credits aren't equitable,
and using the tax credit fund ensures that the funds are there
and doesn't compete with general fund expenditures. The funding
mechanism allows the legislature to know what is going on.
11:31:44 AM
CHAIR FRENCH recognized Senate President Lyda Green.
SENATOR WIELECHOWSKI asked if he thought this section would cost
$100 million.
MR. BURNETT said it will not cost the taxpayer anything, but the
credits that are in current legislation will cost about $125
million and he already has a FY'08 authorization. This section
would put about $200 million into the fund if the appropriation
bill also has a language section conforming to it (incorporating
the money into the fund). Other provisions in ACES would likely
increase the amount of credits that needed to be paid from the
fund beyond the $125 million.
SENATOR WIELECHOWSKI asked how he negotiates the price for the
credits.
MR. BURNETT replied that when the state is paying refundable tax
credits it is a 100 percent value, but a transferable credit to
a producer is a negotiated value between the holder of the tax
credit certificate and the producer. Testimony has indicated
that to be in the 90 percent range. The department believes that
since producers get 100 percent of the value of their credits,
there is no advantage to the state to not give 100 percent of
the value of a credit to a non-producer who could transfer it to
a producer and the producer would get 100 percent.
11:34:27 AM
CHAIR FRENCH asked him how much would have to be appropriated to
the fund to get it up and running and to explain how it doesn't
get swept into the CBR.
MR. BURNETT started with Section (c), which assigns 10 percent
of the production tax revenue when the price for ANS West Coast
is above $60 into the credit fund. That fund would hold the
money; it will be invested by the treasury in short term
investments. Tax credits will be paid from the fund to the
taxpayer when the division finishes auditing a tax application.
CHAIR FRENCH asked how they arrived at the 10 percent figure.
MR. BURNETT replied that 10 percent was based on an estimate by
the department's economist based on what the likely value of tax
credits will be relative to production tax over time. This is
just for those who have no current tax liability and small
amounts of production for that year.
MR. BURNETT estimated that this year the fund paid out $125
million and left $75 million. He said next year they were hoping
for $250 million in credits because that means more investment
is being done. He said it's not expected to grow in a linear way
over time; it's expected to be lumpy. This smoothes the flow of
money out of the production tax by taking a percentage out each
year and then the fund is able to pay differing amounts each
year and the rest is carried forward. The legislature could
decide each year to stay with 10 percent or to change it
depending on how much is left in the fund.
11:38:50 AM
CHAIR FRENCH asked if this was a guideline rather than a
prescriptive value that will automatically pop up in an
appropriation bill.
MR. BURNETT replied that he expected the administration would
always put that into the appropriation bill and then the
legislature would discuss it.
SENATOR THERRIAULT said he expected the Finance Committee to
watch the balance. He also pointed out that this language gives
the department the authorization to pay for these credits only,
and it wouldn't have access to any other balance in that fund.
The legislature does, however. Everyone agreed.
SENATOR WIELECHOWSKI asked if there would be a market for these
tax credit certificates if the state declined to purchase them.
MR. BURNETT replied that the state doesn't have an option as to
whether or not to pay the different types of credits unless
there is insufficient money in the fund. Remaining amounts of
the credits that weren't purchased by the state because of
insufficient funds would be either carried forward or could be
transferred to another taxpayer who had sufficient tax
liability. There are limitations on how much one could reduce
tax liability through transferable credits, so there could be
circumstances where it could only be carried forward.
SENATOR THERRIAULT noted that the agency could ask for a general
fund appropriation the next year or ask for them in a
supplemental budget to pay credits that were turned in with
insufficient funds.
MR. BURNETT replied yes, but a long period of low oil prices
could lead to insufficient money in the fund after lots of
credits have been paid out, and the legislature might choose to
not spend the money on credits.
SENATOR THERRIAULT followed up on Senator Wielechowski's
question and said even though there is a private sector market
mechanism, payment of these credits ultimately always comes back
to the state treasury.
MR. BURNETT said yes.
SENATOR WIELECHOWSKI asked if the state pays interest to the
credit holder if it doesn't turn in its credits for a few years.
MR. BURNETT replied no; it is unlike a tax refund. Tax credits
are not ones that earn interest. They are paid when there is a
sufficient balance.
11:44:09 AM
CHAIR FRENCH asked how this would work and if the fund would
fill up during FY'08 through an appropriation.
MR. BURNETT replied that the state has outstanding credits, so
it would make sense to request a supplemental appropriation to
capitalize the fund in 2008 - especially since the revenues in
2008 should be sufficient.
CHAIR FRENCH asked if it is the administration's plan to both
capitalize the fund and spend it in the same year.
MR. BURNETT replied yes, but the fund would have ongoing
capitalization and would fluctuate from year to year.
CHAIR FRENCH said it's not a slush fund.
MR. BURNETT agreed and added that a slush fund would have no
value to the department or the administration; it's just to
cushion swings in income from year to year and to have
sufficient funds to pay the credits each year.
11:47:01 AM
CHAIR FRENCH asked how rapidly declining oil prices would affect
the fund.
MR. BURNETT replied that language in the bill requires the
department to write regulations that determine how it pays
credits in a time when there is an insufficient balance in the
fund. It could be a case where explorers are spending a great
deal of capital and so lots of money isn't going into the fund.
He said the department is thinking of pro-rating the credits
between the various tax certificate holders and allow them to
carry them forward into the next year. It could be that the
legislature will need to make a decision at some point.
CHAIR FRENCH asked by how much FY'07 estimates were off.
MR. BURNETT replied that the department asked for around $25
million in the supplemental budget and it ended up paying about
$59 million in credits. Some credits have been paid out in
FY'08, but not to the $25 million limit. He expected that most
of the credits would come after the winter season and with the
tax returns at the end of the year. Tax returns come in in April
and they have 60 days to audit the credit application.
MR. ROGERS clarified that under this proposal that is extended
to 120 days.
11:52:34 AM
CHAIR FRENCH referred to SB 80 corrosion elements inside the
bill before them [CSSB 2001(RES), version M] and noted the memo
from Mr. Bullock to Senator Wagoner, dated February 26, 2007,
relating to retroactivity. Mr. Bullock opined that it would not
violate ex post facto laws and it would be legal to look back
that far.
The committee recessed from 11:53:53 AM until 1:31:32 PM.
CHAIR FRENCH called the meeting back to order. He said that Dr.
Scott would address transportation deductions and that he had
copies of the current law for the committee members.
ANTONY SCOTT, Commercial Analyst, Division of Oil and Gas,
Department of Natural Resources (DNR), said AS 43.55.150 is
about transportation deductions which are used to determine
gross value at the point of production. He said he would review
the current law, some of its problems and some potential
remedies for determining transportation deductions for tax
purposes. He explained that gross value at the point of
production is determined by subtracting reasonable costs of
transportation from market prices. The statute says reasonable
costs are determined to be different from actual costs by
meeting three conditions.
CHAIR FRENCH asked if this calculation applies to both royalty
oil and PPT payments.
MR. SCOTT said he is only talking about PPT payments, not how
transportation tariffs are set for rate-making purposes, and he
isn't suggesting the state can do anything about what a pipeline
actually charges. He was speaking to what the legislature wants
to determine is the appropriate transportation deduction for tax
purposes. This is not about royalty deductions, which are
determined by contract, either.
MR. SCOTT said under the current PPT, reasonable costs are
deemed to be the actual costs unless three simultaneous
conditions hold. The last condition, the oil/gas transportation
method, is not reasonable in view of existing alternative
methods of transportation and will never be obtained. The only
reasonable method of transportation of gas or oil off the North
Slope, for example, is always going to be by pipeline - unless
the sea ice melts. So the third condition, which would provide
an exception to reasonable costs being actual costs, is never
going to be obtained - they will always be actual costs.
1:36:50 PM
CHAIR FRENCH asked why that matters.
MR. SCOTT replied that the first condition (which would suggest
that maybe reasonable costs shouldn't be actual costs) is when
the parties to the transportation of oil and gas are affiliated.
It's possible that the price paid doesn't indicate appropriate
costs. Affiliate language exists elsewhere for determining
appropriate lease expenditures. For instance, the production
wing of an integrated oil company will pay a rate to the
transportation subsidiary of the same integrated company. But
because it's affiliated, it may not be reasonable. He surmised
that when the statute was initially drafted, people probably
thought the DOR should be able to take a closer look. The second
condition is similar: If the contract for transportation of oil
or gas is not an arms-length transaction or is not
representative of market value of that transportation.
1:39:03 PM
CHAIR FRENCH said the first two conditions cause a person's
eyebrows to be raised that the correct rate is not being charged
and that they need to look deeper.
MR. SCOTT agreed.
SENATOR HUGGINS said he believed that an arms-length transaction
is a basic requirement for transportation for the affiliates.
MR. SCOTT responded with an example supposing that BPXA owns 100
percent the North Star field, BPTA owns the North Star oil
pipeline, and they transport 100 percent of BPXA's oil. Although
they are separate companies, they are clearly affiliates. One
could at least argue that it is not a fully arms-length
transaction - although legally they are two separate entities
and the parties nominating oil on the pipeline will be separate
people from the parties receiving those nominations. He added
that the pipeline has rules to insure that the pipeline
personnel from BPTA do not provide privileged information to the
shippers in BPXA.
SENATOR HUGGINS said he operates under the assumption that an
arms-length transaction is one of the requirements for the
transportation.
MR. SCOTT said that gets into the issue of what arms length is.
1:41:29 PM
CHAIR FRENCH doubts it's possible to have arms-length
transactions between affiliates.
SENATOR WIELECHOWSKI asked where the potential for conflict
between the state and producers is on this issue. Is there a
concern that actual costs are not what reasonable costs should
be? Is the concern that when they set their tariff they don't
get taxed on that tariff? Is there a concern from anyone's
perspective that when the tax is raised, the producers can raise
their tariff?
MR. SCOTT responded that the concern is if one affiliate is
charging a rate to another affiliate of the same company. At the
parent level, the company doesn't care about the rate, because
it is moving the money from the left hand pocket to the right.
But there is a substantial tax consequence, because the
transportation deduction is a tax deduction. If the
transportation tariff is $1 too high (above reasonable cost)
under PPT, the state receives 22.5 cents less on each barrel of
oil that is subject to tax.
1:44:34 PM
MR. SCOTT said in practice, the first two parts of AS
43.55.150(a) go to circumstances that might raise some eyebrows
about actual costs being reasonable. He advised:
It might be worth taking a second look, but right now
in the statute it's not just that you have to be an
affiliate or have an arms-length transaction, it is
also the case that reasonable costs and actual costs
cannot be different unless there is an alternative
mode of transportation - and practically speaking,
that's never the case.
MR. SCOTT said that right now this statute might remotely apply
to some circumstances in Cook Inlet, but he couldn't imagine it.
SENATOR THERRIAULT speculated that other basins where perhaps
the oil could be trucked wouldn't trigger the state to impose a
reasonable rate because one or two wouldn't be satisfied.
1:47:11 PM
MR. SCOTT said that is correct. He supposed a case where a
producer has chosen to truck the oil to market and there is more
than one trucking company, but the producer does a sweetheart
deal with one. If it is not an affiliate transaction and even
though the one would charge less, the state would be required to
pay the other rate. The state would have no recourse.
1:48:09 PM
SENATOR HUGGINS reminded them that they would have to discuss
the treatment of different geographical areas based on the
different variables of developing.
SENATOR THERRIAULT said now they are focused on the North Slope
with its developed transportation system. But the state hopes to
find resources in other areas, and the committee should make
sure this statute, which applies statewide, works statewide.
MR. SCOTT said transportation deductions on oil pipelines in the
state have historically been determined by rates that have been
sanctioned by regulatory bodies - the Regulatory Commission of
Alaska (RCA) or the Federal Energy Regulatory Commission (FERC).
Historically this has been the basis for saying that's the
transportation deduction.
1:49:35 PM
CHAIR FRENCH asked how far the transportation element is meant
to carry.
MR. SCOTT replied that transportation can begin downstream of
the point of production. Upstream of the point of production,
which is defined for tax deduction purposes in AS 43.55.920, is
not considered transportation. Downstream is considered
transportation. Moving oil on TAPS is transportation. Prudhoe
Bay has oil transit lines that are not transportation; they are
field lines that are considered to be upstream of the point of
production because the oil is not metered yet for custody
transfer. In Prudhoe Bay, transportation begins downstream of
Pump Station 1.
CHAIR FRENCH asked if that is really the inlet valve to pump 1.
MR. SCOTT replied yes - it is metered where the producer
transfers custody at a flange to TAPS. He said the Alpine unit
has a similar story in that the custody transfer happens to the
Alpine pipeline, which is owned by a separate transportation
company. At that point, transportation begins. Upstream of that
any of the flow lines within Alpine are not transportation for
tax purposes. Those are lease expenditures (for tax purposes).
"So that custody transfer meter marks the distinction between
whether you're upstream of the point of production or
downstream, and if you're downstream, it can be transportation."
1:52:36 PM
CHAIR FRENCH said this came up yesterday, and he said that
Kuparuk is more like the Alpine scenario. Prudhoe Bay has feeder
lines that go into pump 1.
MR. SCOTT agreed and said North Star is the same thing.
CHAIR FRENCH asked how far downstream transportation goes.
MR. SCOTT replied that it goes to market. He added that the
Department of Natural Resources (DNR) and Department of Revenue
(DOR), separately, have spent an enormous amount of time
figuring out the reasonable cost of transportation for tankers.
SENATOR HUGGINS asked how much maritime costs are.
1:54:08 PM
MR. SCOTT replied that those change for different companies and
he didn't want to venture a figure. There are differences
between the tanker transportation deduction for royalty and for
tax, but it's in the range of $1.50 to $2.00. DOR publishes what
the marine transport deduction is to the West Coast for income
tax purposes.
SENATOR THERRIAULT said that was discussed last year. Exxon was
the highest and the state is trying to come to an agreement with
them on what fee should be paid - as a contractual dispute.
MR. SCOTT said he would be happy to get those figures. He went
on to explain that historically the transportation deduction for
tax purposes has relied on rates that have been sanctioned by
the regulatory bodies; however, it has not resulted from a
regulatory determination. This is an important distinction. If
you have a rate which is approved by a regulatory body, in
general those agencies have a requirement to establish rates
that are just and reasonable. Historically, and it's usually the
case within the state, the producers through their affiliates
own transportation. Typically you see a very close match between
ownership percentages in the pipelines and ownership percentages
of the production which comes out of the fields.
He said because these integrated companies are paying themselves
- moving money from one pocket to the other - they would prefer
a high rate. Because the higher the rate, the lower their tax
payments will end up being and the lower the royalty payments
will be. So the only party usually complaining about
transportation deductions has been the state. A dispute will
occur and rate litigation will ensue. Without exception the
state has ultimately come up with settlement agreements for
those pipeline tariffs. The regulatory agencies have never said
that the rates produced by the settlement agreements are just
and reasonable rates. Just and reasonable is a term of art in
the regulatory arena, which means historically cost-based rates
- rates which reflect actual costs of developing and operating a
pipeline including reasonable return on capital.
1:58:59 PM
CHAIR FRENCH asked why the state has not pursued this claim to
the very end. Why has it relied on settlement agreements when it
would have gotten a better result by forcing the regulatory
agency to come to a decision on what actual costs are?
MR. SCOTT replied that TAPS is the really big deal, and when
those tariffs were being litigated from 1977 through 1985 (when
the state finally settled), there was significant uncertainty
around methodology issues for pipeline rate making. This applied
to pipelines in the Lower 48 as well. It was against that
context of regulatory uncertainty that the state made the
determination that it had no comfort in getting to a final
conclusion any time soon. Another ten years was the prediction
at the time of the settlement.
He said the determination was made that the state was better off
settling, because it might have a potential refund obligation
that was continually accruing. It measured in billions of
dollars. There are a number of reasons why it seemed reasonable
at the time for the state to settle the TAPS dispute when and
how it did.
2:01:29 PM
MR. SCOTT said his Master's thesis was on this question, and he
never opined whether it was good for the state or not. Many
people think that the state made a mistake and others think it
was the right thing to do. Having settled TAPS, he said it could
be argued that the state got used to not wanting to litigate any
more and it now has a framework for subsequent settlements and
has long-term settlement agreements. He assured them that those
settlement agreements did not say that for tax purposes the
state would use the tariff numbers that came out of those
settlement agreements. Those settlement agreements said the
following:
Here is a methodology. It'll determine a rate. So long
as the rate each year that the transportation company
files is at or below that rate, the state will not
protest the rate. That's what the agreements say. It
doesn't say we're going to use them for tax purposes
or royalty purposes or any other purpose for that
matter....
Now, on the royalty side, we have a number of royalty
settlement agreements, which make reference to various
transportation rates, but again, for tax purposes -
and so we're bound to the extent that our contracts
bind us. But for tax purposes, when coming up with
appropriate transportation deductions, you are not
similarly bound - just like you're not bound on issues
relating to corrosion.... You're the policy makers;
you get to decide what's an appropriate course of
action for deductions.
2:04:19 PM
SENATOR WIELECHOWSKI asked if the state has lost money because
of the way the rates are set.
MR. SCOTT replied that the RCA was host to intrastate rate
litigation concerning rates for 1977 through 2000 brought by
Tesoro, an instate refiner. Tesoro thought the rates were too
high. Eventually the RCA "disgorged" a 200-page decision that
found that through 1996, TAPS tariffs had collected $9.9 billion
too much from shippers. A very large percentage of that $9.9
billion was collected from Exxon Production Company to Exxon
Transportation Company, but given the state's royalty and tax
interests, the state footed roughly 25 percent of the bill - or
$2.5 billion.
SENATOR HUGGINS asked who paid the remaining $7.7 billion.
MR. SCOTT replied that the remainder of the settlement would be
mainly transfer payments from affiliates of the pipeline. In
other words BPXA paid BPTA too much. "But since they were paying
themselves, it's neither here nor there."
CHAIR FRENCH commented, "We don't care except that it reduces
our royalty and taxes."
2:07:17 PM
MR. SCOTT repeated that the vast majority of the remainder of
the $7.7 billion was paid by affiliates of the pipeline to
itself. There were some independent shippers, but very few.
CHAIR FRENCH recognized Senator Thomas and Representative Buch.
SENATOR WIELECHOWSKI asked if the state can recoup that $2
billion based on that RCA decision.
MR. SCOTT replied no.
SENATOR THERRIAULT said that four years were being disputed and
the FERC decision potentially goes back two or three years. The
potential impact to the state treasury if the RCA rate is upheld
is $800 million.
2:08:34 PM
MR. SCOTT said he would talk about tax impacts shortly. He
explained that in 2005, rate litigation at the FERC commenced
with Anadarko and Tesoro as parties. The state was also a party,
but its complaint had to do with discrimination because the
intrastate rates were so much lower than the interstate rates.
Last May, an administrative law judge for the FERC determined
that indeed the interstate rates set pursuant to the TAPS
settlement methodology with the state were much too high and
suggested that the just and reasonable rate (for transportation
on TAPS) should be about $2.00 rather than $5.00. That matter
was appealed to the FERC as a whole, but he could guarantee
that, no matter what the result, the FERC's decision will be
appealed in the D.C. Circuit Court.
SENATOR WIELECHOWSKI said losing this tax makes him angry.
MR. SCOTT said the $2.2 billion figure from the RCA's decision
is from the period of 1977 through 1996.
SENATOR WIELECHOWSKI asked if the state could do a statute of
limitations retroactively to recoup that loss.
2:10:53 PM
MR. SCOTT said he couldn't answer that.
SENATOR WIELECHOWSKI remarked that was like stealing.
SENATOR THERRIAULT reminded them that it was only in 2005 that
the state started protesting, and the opportunity to protest
previous years is lost.
MR. SCOTT said that is correct. In essentially all cases, until
recently, regulatory bodies have blessed settlement agreements
that the state has struck with industry rather than having a
fully-litigated rate case that eventually came to conclusion.
That raises some issues about whether actual costs are
reasonable, and evidence exists that they are unreasonable -
given recent regulatory determinations of actual costs.
CHAIR FRENCH recognized the presence of Senator Hoffman.
2:12:19 PM
MR. SCOTT said the first question he wanted to raise is why the
state bases its tax policy for pipeline transportation
deductions on pipeline rate litigation. For royalty, it is
pretty much stuck doing so, but for taxation, it is not. Tax for
transportation deductions is a sovereign matter. The right
answer could be zero, he remarked, and added that this is not an
unheard of measure. It's the legislature's call.
MR. SCOTT further elaborated:
On pipelines transporting federal royalty, if the
pipeline is an affiliate of the producer, MMS
(Minerals Management Service) doesn't take the tariff
rate as the basis for determining the transportation
deduction, in general. MMS is the federal equivalent
of DNR for the state. So, under their leases, MMS,
says, 'We will give you an actual and reasonable cost,
but we're not going to look to the regulatory agency
to determine actual and reasonable costs for
transportation if you don't have a properly contested
rate proceeding.' So, if this is not an arms-length
transaction, what we do is we'll say, 'Here is a
method, here's what you'll use. This is the formula,
crank it through the formula. The rate that comes out
[is] your transportation deduction.' It is not
dissimilar, frankly, from what DOR - it's actually a
little more formal. No, I shouldn't say that. It's not
dissimilar from what DOR does for marine
transportation deductions....
There are some reasons for the state to avoid relying
on the regulatory process in setting tax value. First
of all, as we've just been talking about, pipeline
litigation can drag on for a considerable period of
time and in the meantime you're accruing balances that
may show up as refunds to the state treasury and may
not, but you're creating uncertainty as to the
ultimate tax value when you rely on litigation for
determining tax value.
2:15:28 PM
CHAIR FRENCH said his sense is that the regulatory process and
the litigation that is used from that takes much longer than the
litigation process that ensues when you have a tax dispute.
MR. SCOTT said that can be the case. In a memo to DNR, Spencer
Hosie said he could resolve tax disputes in two or three years.
Mr. Scott said he hoped the first stage of the rate litigation
at the FERC will be concluded within three years, but then it
will go to the D.C. Circuit Court; more than likely a small
portion of it will be remanded back to the FERC. It is a process
that can take considerably longer than three years. He said the
original Tesoro protest with the RCA was in 1997 and that was
not concluded until 2005. That decision is still not final and
is before the Alaska Supreme Court right now.
SENATOR THERRIAULT said it took RCA five years, but it is
evaluating a methodology and doing all the work. Then the
challenge in the court system determines whether it was
reasonable and not arbitrary. So there is some deference to the
agency's expertise. One would expect the agency function to be
the longest.
MR. SCOTT agreed and said the second reason to question using
the regulatory process to set tax value is that absent arms-
length transactions with commercially sophisticated parties like
Tesoro was at the RCA or like Anadarko and Tesoro were at the
FERC. Absent that kind of a protest, it is at least questionable
whether you're going to get settlement results that are a good
match to actual costs or reasonable costs.
2:18:25 PM
MR. SCOTT gave an example. Right now the TAPS transportation
deduction is about $5.00. TAPS is one hose with separate straws
within it and each one has a different tariff and those bounce
around from year to year. The RCA determined that costs were
actually around $1.97. The FERC law judge determined they were
about $2.05. While the litigation continues, the state continues
to allow $5.00 for a transportation deduction for tax purposes.
If it is the case that TAPS deductions are $3.00 too high and
assuming production is 760,000 barrels per day and production
tax rate is 22.5 percent, it would cost the state about $160
million per year.
2:21:12 PM
MR. SCOTT said he wanted to shift focus to talk about
transportation deductions for gas pipelines. He said gas
pipelines are typically built on the basis of negotiated rates
between shippers and pipelines, and there is no scrutiny by FERC
as to whether it is a fair bargain. In the case of a major North
Slope gas pipeline, if the producers end up owning the gas
pipeline, they can negotiate with themselves. That could result
in a very high negotiated rate because they could use that rate
for determining their deduction for determining gross value at
the point of production for gas. Given the current statute, the
state wouldn't even have a regulatory forum really to go to,
practically speaking, to complain about this excessive, non-
arms-length negotiated rate. The FERC doesn't care.
So, why would the state want to set its tax policy for
transportation deductions on the basis of a non-arms-length deal
that the state can't even litigate before a regulatory body? The
state's experience with TAPS suggests that would be unwise and
there is no need to do so. He said this is an opportunity for
the state to reconsider how transportation deductions are
handled for determining gross value at the point of production.
2:23:56 PM
MR. SCOTT said the state presently must live with it because
it's never the case that there will be other reasonable modes of
transportation - so the third condition in AS 43.55.150(a) will
never be met. The DOR could follow MMS's lead and establish
regulations given a statutory change to determine appropriate
cost deductions for non-arms-length transactions. But the state
will need to be careful to deal with the circumstance that
Anadarko faces, for example. Anadarko really does pay TAPS
tariffs; it doesn't own a part of the pipeline. A non-TAPS owner
that is not an affiliate may want to use their actual costs.
SENATOR WIELECHOWSKI asked the impact of exploration on the
North Slope when tariffs are so much higher than they should be.
MR. SCOTT said it is not helpful. There have been a number of
presentations on how the tax rate affects the break-even point.
Those movements based on tax may be well under that $3.00 swing.
It is a substantial difference.
2:26:36 PM
SENATOR WIELECHOWSKI asked if tariffs were down to $2.00 would
that encourage exploration on the North Slope.
MR. SCOTT said the short answer is no, and:
the reason is because the state cannot, through its
tax policy, determine what a pipeline actually
charges; so a third party shipper right now faces TAPS
tariffs which are arguably too high. They have to pay
that tariff if they want to get their product off the
North Slope. What you choose as an appropriate
transportation deduction for tax purposes can't
directly affect what the pipeline charges that third
party. What you can do, and what you clearly have the
power to do, is affect whether that transportation
deduction affects the state's general fund. So,
through tax policy you can't directly change the rate.
Through tax policy you can directly affect the
transportation deduction.
SENATOR WIELECHOWSKI asked if the pipeline owners have to get
FERC approval on rates or if they charge whatever they want.
MR. SCOTT replied that owners of a pipeline will have to have a
tariff on file with the FERC, for example. Absent someone
complaining about that tariff, it will be allowed to go into
effect. Protesting tariffs is an extremely lengthy and expensive
process; it's not something that a company undertakes lightly.
It would have to have enough production to be worth their while
on a cost benefit basis. When Anadarko and Tesoro decided to
challenge TAPS tariffs at the FERC, they needed approval for the
legal expenditures that were going to be entailed because they
measured in many millions of dollars. Small, new entrants will
not be inclined to do that.
2:29:17 PM
CHAIR FRENCH went back to the Anadarko case and asked why it
wouldn't deduct the actual costs, since they are not affiliated.
MR. SCOTT replied that changing "and" to "or" will get the state
most of the way, if not all of the way, to where it needs to go.
It won't capture Anadarko, but they want to make sure that when
DOR promulgated regulations (after changing "and" to "or") for
setting appropriate transportation deductions that it applies to
everyone whether they are affiliated or not. It's probably not
necessary to do it in statute.
2:31:06 PM
SENATOR THERRIAULT said the actual cost will be a legitimate
deduction for Anadarko or any other non-TAPS owner.
MR. SCOTT said that is right. TAPS is the poster child, but this
change could potentially apply to the other pipelines and it
makes a difference. One needs to look on a case-by-case basis.
It is really about transportation deduction policy.
The committee took a recess from 2:33:05 PM to 2:52:53 PM.
CHAIR FRENCH called the meeting back to order and said that they
would hear a response to the previous testimony from Mr. Scott
about actual versus reasonable costs from AOGA.
MARILYN CROCKET, AOGA, said she is not planning to respond to
the previous testimony. She has testimony on actual versus
reasonable cost and the credit buy back.
CHAIR FRENCH asked to start with the most recent topic.
2:54:07 PM
TOM WILLIAMS, Chairman, AOGA Tax Committee, said the issue of
actual versus reasonable costs is real and was faced by the DOR
when he was director of the Petroleum Revenue Division of DOR
(which is now the Tax Division) from 1975 to 1979 and also when
he was DOR commissioner from 1979 to 1982. Back then the same
issue arose in other contexts. In the context of the cost to
transport ANS crude by marine tankers from Valdez to markets on
the West Coast, Hawaii, St. Croix in the Virgin Islands and to
the U.S. East and Gulf Coasts, the respective marine
transportation costs had to be netted out or subtracted from the
market value of the ANS delivered at each outside market
destination in order to determine the corresponding netback
value of that oil at Valdez. From the Valdez netback the
pipeline transportation costs were further netted out to get the
corresponding netback in the field (which was formally called
the gross value at the point of production in production tax
statutes starting in mid-1977).
MR. WILLIAMS said, from a tax administrator's perspective, the
advantage of using reasonable costs instead of actual costs is
that you don't have to audit reasonable costs. You just find a
publication or other recognized authority that tells you what
the reasonable costs are and the current market conditions.
For international marine transportation there was actually such
a publication or authority. He said the average freight rate
assessment (AFRA) was published by the London Tanker Brokers
Panel. Those rates were helpful to DOR to find the delivered
cost to acquire comparable foreign crude at a market destination
where ANS was also going and competing against that foreign
supply, but AFRA didn't give them the reasonable cost or market
value of waterborne transportation in Jones Act ships. When he
first heard about a new U.S. AFRA in 1978 he was inclined to
consider using it to determine the reasonable costs for Jones
Act tanker transportation from Valdez to the other U.S. ports
where ANS was shipped - he was very inclined until he discovered
that the tanker fleet for ANS would dominate the rates quoted
for this U.S. AFRA. In other words, those quotes would basically
be the same information he would be getting - it would be just
another source. This illustrates one of the problems of using
reasonable rates - which is finding an authoritative source you
can trust. Often times there simply isn't one and sometimes they
go out of business or become unreliable and inaccurate. The only
other way to implement the reasonable cost approach is to audit
the cost of everyone involved.
2:58:07 PM
MR. WILLIAMS said this is the worst of all possible worlds from
a tax administrator's perspective because you have to do all the
auditing and other work in an actual cost system and once that
is done there are the further challenges of proving to everyone
that your reasonable cost figures are accurate and represent
market conditions. Given the constraints of tax confidentiality,
he asked how cost information could be used from one taxpayer to
show any other taxpayer how reasonable cost was determined. The
issue of how one taxpayer's information could be used to show
another taxpayer was solved in the statute enacted last year.
MR. WILLIAMS said reasonable cost figures will be badly out of
date given that taxpayer information from which the department's
figures are derived would have to be audited first to insure
reliability. There would be a tax that no taxpayer could comply
with correctly when due. It would require numerous filings and
refilings of amended returns by tax payers as reasonable cost
data was published or updated on the basis of new audit results,
or it would be a tax whose correct amount cannot be determined
at all until taxpayers are audited. The challenge for DOR to set
up and maintain accurate records of each taxpayer's payment,
corrections, and final cost figures would be enormous, but
relying on audits is the only way to determine the correct
amount of reasonable costs, and that would amount to taxation by
audit instead of self reporting and self assessment. It would be
difficult and inefficient to administer a tax that supposedly is
self reported and self assessed. He continued:
Rather than taking any of these unappealing
alternatives, we (DOR) opted in 1979 and 1980 to use
actual transportation costs as much as we could and
save ourselves these troubles. From a taxpayer's point
of view - and I am now putting my hat back on as chair
of the AOGA Tax Committee - the reasonable cost
approach suffers from three major problems. First,
taxpayers only know their own business and their own
actual costs. Anything different from a taxpayer's own
actual costs cannot be right in its eyes, because the
actual costs are what they are and the facts cannot be
different from what they are. It is a rare tax,
indeed, that does not look at the actual performance
or results of a taxpayer's business or business
related activities.
3:00:45 PM
And as long as the tax is taking such later items into
account, it is fundamentally unsound to ignore actual
costs or similar actual results, and to base the tax
instead on some different cost or result no matter how
reasonable this derivation may be. Second, unless
there is some reliable and authoritative source about
reasonable costs under the current conditions that is
available to taxpayers before their tax returns and
payments become due, it will be impossible for them to
compute, report, and pay the correct amount of tax on
that due date. In the case of operating and capital
costs to explore for, develop, or produce oil or gas
on the North Slope, there is no reliable authoritative
source available at all, much less one that can be
available on a timely basis. Here you can see we
misunderstood where the concerns seem to be of the
committee on this subject. We were addressing the
issue of the upstream costs in the field rather than
downstream costs of the transportation.
Third, if DOR would be determining the amount of
reasonable costs to explore for, develop, or produce
oil and gas on the North Slope on the basis of
taxpayers' verified and audited actual costs for these
activities, it would still be impossible for taxpayers
to report and pay the correct amount of tax when it
comes due. In addition, the problems of filing and
refiling amended tax returns or of having the
alternative taxation by audit will be about as
difficult and onerous for taxpayers as they would be
for tax administrators.
It is also worth remembering that to the extent the
actual lease expenditures can be based on joint
interest billings by the operator to other
participants in the operations, the total actual costs
under those billings will be the same for each
participant with the only difference being the size of
each one's share of that total. Even if DOR were not
to rely on the audits by non operating participants of
the billings to ensure that those billings are
appropriate and accurate, it would have to do only one
audit of each set of billings by the operator. This is
the same set for all the partners. And that would be,
instead then of doing completely independent audits
for each participant's actual costs. So, using actual
costs could prove to be significantly less burdensome
for DOR to administer, audit, and enforce than one
might first expect.
3:03:14 PM
SENATOR WIELECHOWSKI asked if his testimony represents a
consensus view within AOGA including Anadarko.
MR. WILLIAMS replied yes. "There was no dissent."
SENATOR THERRIAULT said Mr. Williams indicated his testimony was
not in response to the previous discussion, but rather in
response to the upstream in-field reasonable cost discussion.
MR. WILLIAMS said yes, but the anecdotal discussion about AOGA's
experience with tanker rates fits into the discussion.
CHAIR FRENCH asked if AOGA takes a position on the proposal with
respect to AS 43.55.150, to change the final "and" to an "or",
he would give him further opportunity to speak before the bill
leaves committee.
3:05:13 PM
SENATOR THERRIAULT asked if the gathering lines on the North
Slope are regulated or just negotiated.
MR. WILLIAMS replied that the pipelines in the fields, whether
they are oil transit lines or not, upstream of the custody
transfer meter are not regulated and have not been deducted in
getting to the gross value at the point of production. That
point of production is downstream.
SENATOR THERRIAULT asked if the discussion for transportation
costs for tax purposes is only for the downstream stuff.
MR. WILLIAMS said yes. The transportation costs start at the
custody transfer meter where it leaves the unit and goes into
the custody of the common carrier pipeline serving that field.
CHAIR FRENCH asked if AOGA had an opinion on a tax credit fund.
3:06:18 PM
MR. WILLIAMS replied that AOGA supports the concept of the state
buying back tax credit certificates and creating the fund to do
so. Further he said.
However, for this system to work it will be essential
that future legislatures appropriate the necessary
money into the fund each year. Otherwise the fund will
turn into an empty promise for future investors. In as
much as the topic currently under consideration
includes appropriation authority for credit buy backs,
AOGA would draw your attention to a few potential
issues relating to this portion of the topic.
First, might the automatic inclusion of earnings on
the fund as part of the fund without specific
appropriations of those earnings back into the fund
each year violate Alaska's constitutional prohibition
against dedicated revenues? If so, what might the
legal effect be of AS 43.55.028(h) stating that
'Nothing in this section creates a dedicated fund?'
With respect to that question, if I may depart from
the testimony, I think that since this fund is an
account in the general fund, this issue of dedication
might be moot - as I understand it, because it is not
an independent thing like the University of Alaska or
something like that. But if that's the case and the
earnings sort of automatically are there and there
isn't an appropriation, then could they be taken out
of the treasury without violating the clause in the
constitution requiring an appropriation to take money
out of the treasury? The fact that this statute says
that they are automatically in the fund balance might
not be self executing because it's not an
appropriation; so you would have to take care in the
future to make sure that in addition to appropriating
the new tax receipts, the percentage of the tax each
year, that you would also be appropriating the
interest. There might be an issue otherwise about the
use of that money that might not have been
appropriated and that violates Article 9, Section 13 -
or it might. I can't give you the legal opinion on
that. Our concern is that it might.
3:09:07 PM
The second question, which is now - might the anti-
lapse provisions in AS 43.55.028(f), which states that
money in the fund at the end of a fiscal year does not
lapse and remains available for expenditure in
successive fiscal years, which includes the monies
appropriated to it, does that more properly belong in
a bill making an appropriation to the fund or a bill
specifically reappropriating the money back into the
fund, rather than in this legislation establishing the
fund in the first place. If so, would AS 43.55.028(f)
violate the constitution's one-subject rule for
legislation? There it says: 'Every bill should be
confined to one subject unless it is an appropriation
bill or one codifying, revising, or rearranging
existing laws. Bills for appropriations shall be
confined to appropriations.'
Although representative of some members of the AOGA
tax committee may be attorneys, the tax committee is
not authorized nor qualified to offer you any legal
advice or opinion about what the answers to these
questions might or might not be. The most we feel we
can properly do under the circumstances is to point
out these potential issues so you can get whatever
professional legal advice you may feel is necessary or
appropriate to answer these questions and to revise,
if necessary or prudent, these provisions of the bills
accordingly. And I would add here that technically
these are not in the bill in the sense that they are
not in the committee substitute from Resources, but I
discussed them because they are on the agenda and it's
in the original bill.
As I close, Mr. Chairman, I should mention that AOGA
has prepared a white paper on aspects of tax credits
since we're on the subject sort of tax credits, under
the proposed bill that falls outside the specific
scope of the present topic. In fact, the white paper
covers the following topics: the 50 percent limitation
on credits taken the first year for capital
investments, the "TIE" credits, electric ratepayer
benefits from selling tax credits, and conditioning
exploration tax credits on new requirements to share
information. We believe the committee members might
find some or all of these points to be of interest and
with your permission I would like to have that be
submitted as part of the record.
CHAIR FRENCH responded he would be happy to take that in.
3:11:27 PM
SENATOR THERRIAULT suggested that the drafter had patterned the
language after other sub-funds of the general fund that retain
their interest and it may be worth having the legal division
look at it. He didn't think it would create a problem. If the
legislature in the future did not go through this separate fund
mechanism to repay the credits, that doesn't mean the credits
wouldn't be honored. Future legislatures could have different
ways of honoring the state's commitment.
3:12:55 PM
JERRY BURNETT, Director, Administrative Services Division,
Department of Revenue, said he agreed with Mr. Williams that the
legislature would have to appropriate the interest each year in
order for the department to be able to spend it. The dedication
of funds issue can be taken care of in the annual appropriation
bill and it would be their intent to do it that way.
CHAIR FRENCH asked about the anti-lapse provisions being in an
appropriation bill as opposed to this one.
MR. BURNETT replied that the intent of this legislation clearly
can't deal with appropriations, so he intended to put the lapse
language in the appropriation bill.
SENATOR THERRIAULT asked if their main concern is having a fund
that is not sweepable. Mr. Burnett replied yes.
CHAIR FRENCH asked Mr. Scott if he wanted to respond to some of
the comments made with on transportation costs. He replied no.
3:14:53 PM
SENATOR THERRIAULT asked for producers who are owners of the
means of transportation, if the state has to be careful in
applying a reasonable rate to all shippers because some of them
actually pay that rate.
MR. SCOTT replied that is exactly right. So for TAPS, for
example, there are a number of companies that have production on
the North Slope who ship through TAPS or sell to other parties
who ship through TAPS and don't own any interest in TAPS. For
those parties, the reasonable costs really should be their
actual costs because they really do pay it. The primary function
of the tariff for an affiliate producer is to affect their tax
and royalty distributions to the state.
CHAIR FRENCH said he wanted to hear from a producer with no
interest in TAPS before the committee takes final action on the
proposed amendments. He said they would next take up the cost of
the spill and how SB 2001 prohibits producers from deducting the
costs of unusual events from their production taxes.
3:17:16 PM
BERNARD HAJNY, Manager, Production Taxes and Royalties Alaska,
BP Exploration Alaska, testified that their Prudhoe Bay manager
testified that the cost to replace the oil transit lines is
currently in the range of $250 million to $260 million.
CHAIR FRENCH asked if those costs had been spent or will be
spent or both.
MR. HAJNY replied that some will be spent in calendar year 2007
and the remainder will be in 2008. That is the expected total.
3:19:20 PM
SENATOR WIELECHOWSKI asked if that cost was all incurred by BP
or if other parties are participating.
MR. HAJNY replied that expenditure would be borne by the
operating unit with BP as the operator.
SENATOR WIELECHOWSKI surmised the cost would be spread around.
MR. HAJNY replied yes.
SENATOR WIELECHOWSKI asked if BP intends to write off the full
amount as a deduction under the current PPT.
MR. HAJNY referred him back to Doug Suttle's letter to the
legislature on February 15, 2007 where he indicated BP intended
to deduct the cost of inspection, business resumption, and
replacement of the oil transit lines.
There being no further business to come before the committee,
the meeting was adjourned at 3:22:02 PM.
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